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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

 
FORM 10-K
 
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to            
Commission File Number 001-35410

Matador Resources Company
(Exact name of registrant as specified in its charter)

Texas27-4662601
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
5400 LBJ Freeway, Suite 150075240
Dallas, Texas
(Address of principal executive offices)(Zip Code)


(972) 371-5200
(Registrant’s telephone number, including area code)
_________________________________________________________  
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbol(s)Name of each exchange on which registered
Common Stock, par value $0.01 per shareMTDRNew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes   No  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes      No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   
Yes      No  

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $5,188,536,396.

As of February 21, 2023, there were 119,071,975 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2022 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.
Auditor Name: KPMG LLP
Auditor Location: Dallas, TX
Auditor Firm ID: 185






Table of Contents
MATADOR RESOURCES COMPANY
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2022
TABLE OF CONTENTS
 
  
 Page
PART I
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
PART II
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
PART III
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
PART IV
ITEM 15.
ITEM 16.
 






i


Table of Contents
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; the operating results of and availability of any potential distributions from our joint ventures; weather and environmental conditions; the ongoing impact of the novel coronavirus (“COVID-19”) and its variants on oil and natural gas demand, oil and natural gas prices and our business; our ability to consummate the Advance Acquisition (as defined below) in the anticipated timeframe or at all; risks related to the satisfaction or waiver of the conditions to closing the Advance Acquisition in the anticipated timeframe or at all; risks related to obtaining the requisite regulatory approvals for the Advance Acquisition; disruption from the Advance Acquisition making it more difficult to maintain business and operational relationships; significant transaction costs associated with the Advance Acquisition; the risk of litigation and/or regulatory actions related to the Advance Acquisition; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about:
our business strategy;
our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized;
our cash flows and liquidity;
the amount, timing and payment of dividends, if any;
our financial strategy, budget, projections and operating results;
the supply and demand of oil, natural gas and NGLs;
oil, natural gas and NGL prices, including our realized prices thereof;
the timing and amount of future production of oil and natural gas;
the availability of drilling and production equipment;
the availability of oil storage capacity;
the availability of oil field labor;
the amount, nature and timing of capital expenditures, including future exploration and development costs;
the availability and terms of capital;
our drilling of wells;
our ability to negotiate and consummate acquisition and divestiture opportunities;
the integration of acquisitions, including the Advance Acquisition, with our business;
government regulation and taxation of the oil and natural gas industry;
our marketing of oil and natural gas;
our exploitation projects or property acquisitions;
our ability and the ability of our midstream joint venture to construct, maintain and operate midstream pipelines and facilities, including the operation of cryogenic natural gas processing plants and the drilling of additional salt water disposal wells;
the ability of our midstream business to attract third-party volumes;
our costs of exploiting and developing our properties and conducting other operations;
general economic conditions;

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competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;
the effectiveness of our risk management and hedging activities;
our technology;
environmental liabilities;
our initiatives and efforts relating to environmental, social and governance matters;
counterparty credit risk;
geopolitical instability and developments in oil-producing and natural gas-producing countries;
the impact of COVID-19 and its variants on the oil and natural gas industry and our business;
our future operating results;
the Advance Acquisition and the anticipated timing and benefits thereof;
the impact of the Inflation Reduction Act of 2022; and
our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical.
Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.

PART I
 
Item 1. Business.
In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries and (iv) references to “Pronto” refer to Pronto Midstream, LLC, and the “Pronto Acquisition” refers to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.
General
We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million.
On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

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Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies:
focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin;
identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties;
continue to improve operational and cost efficiencies;
identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto;
maintain our financial discipline;
return capital to shareholders through our dividend policy;
pursue opportunistic acquisitions, divestitures and joint ventures; and
provide the energy that society needs and do so in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.
Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, global oil demand and oil and natural gas prices improved significantly during 2021 and 2022. These factors, along with the successful execution of our business strategies, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2022, as well as to increases in our oil and natural gas revenues and cash flows. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”). In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down borrowings, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC, our joint venture partner in San Mateo (“Five Point”). Further, we concluded several important financing transactions in 2022, including increasing the borrowing base under our Credit Agreement (as defined below) and extending the maturity of and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2022, including the addition of produced water disposal capacity and being awarded several new customer contracts. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position.
2022 Highlights
Increased Oil, Natural Gas and Oil Equivalent Production
For the year ended December 31, 2022, we achieved record oil, natural gas and average daily oil equivalent production. In 2022, we produced 21.9 million Bbl of oil, an increase of 23%, as compared to 17.8 million Bbl of oil produced in 2021. We also produced 99.3 Bcf of natural gas, an increase of 22% from 81.7 Bcf of natural gas produced in 2021. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended December 31, 2021. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2022 and 2021.
Increased Oil, Natural Gas and Oil Equivalent Reserves
At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, an increase of 10% from 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, at December 31, 2021. The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 were primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to

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December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”
At December 31, 2022, proved developed reserves included 116.0 million Bbl of oil and 632.9 Bcf of natural gas, and proved undeveloped reserves included 80.3 million Bbl of oil and 329.7 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022. Proved developed reserves and proved oil reserves comprised 60% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2021. The improvement in proved developed reserves as a percentage of our total proved oil and natural gas reserves to 62% at December 31, 2022 from 60% at December 31, 2021 was primarily attributable to the development and conversion of approximately 38.4 million BOE of our proved undeveloped reserves to proved developed reserves and the addition of 24.7 million BOE in extensions and discoveries primarily in the Delaware Basin in 2022.
Operational Highlights
We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2023.
We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin in 2022, including 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells. At December 31, 2022, our total acreage position in the Delaware Basin was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the Wolf and Jackson Trust asset areas in Loving County, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021. We expect our Delaware Basin production to increase in 2023 as we continue the delineation and development of these asset areas.
During 2022, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) were each achieved when we turned to sales:
11 Voni wells, all of which were 2.3-mile laterals, in the western portion of the Stateline asset area in a staggered fashion in early 2022; these 11 Voni wells have produced in aggregate approximately 3.6 million BOE in 11 months of production;
the third group of nine Rodney Robinson wells in the western portion of our Antelope Ridge asset area in March 2022; these nine Rodney Robinson wells have produced in aggregate approximately 3.1 million BOE in 10 months of production;
11 Rustler Breaks wells in April 2022; these 11 wells have produced in aggregate approximately 2.6 million BOE in almost nine months of production;
16 Antelope Ridge wells in the second half of 2022; these 16 wells have produced in aggregate approximately 1.6 million BOE in 2022; and
12 Ranger wells in the fourth quarter of 2022.
In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2022 included:
continued drilling of longer laterals, whereby 90% of the operated horizontal wells we turned to sales in 2022 had lateral lengths of two miles or greater, as compared to 74% in 2020; and
capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2022 of $772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765 to $835

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million as provided on July 26, 2022 and affirmed on October 25, 2022, which included the addition of a seventh operated drilling rig in September 2022.
Capital Resources and Financing Highlights
During 2022, we achieved several significant and important capital resources objectives, which included:
the generation of free cash flow in all four quarters of 2022;
the repayment of all outstanding borrowings under our revolving credit facility, resulting in no outstanding borrowings under that facility at December 31, 2022;
the repurchase of $350.8 million of our outstanding senior notes;
the amendments of our dividend policy in the second and fourth quarters of 2022, pursuant to which we increased the quarterly cash dividend from $0.05 per share of common stock to $0.15 per share of common stock; and
the receipt of $28.3 million in performance incentives directly from Five Point.
In addition, we concluded several important financing transactions in 2022 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included:
the spring and fall redetermination processes revised our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.25 billion, as compared to $1.35 billion at December 31, 2021, (ii) increase the elected borrowing commitment to $775.0 million, as compared to $700.0 million at December 31, 2021, (iii) reaffirm the maximum facility amount at $1.5 billion and (iv) add one new bank to our lending group; and
the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in December 2022 to (i) extend the maturity date by three years from December 2023 to December 2026, (ii) increase the lender commitments under the San Mateo Credit Facility from $450.0 million to $485.0 million, (iii) refresh the accordion feature that provides for potential increases in lender commitments to up to $735.0 million, as compared to $700.0 million previously, and (iv) add one new bank to San Mateo’s lending group.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information regarding these financing transactions.
Midstream Highlights
Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is a wholly-owned subsidiary.
San Mateo achieved strong operating results in 2022, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2022 and 2021.
During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.
At December 31, 2022, San Mateo’s midstream system included:
Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the acreage in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”);
Oil Assets: Three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and

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Produced Water Assets: 15 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
On June 30, 2022, we acquired a wholly-owned subsidiary of Summit Midstream Partners, LP that was subsequently renamed Pronto, which owned a cryogenic gas processing plant with a designed inlet capacity of 60 MMcf of natural gas per day (the “Marlan Processing Plant”), three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico.
Environmental, Social and Governance (“ESG”) Initiatives 
We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and the highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB).
Highlights from our ESG initiatives, which generally relate to our operations in 2021 except as otherwise noted, include:
Decreased direct greenhouse gas emissions intensity by 28% in 2021, as compared to 2020;
Decreased methane emissions intensity by 48% in 2021, as compared to 2020;
Decreased flaring intensity by 53% in 2021, as compared to 2020;
Increased use of non-fresh water to 96% of total water consumption in 2021;
Increased number of wells utilizing recycled produced water to 72% of total wells completed in 2021;
Transported 99% of operated produced water and 89% of operated produced oil by pipeline in 2022;
Incurred no employee lost time incidents during approximately 3.3 million employee man-hours from 2017 to 2022; and
Provided approximately 16,000 hours of employee continuing education, equating to approximately 50 hours per employee in 2022.
These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2022 data from our ESG initiatives in the second half of 2023 in connection with the preparation of our 2022 Sustainability Report.
Recent Developments

On January 24, 2023, our wholly-owned subsidiary entered into a definitive agreement to acquire Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage located primarily in Lea County, New Mexico and Ward County, Texas (the “Advance Acquisition”). The consideration for the Advance Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and for title and environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close in the second quarter of 2023 with an effective date of January 1, 2023.
We estimate the total proved oil and natural gas reserves associated with these properties are approximately 106.4 million BOE (73% oil) at December 31, 2022. These reserves estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Other highlights of the Advance Acquisition include:
Estimated production in the first quarter of 2023 of 24,500 to 25,500 BOE per day (74% oil);
Approximately 18,500 net acres (99% held by production) in the core of the northern Delaware Basin, most of which is strategically located in our Ranger asset area in Lea County, New Mexico near our existing properties;
206 gross (174 net) operated locations (84% working interest) and 200 gross (29 net) non-operated locations (15% working interest);
21 gross (20 net) drilled but uncompleted wells expected to be turned to sales in the second half of 2023;

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Acreage conducive to drilling longer laterals with an expected average lateral length for operated locations of approximately 9,400 feet; and
Upside related to potential midstream opportunities for Pronto, which operates in Lea County, New Mexico.
Exploration and Production Segment
Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. During 2022, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions.
The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2022.
ProducingTotal IdentifiedEstimated Net Proved
Wells
Drilling Locations(1)
Reserves(2)
Avg. Daily
GrossNet Gross  Net    Gross    Net  %Production
AcreageAcreage
MBOE(3)
Developed
(BOE/d)(3)
Southeast New Mexico/West Texas:
Delaware Basin(4)
237,100 129,400 1,087 543.3 4,382 1,468 346,788 61.0 100,135 
South Texas:
Eagle Ford(5)
15,400 13,100 91 72.3 124 98 3,861 100.0 1,373 
Northwest Louisiana
Haynesville16,200 8,900 246 19.1 161 14 5,126 99.0 3,789 
Cotton Valley(6)
15,800 14,900 65 39.8 154 35 947 100.0 168 
Area Total(7)
18,500 17,300 311 58.9 315 49 6,073 99.2 3,957 
Total 271,000 159,800 1,489 674.5 4,821 1,615 356,722 62.1 105,465 
__________________
(1)Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2022. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 80% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2022, these engineered drilling locations included 390 gross (156 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin and only seven gross (less than 0.1 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. At December 31, 2022, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale.
(2)These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.
(3)Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2022.
(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(7)Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2022, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2022, we also were the operator for approximately 87% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage.

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While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.
Southeast New Mexico and West Texas Delaware Basin
The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but, in recent years, the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations.
In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.
At December 31, 2022, our total acreage position in Southeast New Mexico and West Texas was approximately 237,100 gross (129,400 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. These acreage totals included approximately 40,700 gross (22,600 net) acres in our Ranger asset area in Lea County, 59,500 gross (22,500 net) acres in our Arrowhead asset area in Eddy County, 45,500 gross (26,400 net) acres in our Rustler Breaks asset area in Eddy County, 26,500 gross (17,900 net) acres in our Antelope Ridge asset area in Lea County, 14,400 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County and 47,000 gross (25,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2022. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2022, our acreage position in the Delaware Basin was approximately 77% held by existing production. Excluding the Twin Lakes asset area and the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, our acreage position in the Delaware Basin was approximately 92% held by existing production at December 31, 2022.
During the year ended December 31, 2022, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 144 gross (69.8 net) wells in the Delaware Basin, including 81 gross (64.5 net) operated horizontal wells and 63 gross (5.4 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2022, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn.
As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2022. Our average daily oil equivalent production from the Delaware Basin increased approximately 24% to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022, as compared to 80,534 BOE per day (93% of total oil equivalent production), including 47,339 Bbl of oil per day (97% of total oil production) and 199.2 MMcf of natural gas per day (89% of total natural gas production), in 2021.

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At December 31, 2022, approximately 97% of our estimated total proved oil and natural gas reserves, or 346.8 million BOE, was attributable to the Delaware Basin, including approximately 193.5 million Bbl of oil and 919.7 Bcf of natural gas, an 11% increase, as compared to 312.0 million BOE for the year ended December 31, 2021. Our Delaware Basin proved reserves at December 31, 2022 comprised approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 98% of our proved oil reserves and 95% of our proved natural gas reserves at December 31, 2021.
At December 31, 2022, we had identified 4,382 gross (1,468 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,198 gross (1,296 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2022, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 80% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Our engineered well locations, at December 31, 2022, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2022, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling. At December 31, 2022, these potential future drilling locations included 390 gross (156 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves.
We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors.
Antelope Ridge Asset Area - Lea County, New Mexico
In the Antelope Ridge asset area, we turned to sales 26 gross (21.9 net) operated wells and 23 gross (0.6 net) non-operated wells during 2022.
The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. At the end of the first quarter of 2022, we achieved one of our five operational milestones we set for Matador in 2022 when we turned to sales nine gross (8.1 net) wells on the Rodney Robinson leasehold. These wells were the third group of wells drilled on the Rodney Robinson leasehold. The nine Rodney Robinson wells, which included one Third Bone Spring completion, two Second Bone Spring completions, three First Bone Spring completions and three Avalon completions, have produced in aggregate approximately 3.1 million BOE in approximately ten months of production.
In the third and fourth quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 16 gross (12.9 net) operated wells in other portions of the Antelope Ridge asset area. In addition, we turned to sales one gross (0.9 net) operated well in the first quarter of 2022. In total, these 17 Antelope Ridge wells, which included three Third Bone Spring, eight Second Bone Spring and six First Bone Spring completions have produced in aggregate approximately 1.8 million BOE in an average of approximately four months of production.
In September 2022, we added a seventh drilling rig, which enabled us to accelerate the timing of the fourth group of eight Rodney Robinson wells. These eight gross (7.7 net) wells are expected to be turned to sales late in the first quarter of 2023. We plan to turn to sales 12 gross (9.1 net) operated wells in the Antelope Ridge asset area in 2023.
Rustler Breaks Asset Area - Eddy County, New Mexico
In the Rustler Breaks asset area, we turned to sales 21 gross (13.5 net) operated wells and 22 gross (2.3 net) non-operated wells during 2022.

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In the second quarter of 2022, we achieved one of our five operational milestones in 2022 when we turned to sales eleven gross (6.5 net) wells in the Rustler Breaks asset area. In addition, we turned to sales an additional ten gross (7.0 net) operated wells at various times in the third and fourth quarters of 2022. In total, these 21 Rustler Breaks wells, which included four Wolfcamp B, two Wolfcamp A, two Third Bone Spring, one Third Bone Spring Carbonate, seven Second Bone Spring, four First Bone Spring and one Brushy Canyon completions, have produced in aggregate approximately 3.8 million BOE in an average of approximately six months of production.
We plan to turn to sales 21 gross (13.2 net) operated wells in the Rustler Breaks asset area in 2023.
Arrowhead Asset Area - Eddy County, New Mexico
In the Arrowhead asset area, we turned to sales two gross (1.1 net) operated wells and eight gross (1.3 net) non-operated wells during 2022. This included two Second Bone Spring completions that turned to sales late in the fourth quarter of 2022.
We plan to turn to sales 18 gross (11.5 net) operated wells in the Arrowhead asset area in 2023.
Ranger and Twin Lakes Asset Areas - Lea County, New Mexico
In the Ranger asset area, we turned to sales 14 gross (10.1 net) operated wells and ten gross (1.2 net) non-operated wells during 2022. In the Twin Lakes area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2022.
In February 2022, we contracted a sixth drilling rig to begin development on certain properties acquired in the western portion of our Ranger asset area and late in the fourth quarter of 2022, we achieved another one of our five operational milestones for 2022 when we turned to sales 12 gross (8.8 net) wells. This included two Wolfcamp A, four Third Bone Spring, five Second Bone Spring and one First Bone Spring completions, which have in aggregate produced 0.3 million BOE in approximately one month of production.
Early in the first quarter of 2022, we also turned to sales the second batch of two Uncle Ches wells, which targeted the Second Bone Spring Sand. We are very pleased with the results of these additional Uncle Ches wells, which in aggregate, have produced over 0.7 million BOE in 11 months of production and are exhibiting high (90%) oil cuts and low water cuts (approximately one Bbl of water per Bbl of oil produced).
We plan to turn to sales 21 gross (14.5 net) operated wells in the Ranger asset area in 2023, not including any wells expected to be turned to sales on Advance’s properties.
Stateline Asset Area - Eddy County, New Mexico
In the Stateline asset area, we turned to sales 15 gross (15.0 net) operated wells during 2022. Early in the first quarter of 2022, we achieved another one of our five operational milestones in 2022 when we turned to sales 11 gross (11.0 net) wells on the Voni leasehold in the Stateline asset area. The 11 Voni wells, which included four Wolfcamp B, five Third Bone Spring Carbonate and two First Bone Spring completions, have produced in aggregate approximately 3.6 million BOE in approximately 11 months of production. These 11 Voni wells had average completed lateral lengths of approximately 12,100 feet.
In the second quarter of 2022, we returned to Stateline to drill an additional batch of four Wolfcamp B wells on the Boros leasehold on the eastern side of the Stateline asset area. These four Wolfcamp B completions were turned to sales late in the third quarter of 2022 and have produced in aggregate approximately 0.5 million BOE in approximately three months.
We plan to turn to sales eight gross (8.0 net) operated wells in the Stateline asset area in 2023.
Wolf and Jackson Trust Asset Areas - Loving County, Texas
In the Wolf and Jackson Trust asset areas, we turned to sales three gross (2.7 net) operated wells during 2022. This included three Second Bone Spring completions that have in aggregate produced 0.9 million BOE in approximately 11 months.
We plan to turn to sales nine gross (8.3 net) operated wells in the Wolf asset area in 2023.
South Texas Eagle Ford Shale and Other Formations
At December 31, 2022, our properties included approximately 15,400 gross (13,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 89% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2022.

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During the year ended December 31, 2022, we converted approximately $46.5 million of non-core assets to cash, including the sales of approximately 12,000 gross (12,000 net) acres in the Eagle Ford shale for approximately $46.5 million. We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2022. In fact, as of December 31, 2022, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 35% to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022, as compared to 2,126 BOE per day, including 1,528 Bbl of oil per day and 3.6 MMcf of natural gas per day, during 2021. For the year ended December 31, 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 2% for the year ended December 31, 2021.
At December 31, 2022, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.9 million BOE, was attributable to the Eagle Ford shale, including approximately 2.8 million Bbl of oil and 6.5 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2022, essentially unchanged from December 31, 2021.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations
We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville shale wells that were turned to sales in 2022. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2023.
At December 31, 2022, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,800 gross (14,900 net) acres in the Cotton Valley play. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022.
For the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 4% of our average daily oil equivalent production, or 3,516 BOE per day, including nine Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2021, approximately 9% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to these properties. At December 31, 2022, approximately 2% of our estimated total proved reserves, or 6.1 million BOE, was attributable to our properties in Northwest Louisiana.
Midstream Segment
Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Southeast New Mexico and West Texas Delaware Basin
On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year. At February 21, 2023, we had earned all of the potential $73.5 million in performance incentives. Through February 21, 2023, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020 and 2021, and the remaining $14.7 million in performance incentives is expected to be paid during the first quarter of 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement.

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On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024, plus additional performance incentives for securing volumes from third-party customers. At February 21, 2023, we had received $62.2 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements.
Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and facilities that have been developed in the Greater Stebbins Area and the Stateline asset area.
On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition.
Natural Gas Gathering and Processing Assets
The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks.
In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2022, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area.
At December 31, 2022, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles). At December 31, 2022, San Mateo was gathering or transporting all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf asset area.
In addition, at December 31, 2022, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise.
In our Wolf asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Wolf asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines.
At December 31, 2022, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2022, San Mateo gathered an average of approximately 287 MMcf of natural gas per day, an increase of 22% as compared to 236 MMcf of natural gas per day gathered during the year ended December 31, 2021. In addition, during the year ended December 31, 2022, San Mateo processed approximately 289 MMcf of natural gas at the Black River Processing Plant, an increase of 36%, as compared to 213 MMcf of natural gas per day processed during the year ended December 31, 2021. Natural gas gathering and processing volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain

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San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues.
At December 31, 2022, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico.
Crude Oil Gathering and Transportation Assets
San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.
At December 31, 2022, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2022, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area.
At December 31, 2022, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2022, the San Mateo Oil Pipeline Systems had throughput of approximately 48,300 Bbl of oil per day, an increase of 18%, as compared to throughput of approximately 40,800 Bbl of oil per day during the year ended December 31, 2021.
Produced Water Gathering and Disposal Assets
During 2022, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 21, 2023, San Mateo had eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the Wolf asset area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 21, 2023, San Mateo had designed disposal capacity of approximately 445,000 Bbl of produced water per day.
During the year ended December 31, 2022, San Mateo handled approximately 361,000 Bbl of produced water per day, an increase of 30%, as compared to approximately 278,000 Bbl of produced water per day handled during the year ended December 31, 2021.
South Texas / Northwest Louisiana
In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto.

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Operating Summary
The following table sets forth certain unaudited production and operating data for the years ended December 31, 2022, 2021 and 2020.
 Year Ended December 31,
202220212020
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl)21,943 17,840 15,931 
Natural gas (Bcf)99.3 81.7 69.5 
Total oil equivalent (MBOE)(1)
38,495 31,454 27,514 
Average daily production (BOE/d)(1)
105,465 86,176 75,175 
Average Sales Prices:
Oil, without realized derivatives (per Bbl)$96.32 $67.58 $37.38 
Oil, with realized derivatives (per Bbl)$92.87 $56.70 $39.83 
Natural gas, without realized derivatives (per Mcf)$7.98 $6.06 $2.14 
Natural gas, with realized derivatives (per Mcf)$7.15 $5.74 $2.14 
Operating Expenses (per BOE):
Production taxes, transportation and processing$7.33 $5.69 $3.39 
Lease operating$4.08 $3.46 $3.81 
Plant and other midstream services operating$2.48 $1.95 $1.51 
Depletion, depreciation and amortization$12.11 $10.97 $13.15 
General and administrative$3.02 $3.06 $2.27 
__________________
(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
Southeast
New Mexico/West Texas
South TexasNorthwest Louisiana
Delaware Basin
Eagle Ford(1)
Haynesville
Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl)21,585 355 — 21,943 
Natural gas (Bcf)89.8 0.9 8.3 0.3 99.3 
Total oil equivalent (MBOE)(3)
36,550 501 1,383 61 38,495 
Percentage of total annual net production94.9 %1.3 %3.6 %0.2 %100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d)59,139 971 — 60,119 
Natural gas (MMcf/d)246.0 2.4 22.7 1.0 272.1 
Total oil equivalent (BOE/d)100,135 1,373 3,789 168 105,465 
Average Sales Prices(4)
Oil (per Bbl)$96.34 $95.23 $— $91.53 $96.32 
Natural gas (per Mcf)$8.18 $9.04 $5.81 $5.71 $7.98 
Total oil equivalent (per BOE)$76.98 $83.24 $34.87 $37.23 $75.48 
Production Costs(5)
Lease operating, transportation and processing (per BOE)$5.10 $27.41 $5.37 $22.69 $5.43 
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(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. 
Southeast
 New Mexico/West Texas
South TexasNorthwest Louisiana
Delaware Basin
Eagle Ford(1)
Haynesville
Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl)17,279 558 — 17,840 
Natural gas (Bcf)72.7 1.3 7.3 0.4 81.7 
Total oil equivalent (MBOE)(3)
29,395 776 1,217 66 31,454 
Percentage of total annual net production93.4 %2.5 %3.9 %0.2 %100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d)47,339 1,528 — 48,876 
Natural gas (MMcf/d)199.2 3.6 20.0 1.0 223.8 
Total oil equivalent (BOE/d)80,534 2,126 3,334 182 86,176 
Average Sales Prices(4)
Oil (per Bbl)$67.65 $65.41 $— $64.40 $67.58 
Natural gas (per Mcf)$6.33 $7.39 $3.19 $4.31 $6.06 
Total oil equivalent (per BOE)$55.43 $59.49 $19.16 $27.81 $54.06 
Production Costs(5)
Lease operating, transportation and processing (per BOE)$4.49 $19.51 $4.84 $25.69 $4.92 
_________________
(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.


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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
Southeast
 New Mexico/West Texas
South TexasNorthwest Louisiana
Delaware Basin
Eagle Ford(1)
Haynesville
Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl)15,254 674 — 15,931 
Natural gas (Bcf)56.8 1.2 11.0 0.5 69.5 
Total oil equivalent (MBOE)(3)
24,713 883 1,835 83 27,514 
Percentage of total annual net production89.8 %3.2 %6.7 %0.3 %100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d)41,678 1,840 — 43,526 
Natural gas (MMcf/d)155.1 3.4 30.1 1.3 189.9 
Total oil equivalent (BOE/d)67,522 2,412 5,015 226 75,175 
Average Sales Prices(4)
Oil (per Bbl)$37.38 $37.42 $28.77 $38.31 $37.38 
Natural gas (per Mcf)$2.23 $2.82 $1.66 $1.69 $2.14 
Total oil equivalent (per BOE)$28.19 $32.56 $9.94 $11.09 $27.06 
Production Costs(5)
Lease operating, transportation and processing (per BOE)$4.52 $20.52 $4.71 $19.39 $5.09 
_________________
(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021.
Our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021 increased 14% from our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2021, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2021 was 86,176 BOE per day, as compared to 75,175 BOE per day for the year ended December 31, 2020. Our average daily oil production for the year ended December 31, 2021 was 48,876 Bbl of oil per day, an increase of 12% from 43,526 Bbl of oil per day for the year ended December 31, 2020. Our average daily natural gas production for the year ended December 31, 2021 was 223.8 MMcf of natural gas per day, an increase of 18% from 189.9 MMcf of natural gas per day for the year ended December 31, 2020.

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Producing Wells
The following table sets forth information relating to producing wells at December 31, 2022. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 81% in all wells that we operated at December 31, 2022. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. 
Oil WellsNatural Gas WellsTotal Wells
GrossNetGrossNetGrossNet
Southeast New Mexico/West Texas:
Delaware Basin(1)
929 461.8 158 81.5 1,087 543.3 
South Texas:
Eagle Ford(2)
91 72.3 — — 91 72.3 
Northwest Louisiana:
Haynesville— — 246 19.1 246 19.1 
Cotton Valley(3)
1.0 64 38.8 65 39.8 
Area Total1.0 310 57.9 311 58.9 
Total1,021 535.1 468 139.4 1,489 674.5 
__________________
(1)Includes 239 gross (87.5 net) vertical wells that were primarily acquired in multiple transactions.
(2)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(3)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
Estimated Proved Reserves
The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2022, 2021 and 2020. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 
At December 31,(1)
202220212020
Estimated Proved Reserves Data:(2)
Estimated proved reserves:
Oil (MBbl)196,289 181,306 159,949 
Natural Gas (Bcf)962.6 852.5 662.3 
Total (MBOE)(3)
356,722 323,397 270,332 
Estimated proved developed reserves:
Oil (MBbl)116,030 102,233 69,647 
Natural Gas (Bcf)632.9 546.2 323.2 
Total (MBOE)(3)
221,507 193,262 123,507 
Percent developed62.1 %59.8 %45.7 %
Estimated proved undeveloped reserves:
Oil (MBbl)80,259 79,073 90,301 
Natural gas (Bcf)329.7 306.4 339.1 
Total (MBOE)(3)
135,215 130,135 146,825 
Standardized Measure(4) (in millions)
$6,983.2 $4,375.4 $1,584.4 
PV-10(5) (in millions)
$9,132.2 $5,347.6 $1,658.0 
__________________

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(1)Numbers in table may not total due to rounding.
(2)Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas, for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas and for the 12 months ended December 31, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold.
(3)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(5)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022, 2021 and 2020 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022, 2021 and 2020 were $2.15 billion, $972.2 million and $73.6 million, respectively.
Our estimated total proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. This increase in proved oil and natural gas reserves was primarily attributable to (i) our delineation and development operations in the Delaware Basin during 2022 and (ii) the 43% increase in oil prices and the 77% increase in natural gas prices used to estimate total proved reserves at December 31, 2022, as compared to December 31, 2021. We added 71.1 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations turned to sales during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022, but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 7.4 million BOE to proved reserves at a future date.
Our proved oil reserves grew 8% from approximately 181.3 million Bbl at December 31, 2021 to approximately 196.3 million Bbl at December 31, 2022. Our proved natural gas reserves increased 13% from 852.5 Bcf at December 31, 2021 to 962.6 Bcf at December 31, 2022. Our proved reserves to production ratio at December 31, 2022 was 9.3, a decrease of 10% from 10.3 at December 31, 2021.
The Standardized Measure of our total proved oil and natural gas reserves increased 60% from $4.38 billion at December 31, 2021 to $6.98 billion at December 31, 2022. The PV-10 of our total proved oil and natural gas reserves increased 71% from $5.35 billion at December 31, 2021 to $9.13 billion at December 31, 2022. The increases in our Standardized Measure and PV-10 are primarily a result of the significantly higher unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2022, as compared to December 31, 2021, but also due to the 10% increase in our total proved oil and natural gas reserves at December 31, 2022, as compared to December 31, 2021. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2022 were $90.15 per Bbl and $6.36 per MMBtu, an increase of 43% and 77%, respectively, as compared to average oil and natural gas prices of $63.04 per Bbl and $3.60 per MMBtu used to estimate proved reserves at December 31, 2021. Our total proved reserves were made up of 55% oil and 45% natural gas at December 31, 2022 and 56% oil and 44% natural gas at December 31, 2021. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table.

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The following table summarizes changes in our estimated proved developed reserves at December 31, 2022.
Proved Developed Reserves
(MBOE)(1)
As of December 31, 2021193,262 
Extensions and discoveries24,717 
Net acquisitions of minerals-in-place753 
Revisions of prior estimates2,867 
Production(38,495)
Conversion of proved undeveloped to proved developed38,403 
As of December 31, 2022221,507 
__________________
(1)    Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved developed oil and natural gas reserves increased 15% from 193.3 million BOE at December 31, 2021 to 221.5 million BOE at December 31, 2022. We added 24.7 million BOE in proved developed reserves through extensions and discoveries during 2022, which resulted from new well locations drilled during 2022 to establish proved reserves. We realized approximately 2.9 million BOE in net upward revisions to prior estimates, most of which was attributable to the significantly higher commodity prices used to estimate proved reserves at December 31, 2022, which resulted in longer estimated economic lives for certain of our producing properties. In addition, we converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022, primarily in our Ranger, Stateline, Antelope Ridge and Rustler Breaks asset areas. In addition, we realized 0.8 million BOE in net upward revisions to our proved developed reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. These cumulative net upward revisions of 66.7 million BOE to our proved developed reserves exceeded by 1.7 times our total oil and natural gas production of 38.5 million BOE in 2022.
Our proved developed oil reserves increased 13% from 102.2 million Bbl at December 31, 2021 to 116.0 million Bbl at December 31, 2022. Our proved developed natural gas reserves increased 16% from 546.2 Bcf at December 31, 2021 to 632.9 Bcf at December 31, 2022. Proved developed reserves constituted 62% of our total proved oil and natural gas reserves at December 31, 2022, as compared to 60% at December 31, 2021.
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2022.
Proved Undeveloped Reserves
(MBOE)(1)
As of December 31, 2021130,135 
Extensions and discoveries46,388 
Net acquisitions of minerals-in-place264 
Revisions of prior estimates(3,169)
Conversion of proved undeveloped to proved developed(38,403)
As of December 31, 2022135,215 
__________________
(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Our proved undeveloped oil and natural gas reserves increased 4% from 130.1 million BOE at December 31, 2021 to 135.2 million at December 31, 2022. We added 53.8 million BOE in proved undeveloped reserves through extensions and discoveries during 2022, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2022 but which were partially offset by the removal of 7.4 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. We realized approximately 3.2 million BOE in net downward revisions to our prior estimates of proved undeveloped reserves, most of which was attributable to forecast updates at December 31, 2022. In addition, we realized 0.3 million BOE in net upward revisions to our proved undeveloped reserves at December 31, 2022 as a result of property acquisitions and divestitures completed during 2022. During 2022, we also converted 38.4 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin during 2022.

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At December 31, 2022, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2022 within five years of booking these reserves. The following table sets forth, since 2019, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Proved Undeveloped Reserves
Converted to
Proved Developed Reserves
Oil Natural GasTotal
(MBbl)(Bcf)
(MBOE)(1)
201913,832 58.8 23,629 $318,609 
202016,256 76.1 28,944 257,590 
202123,965 96.6 40,071 240,664 
202222,515 95.3 38,403 434,336 
Total76,568 326.8 131,047 $1,251,199 
__________________
(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2022.
Net Proved Reserves(1)
OilNatural GasOil Equivalent
Standardized Measure(2)
PV-10(3)
(MBbl)(Bcf)
 (MBOE)(4)
(in millions)(in millions)
Southeast New Mexico/West Texas:
Delaware Basin193,500 919.7 346,788 $6,852.8 $8,961.8 
South Texas:
Eagle Ford(5)
2,780 6.5 3,861 68.4 89.8 
Northwest Louisiana
Haynesville— 30.8 5,126 56.5 73.9 
Cotton Valley(6)
10 5.6 947 5.2 6.8 
Area Total10 36.4 6,073 61.7 80.7 
Total196,290 962.6 356,722 $6,982.9 $9,132.3 
__________________
(1)Numbers in table may not total due to rounding.
(2)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2022 were approximately $2.15 billion.
(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
Technology Used to Establish Reserves
Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual

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production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods.
Internal Control Over Reserves Estimation Process
We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2022. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of our Board of Directors as well.
Acreage Summary
The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2022.
 Developed Acres Undeveloped Acres Total Acres
 Gross Net GrossNet Gross Net
Southeast New Mexico/West Texas:
Delaware Basin191,300 99,200 45,800 30,200 237,100 129,400 
South Texas:
Eagle Ford 15,400 13,100 — — 15,400 13,100 
Northwest Louisiana:
Haynesville16,200 8,900 — — 16,200 8,900 
Cotton Valley15,800 14,900 — — 15,800 14,900 
Area Total(1)
18,500 17,300 — — 18,500 17,300 
   Total225,200 129,600 45,800 30,200 271,000 159,800 
__________________
(1)Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.

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Undeveloped Acreage Expiration
The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2022 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2028 and beyond totals 7,100 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2022.
AcresAcresAcresAcresAcres
Expiring 2023Expiring 2024Expiring 2025Expiring 2026Expiring 2027
GrossNetGrossNetGrossNetGrossNetGrossNet
Southeast New Mexico/West Texas:
Delaware Basin(1)
7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 
Total7,000 4,300 5,300 1,800 8,600 3,700 5,900 2,000 11,600 11,300 
__________________
(1)Approximately 75% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable.
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2022, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. At December 31, 2022, approximately 1% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage.
Drilling Results
The following table summarizes our drilling activity for the years ended December 31, 2022, 2021 and 2020
Year Ended December 31,
202220212020
GrossNetGrossNetGrossNet
Development Wells
Productive138 61.4 96 40.2 89 44.5 
Dry— — — — — — 
Exploration Wells
Productive(1)
20 11.0 8.0 3.3 
Dry— — — — — — 
Total Wells
Productive158 72.4 104 48.2 93 47.8 
Dry— — — — — — 
(1)Includes 17 gross (9.4 net) horizontal and three gross (1.6 net) vertical wells.
At December 31, 2022, we had a total of 25 gross (19.4 net) development wells and nine gross (7.8 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations.
Marketing and Customers
Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and

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natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids.
Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids, or NGLs, based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.
The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflict between Russia and Ukraine; domestic or global health concerns, including the outbreak of contagious or pandemic diseases such as COVID-19; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.”
For the years ended December 31, 2022, 2021 and 2020, we had three, three and two significant purchasers, respectively, that accounted for approximately 70%, 72% and 65%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference.
Title to Properties
We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to

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expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.”
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business. As discussed below in “—Regulation,” the Biden administration has issued certain orders and implemented certain policies limiting or delaying the issuance of federal drilling permits and other necessary federal approvals. Although some of these restrictions have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear, and should those or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.”

Competition
The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in its areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability.
Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.
Our ability to drill and explore for oil and natural gas, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations.
The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.”

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Environmental
Emissions Mitigation
We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities.
Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control And Data Acquisition (“SCADA”) equipment at a number of larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require.
Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions.
Water Management
Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. This use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water.
Land Stewardship
We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, which results in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations.
During 2022, 89% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the produced oil and water. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions.
Regulation
Oil and Natural Gas Regulation
Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.

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Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022.
In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under the National Environmental Policy Act (“NEPA”) in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits is uncertain.
In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making (the “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the EPA suggested increasing the value of the social cost of carbon from $51 per metric ton to $190 per metric ton.
In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain.
Although some of the restrictions in the Biden Administration Federal Lease Orders lapsed at the end of 2021, the impact of federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is

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located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction.
In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.
As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative.
The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.
In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder.
The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate

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oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.”
Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays.
U.S. Federal and State Taxation
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico.
In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows.
Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.”
Hydraulic Fracturing Policies and Procedures
We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”
The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage).

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Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures.
The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and employ rigorous safety procedures to protect the environment and work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.
While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us. Furthermore, an increasing percentage of the water used in our hydraulic fracturing operations is sourced from recycled produced water from our wells or other sources, further reducing the amount of fresh water in our hydraulic fracturing operations.
Environmental, Health and Safety Regulation
The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”), the Safe Drinking Water Act (the “SDWA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us.
The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action.
The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the Environmental Protection Agency (the “EPA”) and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On December 30, 2022, the

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EPA and the Corps jointly issued a pre-publication of a final rule revising the definition of WOTUS that largely returns to the pre-2015 regulatory regime. The rule will become effective 60 days after publication in the Federal Register.
Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the USFWS under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order was partially vacated in the Ninth Circuit Court of Appeals as moot, based on the Corps’ re-issuance of NWPs in 2021. In 2021, the Corps issued a new set of NWPs to replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but elected not to consult with the USFWS. The re-issued NWPs were subject to the same legal challenges based on the lack of a formal ESA consultation, but in September 2022, the U.S. District Court for Montana dismissed the ESA-consultation challenges as moot and dismissed the remainder of the lawsuit without prejudice.
CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA.
RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes.
The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and imposes a fee on greenhouse gas (“GHG”) emissions from certain facilities that exceed specified emissions levels. In addition, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on GHGs from new and existing sources in the oil and natural gas industry. On December 6, 2022, the EPA published a supplemental proposal to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA. On December 23, 2022, the EPA proposed a rule that would enable states to implement more stringent methane emissions standards than the federal guidelines require. Also in November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas

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production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations.
In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things. Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.”
We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent

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seismic activity require enhanced review prior to approval. The protocols also require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement.
Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.
Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.
We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.
The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On November 25, 2022, a final rule was published that lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. The effective date of the final rule is March 27, 2023. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle

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Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.
As of December 31, 2022, approximately 31% of our Delaware Basin acreage position consisted of federal leasehold administered by the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. Delays in obtaining necessary permits can disrupt our operations and have a material adverse effect on our business. These BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted.
Oil and natural gas exploration and production activities on federal lands are also subject to NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.
We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.”
Office Location
Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240.

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Human Capital
At December 31, 2022, we had 360 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.
Employee Recruiting, Retention and Professional Development
We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status.
Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders.
We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2022, for example, our employees completed approximately 16,000 hours of continuing education and study. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills.
Proactive Safety Culture
We are proud to have a company culture that emphasizes safety throughout our operations. Between 2017 and 2022, we estimate our employees have worked approximately 3.3 million combined hours without experiencing a single lost time incident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations to proactively minimize safety risks and address any potential areas of concern.
We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts.
Available Information
Our Internet website address is www.matadorresources.com. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.

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Item 1A. Risk Factors.
Summary of Risk Factors
The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition, results of operations and cash flows. You should read this summary together with the more detailed risk factors contained below.
Risks Related to the Pending Advance Acquisition
There can be no assurance as to when or if the Advance Acquisition will be completed.
We may be unable to successfully integrate Advance’s business or achieve anticipated benefits.
Risks Related to our Financial Condition
Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition.
Our industry and the broader U.S. economy experienced higher than expected inflationary pressures in 2022.
We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand.
We cannot predict the impact of the ongoing military conflict between Russia and Ukraine.
Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings.
Our oil and natural gas reserves are estimated , and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
Approximately 38% of our total proved reserves at December 31, 2022 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
Unless we replace our oil and natural gas reserves, our reserves and production will decline.
We may be required to write down the carrying value of our proved properties under accounting rules.
Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us.
Our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.
We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly.
We may incur losses or costs as a result of title deficiencies in the properties in which we invest.
Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.
Risks Related to our Liquidity
We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility.
The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.
The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations.
Our credit rating may be downgraded, which could reduce our financial flexibility.
Dividend payments are at the discretion of our Board of Directors and subject to numerous factors.
Risks Related to our Operations
Drilling for and producing oil and natural gas involve a high degree of operational and financial risk.
Our reserves and production are concentrated in a few core areas.
There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques.
Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators.
Multi-well pad drilling may result in volatility in our operating results.
The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis.
We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules.
Regulatory changes could prevent our ability to continue to pool wells in accordance with our past practices.

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Midstream projects are subject to risks of construction delays and cost over-runs.
Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling.
The seismic data and other technologies we use cannot eliminate exploration risk.
Risks Related to Third Parties
Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations.
The marketability of our production is dependent upon gathering, processing and transportation facilities.
We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks.
San Mateo’s and Pronto’s long-term success depends on their ability to obtain new sources of products, which depends on certain factors beyond their control.
Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers.
We do not own all of the land on which our midstream assets are located, which could disrupt our operations.
Competition in our industry is intense, and our competitors may use superior technology and data resources.
Strategic relationships upon which we may rely are subject to change.
We have limited control over activities on properties we do not operate.
Risks Related to Laws and Regulations
Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations.
We are subject to government regulation, including complex environmental laws, which could require significant expenditures.
We are subject to tax laws, and changes thereto could eliminate or reduce certain federal income tax deductions currently available.
Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs and additional operating restrictions or delays, and the physical effects of climate change could disrupt our production and cause us to incur significant costs.
New climate disclosure rules proposed by the SEC could increase our costs of compliance.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets.
The rates of our regulated assets are subject to review and reporting by federal regulators.
Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with our business.
Risks Relating to Our Common Stock
The price of our common stock has fluctuated substantially and may fluctuate substantially in the future.
Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect us.
Future sales and offerings of our common stock could depress the price of our common stock.
Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders.
The issuance of preferred stock could diminish the rights of holders of our common stock.
General Risk Factors
We may have difficulty managing growth in our business.
The loss of any key personnel, Board member or special Board advisor could disrupt our business operations.
A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.
Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control.
We operate in a litigious environment and may be involved in legal proceedings.
Risks Related to the Pending Advance Acquisition
The consummation of the Advance Acquisition is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if the Advance Acquisition will be completed, and the failure to complete the Advance Acquisition could have a material and adverse effect on our business, financial condition, results of operations and cash flows.
Although we expect to complete the Advance Acquisition in the second quarter of 2023, there can be no assurances as to the exact timing of the closing or that the Advance Acquisition will be completed at all. The consummation of the Advance

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Acquisition is subject to the satisfaction or waiver of a number of conditions contained in the related securities purchase agreement, including, among others, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the Advance Acquisition uncertain. In addition, the securities purchase agreement contains certain termination rights for both parties, which if exercised will also result in the Advance Acquisition not being consummated. Any such termination or any failure to otherwise complete the Advance Acquisition could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the Advance Acquisition, without realizing any of the benefits of completing the Advance Acquisition; being required to pay our legal, accounting and other expenses relating to the Advance Acquisition; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the Advance Acquisition will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the Advance Acquisition are not realized. Such consequences could materially and adversely affect our business, financial condition, results of operations and cash flows.
Even if the Advance Acquisition is completed, we may be unable to successfully integrate Advance’s business into our business or achieve the anticipated benefits of the Advance Acquisition.
The success of the Advance Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the assets and operations of Advance into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Advance Acquisition. Difficulties in integrating Advance into our company and our ability to manage the combined company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others:
the inability to successfully integrate Advance operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from the Advance Acquisition;
not realizing anticipated operating synergies; and
potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Advance Acquisition.
Risks Related to our Financial Condition
Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.
The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2022, oil prices averaged $94.33 per Bbl, as compared to $68.11 per Bbl in 2021, ranging from a high of $123.70 per Bbl in early March to a low of $71.02 per Bbl in early December, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2022, natural gas prices averaged $6.54 per MMBtu, as compared to $3.71 per MMbtu in 2021, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2022, natural gas prices ranged from a low of $3.72 per MMBtu in early January to a high of $9.68 per MMBtu in mid-August before finishing the year at $4.48 per MMBtu.
The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include, but are not limited to, the following:
the domestic and foreign supply of, and demand for, oil, natural gas and NGLs;
the actions of OPEC+ and state-controlled oil companies;
the prices and availability of competitors’ supplies of oil, natural gas and NGLs;
the price and quantity of foreign imports;
the impact of U.S. dollar exchange rates;
domestic and foreign governmental regulations and taxes;
speculative trading of oil and natural gas futures contracts;

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the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water;
the availability of refining capacity;
the prices and availability of alternative fuel sources;
weather conditions and natural disasters, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin;
political conditions in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China;
the ongoing military conflict between Russia and Ukraine;
domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19 and its variants;
the continued threat of terrorism and the impact of military action and civil unrest;
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities;
the level of global oil, natural gas and NGL inventories and exploration and production activity;
the impact of energy conservation efforts;
technological advances affecting energy consumption; and
overall worldwide economic conditions.
These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts. Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relation to each other.
Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months.
Our industry and the broader U.S. economy experienced higher than expected inflationary pressures in 2022 related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Inflation in the U.S. has become much more significant in recent years, and in 2022 it reached its highest levels in approximately 40 years. Throughout 2022, we began to experience significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, inflation and other factors. These challenges are due in part to increased demand for oil and natural gas production driven by the continued economic recovery from the COVID-19 pandemic and, more broadly, systemic underinvestment in global oil and natural gas development. These supply and demand fundamentals have been further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflict between Russia and Ukraine. We expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary

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products and services we need for drilling, completing and producing wells in a timely fashion, which could result in delays to our operations and could, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flows.
We face numerous risks related to the COVID-19 pandemic, including its impact on global oil demand, which has had and, depending on the progression of the pandemic, may continue to have, a material adverse effect on our business, financial condition, results of operations and cash flows.
Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 and its variants has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which materially reduced global demand for crude oil, natural gas and NGLs in 2020. Although demand for crude oil, natural gas and NGLs generally increased in 2021 and 2022 as many travel restrictions, business closures and other restrictions on conducting business were lifted in response to improved treatments and availability of vaccinations, we cannot reasonably predict the future impact of COVID-19 or its variants on overall economic activity and the demand for, and pricing of, our products.
The extent to which COVID-19 or its variants will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the pandemic and responsive measures, the emergence, contagiousness and threat of new strains of the virus and their severity, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 or its variants, the effectiveness of treatments, vaccines and other actions taken to contain COVID-19 or its variants or treat its impact now or in the future, disruptions in the supply chain and an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic, among others.
Some impacts of the COVID-19 pandemic that could have a material adverse effect on our business, financial condition, results of operations and cash flows include:
significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;
decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19 or its variants;
increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces;
significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo or Pronto due to curtailed or shut-in production by Matador or other of San Mateo’s or Pronto’s customers;
increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate;
increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints;
the potential for the operations of the Black River Processing Plant, the Marlan Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 or its variants among the relevant workforce;
the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production;
the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;
increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns;

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increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;
the potential impact for delays in construction or increased costs related to midstream construction projects;
increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and
increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations.
The COVID-19 pandemic continues to evolve, and the extent to which the pandemic may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired.
We cannot predict the impact of the ongoing military conflict between Russia and Ukraine and the related humanitarian crisis on the global economy, energy markets, geopolitical stability and our business.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and sustained conflict and disruption in the region is likely. Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the Russian-Ukrainian conflict, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of the conflict’s effect on our business and results of operations as well as on the global economy and energy markets.
Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.
Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings, under our Credit Agreement, the San Mateo Credit Facility or otherwise, may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.
Our cash flows from operations and access to capital are subject to a number of variables, including:
our estimated proved oil and natural gas reserves;
the amount of oil and natural gas we produce;
the prices at which we sell our production;
the costs of developing and producing our oil and natural gas reserves;
the costs of constructing, operating and maintaining our midstream facilities;
our ability to attract third-party customers for our midstream services;
our ability to acquire, locate and produce new reserves;
the ability and willingness of banks to lend to us; and
our ability to access the equity and debt capital markets.
In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missio