# Matador Resources Co (MTDR) Informational only - not investment advice. CIK: 0001520006 SIC: 1311 Crude Petroleum & Natural Gas SIC breadcrumb: [Mining](/division/B/) > [SIC Major Group 13](/major-group/13/) > [SIC 1311 Crude Petroleum & Natural Gas](/industry/1311/) Latest 10-K filed: 2026-02-26 SEC page: https://www.sec.gov/edgar/browse/?CIK=1520006 Filing source: https://www.sec.gov/Archives/edgar/data/1520006/000152000626000002/mtdr-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 3696277000 | USD | 2025 | 2026-02-26 | | Net income | 759221000 | USD | 2025 | 2026-02-26 | | Assets | 11710569000 | USD | 2025 | 2026-02-26 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001520006.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | 264,422,000 | 544,276,000 | 899,599,000 | 983,670,000 | 862,126,000 | 1,662,981,000 | 3,058,025,000 | 2,806,785,000 | 3,504,981,000 | 3,696,277,000 | | Net income | -97,421,000 | 125,867,000 | 274,207,000 | 87,777,000 | -593,205,000 | 584,968,000 | 1,214,206,000 | 846,074,000 | 885,322,000 | 759,221,000 | | Operating income | -177,167,000 | 160,841,000 | 363,271,000 | 235,480,000 | -521,499,000 | 793,076,000 | 1,759,270,000 | 1,209,322,000 | 1,434,698,000 | 1,226,542,000 | | Diluted EPS | -1.07 | 1.23 | 2.41 | 0.75 | -5.11 | 4.91 | 10.11 | 7.05 | 7.14 | 6.09 | | Assets | 1,464,665,000 | 2,145,690,000 | 3,455,518,000 | 4,069,676,000 | 3,687,280,000 | 4,262,153,000 | 5,554,505,000 | 7,726,996,000 | 10,850,109,000 | 11,710,569,000 | | Stockholders' equity | 690,125,000 | 1,156,556,000 | 1,688,880,000 | 1,833,654,000 | 1,286,530,000 | 1,907,210,000 | 3,110,797,000 | 3,910,862,000 | 5,089,149,000 | 5,658,141,000 | | Cash and cash equivalents | 212,884,000 | 96,505,000 | 64,545,000 | 40,024,000 | 57,916,000 | 48,135,000 | 505,179,000 | 52,662,000 | 23,033,000 | 15,314,000 | | Net margin | -36.84% | 23.13% | 30.48% | 8.92% | -68.81% | 35.18% | 39.71% | 30.14% | 25.26% | 20.54% | | Operating margin | -67.00% | 29.55% | 40.38% | 23.94% | -60.49% | 47.69% | 57.53% | 43.09% | 40.93% | 33.18% | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-08. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001520006.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 3.47 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 2.82 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 1.36 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 638,083,000 | 164,666,000 | 1.37 | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 772,294,000 | 263,739,000 | 2.20 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 836,132,000 | 254,539,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 787,693,000 | 193,729,000 | 1.61 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 847,136,000 | 228,769,000 | 1.83 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 899,783,000 | 248,291,000 | 1.99 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 970,369,000 | 214,533,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 1,013,958,000 | 240,085,000 | 1.92 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 895,312,000 | 150,225,000 | 1.21 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 939,015,000 | 176,364,000 | 1.42 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 847,992,000 | 192,547,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 671,637,000 | -35,872,000 | -0.29 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1520006/000152000626000023/mtdr-20260331.htm Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high Filing date: 2026-05-08 Report date: 2026-03-31 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our interim unaudited condensed consolidated financial statements and related notes thereto contained herein and the consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2025 (the “Annual Report”) filed with the Securities and Exchange Commission (the “SEC”) on February 26, 2026, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Annual Report. The Annual Report is accessible on the SEC’s website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with the “Risk Factors” section of the Annual Report and the section entitled “Cautionary Note Regarding Forward-Looking Statements” below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements. In this Quarterly Report on Form 10-Q (this “Quarterly 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 and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries. For certain oil and natural gas terms used in this Quarterly Report, please see the “Glossary of Oil and Natural Gas Terms” included with the Annual Report. Cautionary Note Regarding Forward-Looking Statements Certain statements in this Quarterly 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. All statements, other than statements of historical fact, included in this Quarterly Report regarding our strategy, future operations, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. 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,” “seek,” “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 those described in the “Risk Factors” section of the Annual Report, as well as the following factors, among others: general economic conditions, including the effects of inflation and interest rates; tariffs and trade tensions; 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 NGLs or the construction, expansion or operation of our midstream assets; 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, capital markets, 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 conditions, environmental conditions and natural disasters; disruption from our acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitions; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to 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; 21 •the availability of drilling and production equipment; •the availability of oil storage capacity; •the availability and cost 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 with our business; •government regulation and taxation of the oil and natural gas industry; •tariffs and trade restrictions; •our marketing of oil and natural gas; •our exploitation projects or property acquisitions; •the ability of our midstream business 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; •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; •our future operating results; •the impact of the One Big Beautiful Bill Act of 2025 (the “OBBBA”); and •our plans, objectives, expectations and intentions contained in this Quarterly 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 Quarterly 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. Overview 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 have operations in the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, 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. 22 First Quarter Highlights For the three months ended March 31, 2026, our total oil equivalent production was 18.7 million BOE, and our average daily oil equivalent production was 207,594 BOE per day, of which 120,277 Bbl per day, or 58%, was oil and 523.9 MMcf per day, or 42%, was natural gas. Our average daily oil production of 120,277 Bbl per day for the three months ended March 31, 2026 increased 5% year-over-year from 115,030 Bbl per day for the three months ended March 31, 2025. Our average daily natural gas production of 523.9 MMcf per day for the three months ended March 31, 2026 increased 4% year-over-year from 501.6 MMcf per day for the three months ended March 31, 2025. The Delaware Basin contributed 100% of our daily oil production and 97% of our daily natural gas production in the first quarter of 2026, as compared to 100% of our daily oil production and 96% of our daily natural gas production in the first quarter of 2025. For the first quarter of 2026, we reported a net loss attributable to Matador shareholders of $35.9 million, or $0.29 per diluted common share, on a GAAP basis, primarily resulting from a $255.5 million unrealized loss on derivatives, as compared to net income attributable to Matador shareholders of $240.1 million, or $1.92 per diluted common share, for the first quarter of 2025. For the first quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $577.2 million, as compared to Adjusted EBITDA of $644.2 million during the first quarter of 2025. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see “—Liquidity and Capital Resources—Non-GAAP Financial Measures.” For more information regarding our financial results for the three months ended March 31, 2026, see “—Results of Operations” below. 2026 Capital Expenditure Budget Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for drilling, completing and equipping (“D/C/E”) capital expenditures and $100.0 to $110.0 million for midstream ca [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” For a comparison of our results of operations for the years ended December 31, 2024 and December 31, 2023, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 25, 2025. Overview We are an independent energy company founded in July 2003 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 have operations in the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, 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. 2025 Operational Highlights During the year ended December 31, 2025, we completed and began producing oil and natural gas from 151 gross (121.2 net) operated and 107 gross (8.1 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2025, although we did participate in the drilling and completion of 12 gross (0.1 net) non-operated Haynesville shale wells that began producing in 2025. 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. We were able to achieve D/C/E capital expenditures for 2025 of $1.53 billion, which was within our estimated range for 2025 D/C/E capital expenditures of $1.47 to $1.55 billion, as provided on October 21, 2025. Substantially all of our 2025 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. Our average daily oil equivalent production for the year ended December 31, 2025 was 207,070 BOE per day, including 119,723 Bbl of oil per day and 524.1 MMcf of natural gas per day, an increase of 21%, as compared to 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, for the year ended December 31, 2024. Our average daily oil production in 2025 was 119,723 Bbl of oil per day, an increase of 20%, as compared to 99,808 Bbl of oil per day in 2024. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2025 was 524.1 MMcf per day, an increase of 23%, as compared to 425.7 MMcf per day in 2024. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% of our total production for each of the years ended December 31, 2025 and 2024. For the year ended December 31, 2025, our oil and natural gas revenues were $3.24 billion, an increase of 3% from oil and natural gas revenues of $3.14 billion for the year ended December 31, 2024. Our oil revenues increased 2% to $2.84 billion, 70 Table of Contents as compared to $2.77 billion for the year ended December 31, 2024. The increase in oil revenues resulted from the 20% increase in our oil production noted above, which was partially offset by a 14% decrease in the weighted average oil price realized for the year ended December 31, 2025 to $64.99 per Bbl, as compared to $75.89 per Bbl realized for the year ended December 31, 2024. Our natural gas revenues increased 7% to $398.6 million, as compared to $371.5 million for the year ended December 31, 2024. The increase in natural gas revenues resulted from a 23% increase in natural gas production for the year ended December 31, 2025 noted above, which was partially offset by a decrease in our weighted average realized natural gas price of $2.08 per Mcf in 2025, as compared to $2.38 per Mcf in 2024. We reported net income attributable to Matador shareholders of approximately $759.2 million, or $6.09 per diluted common share, on a GAAP basis for the year ended December 31, 2025, as compared to a net income of $885.3 million, or $7.14 per diluted common share, for the year ended December 31, 2024. Adjusted EBITDA for the year ended December 31, 2025 was $2.29 billion, as compared to Adjusted EBITDA of $2.30 billion for the year ended December 31, 2024. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” At December 31, 2025, our estimated total proved oil and natural gas reserves were 667.0 million BOE, including 376.0 million Bbl of oil and 1.75 Tcf of natural gas, with a Standardized Measure of $6.99 billion and a PV-10 of $8.24 billion. At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. Our estimated total proved reserves of 667.0 million BOE at December 31, 2025 represented a 9% year-over-year increase, as compared to 611.5 million BOE at December 31, 2024. Our estimated proved oil reserves were 376.0 million Bbl at December 31, 2025, an increase of 4%, as compared to 361.8 million Bbl at December 31, 2024, and our estimated proved natural gas reserves were 1.75 Tcf at December 31, 2025, an increase of 17%, as compared to 1.50 Tcf at December 31, 2024. Proved oil reserves comprised 56% of our total proved reserves at December 31, 2025, as compared to 59% at December 31, 2024. At December 31, 2025, 61% of our total proved reserves were proved developed reserves, as compared to 60% at December 31, 2024. At December 31, 2025, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. At both December 31, 2025 and December 31, 2024, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. 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% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.” 2025 Midstream Highlights San Mateo achieved strong operating results in 2025, 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. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point. During the second quarter of 2025, San Mateo completed the expansion of the Marlan Processing Plant by adding a designed inlet capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities. This expansion increased the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day. At December 31, 2025, San Mateo’s midstream system included: •Natural Gas Assets: 720 MMcf per day of designed natural gas cryogenic processing capacity and approximately 340 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; •Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 120 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 to gather our and other producers’ oil production in Eddy County, New Mexico; and •Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 195 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. 71 Table of Contents 2026 Capital Expenditure Budget We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2026. 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. Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for D/C/E capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells. At December 31, 2025, we had $15.3 million in cash (excluding restricted cash) and $1.80 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2026 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2026, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. We intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. Purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2026. As we have done in recent years, we may divest portions of our non-core assets as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. Divestitures and other types of monetizations are difficult to estimate with any degree of certainty. Therefore, we have not provided estimated proceeds related to divestitures or monetizations for 2026. 72 Table of Contents Revenues The following table summarizes our revenues and production data for the periods indicated. Year Ended December 31, 2025 2024 2023 Operating Data: Revenues (in thousands):(1) Oil $ 2,840,167  $ 2,772,360  $ 2,144,894  Natural gas 398,583  371,474  400,705  Total oil and natural gas revenues 3,238,750  3,143,834  2,545,599  Third-party midstream services revenues 164,733  141,027  122,153  Sales of purchased natural gas 253,031  194,097  149,869  Realized gain (loss) on derivatives 21,679  12,724  (9,575) Unrealized gain (loss) on derivatives 18,084  13,299  (1,261) Total revenues $ 3,696,277  $ 3,504,981  $ 2,806,785  Net Production Volumes:(1) Oil (MBbl) 43,699  36,530  27,542  Natural gas (Bcf) 191.3  155.8  123.4  Total oil equivalent (MBOE)(2) 75,581  62,495  48,112  Average daily production (BOE/d)(2) 207,070  170,751  131,813  Average Sales Prices: Oil, without realized derivatives (per Bbl) $ 64.99  $ 75.89  $ 77.88  Oil, with realized derivatives (per Bbl) $ 64.99  $ 75.89  $ 77.88  Natural gas, without realized derivatives (per Mcf) $ 2.08  $ 2.38  $ 3.25  Natural gas, with realized derivatives (per Mcf) $ 2.20  $ 2.47  $ 3.17  ________________ (1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues. (2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Year Ended December 31, 2025 as Compared to Year Ended December 31, 2024 Oil and natural gas revenues. Our oil and natural gas revenues increased $94.9 million, or 3%, to $3.24 billion for the year ended December 31, 2025, as compared to $3.14 billion for the year ended December 31, 2024. Our oil revenues increased $67.8 million, or 2%, to $2.84 billion for the year ended December 31, 2025, as compared to $2.77 billion for the year ended December 31, 2024. This increase in oil revenues resulted from a 20% increase in our oil production to 43.7 million Bbl of oil for the year ended December 31, 2025, as compared to 36.5 million Bbl of oil for the year ended December 31, 2024, which was partially offset by a 14% decrease in the weighted average oil price realized for the year ended December 31, 2025 to $64.99 per Bbl, as compared to $75.89 per Bbl realized for the year ended December 31, 2024. Our natural gas revenues increased by $27.1 million, or 7%, to $398.6 million for the year ended December 31, 2025, as compared to $371.5 million for the year ended December 31, 2024. The increase in natural gas revenues was primarily attributable to a 23% increase in our natural gas production to 191.3 Bcf for the year ended December 31, 2025, as compared to 155.8 Bcf for the year ended December 31, 2024, which was partially offset by a 13% decrease in the weighted average natural gas price realized for the year ended December 31, 2025 to $2.08 per Mcf, as compared to $2.38 per Mcf realized for the year ended December 31, 2024. Third-party midstream services revenues. Our third-party midstream services revenues increased $23.7 million, or 17%, to $164.7 million for the year ended December 31, 2025, as compared to $141.0 million for the year ended December 31, 2024. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering and processing revenues to $90.3 million for the year ended December 31, 2025, as compared to $67.5 million for the year ended December 31, 2024, (ii) an increase in our oil transportation revenues to $23.7 million for the year ended December 31, 2025, as compared to $17.3 million for the year ended December 31, 2024, which were partially offset by (iii) a decrease in third-party produced water disposal revenues to $50.7 million for the year ended December 31, 2025, as compared to $56.3 million for the year ended December 31, 2024. Sales of purchased natural gas. Our sales of purchased natural gas increased $58.9 million, or 30%, to $253.0 million for the year ended December 31, 2025, as compared to $194.1 million for the year ended December 31, 2024. This increase was primarily the result of a 21% increase in natural gas volumes sold and an 8% increase in natural gas prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties 73 Table of Contents whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income. Realized gain (loss) on derivatives. Our realized net gains on derivatives were $21.7 million and $12.7 million for the years ended December 31, 2025 and 2024, respectively. These realized net gains were related to natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized average gains on our natural gas derivatives of approximately $0.12 and $0.09 per Mcf of natural gas produced during the years ended December 31, 2025 and 2024, respectively. Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.1 million for the year ended December 31, 2025, as compared to an unrealized gain of $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2025, the aggregate net fair value of our open oil and natural gas costless collars and natural gas basis differential swap contracts changed from a net asset of approximately $16.0 million to a net asset of approximately $34.1 million, resulting in an unrealized gain on derivatives of approximately $18.1 million for the year ended December 31, 2025. During the year ended December 31, 2024, the aggregate net fair value of our open oil and natural gas derivative contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. 74 Table of Contents Expenses     The following table summarizes our operating expenses and other income (expense) for the periods indicated. Year Ended December 31, 2025 2024 2023 (In thousands, except expenses per BOE) Expenses: Lease operating $ 415,810  $ 325,145  $ 232,521  Transportation and processing 66,787  58,593  59,912  Midstream operating 208,142  167,400  124,021  Purchased natural gas 163,094  142,715  129,401  Depletion, depreciation and amortization 1,195,358  974,300  716,688  Taxes other than income 275,629  268,649  220,604  Accretion of asset retirement obligations 7,846  6,027  3,943  General and administrative 137,069  127,454  110,373  Total expenses 2,469,735  2,070,283  1,597,463  Operating income 1,226,542  1,434,698  1,209,322  Other income (expense): Net loss on asset sales and impairment (589) —  (202) Interest expense (208,520) (171,687) (121,520) Other income 16,011  696  8,785  Total other expense (193,098) (170,991) (112,937) Income before income taxes 1,033,444  1,263,707  1,096,385  Income tax provision (benefit) Current 7,088  27,059  13,922  Deferred 165,587  265,305  172,104  Total income tax provision 172,675  292,364  186,026  Net income attributable to non-controlling interest in subsidiaries (101,548) (86,021) (64,285) Net income attributable to Matador Resources Company shareholders $ 759,221  $ 885,322  $ 846,074  Expenses per BOE: Lease operating $ 5.50  $ 5.20  $ 4.83  Transportation and processing $ 0.88  $ 0.94  $ 1.25  Midstream operating $ 2.75  $ 2.68  $ 2.58  Depletion, depreciation and amortization $ 15.82  $ 15.59  $ 14.90  Taxes other than income $ 3.65  $ 4.30  $ 4.59  General and administrative $ 1.81  $ 2.04  $ 2.29  Year Ended December 31, 2025 as Compared to Year Ended December 31, 2024 Lease operating expenses. Our lease operating expenses increased $90.7 million, or 28%, to $415.8 million for the year ended December 31, 2025, as compared to $325.1 million for the year ended December 31, 2024. On a unit-of-production basis, our lease operating expenses increased 6% to $5.50 per BOE for the year ended December 31, 2025, as compared to $5.20 per BOE for the year ended December 31, 2024. These increases were primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) for the year ended December 31, 2025, as compared to the year ended December 31, 2024. Transportation and processing. Our transportation and processing expenses increased $8.2 million, or 14%, to $66.8 million for the year ended December 31, 2025, as compared to $58.6 million for the year ended December 31, 2024. This increase in transportation and processing expenses is primarily due to the 21% increase in our total oil equivalent production between the two periods. On a unit-of-production basis, our transportation and processing expenses decreased 6% to $0.88 per BOE for the year ended December 31, 2025, as compared to $0.94 per BOE for the year ended December 31, 2024. This decrease per BOE primarily resulted from the mix of revenue contracts, including from San Mateo, between the two periods. Midstream operating. Our midstream operating expenses increased $40.7 million, or 24%, to $208.1 million for the year ended December 31, 2025, as compared to $167.4 million for the year ended December 31, 2024. This increase was primarily attributable to the expansion of the Marlan Processing Plant and increased throughput volumes from Matador’s wholly-owned midstream assets, which resulted in (i) increased expenses associated with our expanded pipeline operations of $100.9 million for the year ended December 31, 2025, as compared to $73.9 million for the year ended December 31, 2024 and (ii) increased expenses associated with plant processing of $52.7 million for the year ended December 31, 2025, as compared to $34.6 million 75 Table of Contents for the year ended December 31, 2024, which was partially offset by (iii) decreased expenses associated with our commercial produced water disposal operations of $59.5 million for the year ended December 31, 2025, as compared to $63.0 million for the year ended December 31, 2024. Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $221.1 million, or 23%, to $1.20 billion for the year ended December 31, 2025, as compared to $974.3 million for the year ended December 31, 2024, primarily as a result of the 21% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 1% to $15.82 per BOE for the year ended December 31, 2025, as compared to $15.59 per BOE for the year ended December 31, 2024. Taxes other than income. Our taxes other than income increased $7.0 million, or 3%, to $275.6 million for the year ended December 31, 2025, as compared to $268.6 million for the year ended December 31, 2024. This increase in taxes other than income is primarily due to the increase in oil and natural gas revenues between the two periods. On a unit-of-production basis, our taxes other than income decreased 15% to $3.65 per BOE for the year ended December 31, 2025, as compared to $4.30 per BOE for the year ended December 31, 2024. This decrease per BOE was primarily attributable to a 14% decrease in realized oil prices between the two periods. General and administrative. Our general and administrative expenses increased $9.6 million, or 8%, to $137.1 million for the year ended December 31, 2025, as compared to $127.5 million for the year ended December 31, 2024, primarily due to increased payroll for our existing employees as well as with additional employees joining Matador to support our increased land, geoscience, drilling, completion, production, midstream and administration functions as a result of our continued growth. Our general and administrative expenses on a unit-of-production basis decreased 11% to $1.81 per BOE for the year ended December 31, 2025, as compared to $2.04 per BOE for the year ended December 31, 2024, primarily as a result of the 21% increase in our total oil equivalent production between the two periods. Interest expense. For the year ended December 31, 2025, we incurred total interest expense of approximately $237.3 million. We capitalized approximately $28.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2025 and expensed the remaining $208.5 million to operations. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. The increase in interest expense for the year ended December 31, 2025 was primarily attributable to a $602.3 million increase in the weighted average of senior notes outstanding between the periods in connection with the Ameredev Acquisition in September 2024. Total income tax provision. We recorded a current income tax provision of $7.1 million and a deferred income tax provision of $165.6 million for the year ended December 31, 2025. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. The decrease in the current income tax provision between the periods was primarily the result of the OBBBA, which made permanent, extended or modified certain provisions under the 2017 Tax Cuts and Jobs Act, among other things. The provisions of the OBBBA that are expected to most significantly impact us include (i) a permanent extension of 100% bonus depreciation for certain capital expenditures, (ii) an immediate deduction of domestic research and experimental expenditures, (iii) an acceleration of deductions for unamortized domestic research or development expenditures and (iv) an elimination of the deduction for depreciation, amortization and depletion from the definition of “adjusted taxable income” for the purpose of calculating limitations on interest expense deductions. The effective income tax rate and the total income tax provision for the year ended December 31, 2025 were not materially impacted by the enactment of the OBBBA. Our effective income tax rate of 19% for the year ended December 31, 2025 differed from the U.S. federal statutory rate due primarily to a benefit recognized as a result of the remeasurement of deferred income taxes associated with changes in state apportionment rates following the Company’s filings of its 2024 tax returns, partially offset by state taxes in New Mexico. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes in New Mexico. Our effective income tax rate excluding the effect of net income attributable to non-controlling interest in subsidiaries was 17% and 23% for the years ended December 31, 2025 and 2024, respectively, as disclosed in Note 8 to the consolidated financial statements. 76 Table of Contents Liquidity and Capital Resources Our primary use of capital has been, and we expect will continue during 2026 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2026 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2026, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. At December 31, 2025, we had cash totaling $15.3 million and restricted cash totaling $64.2 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. At December 31, 2025, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 6.500% senior notes due 2032 (the “2032 Notes”), (iii) $750.0 million of outstanding 6.250% senior notes due 2033 (the “2033 Notes”), (iv) $398.0 million of borrowings outstanding under the Credit Agreement and (v) approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We were in compliance with the terms of the Credit Agreement at December 31, 2025. At December 31, 2025, San Mateo had $883.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In December 2025, San Mateo and certain of its lenders amended the San Mateo Credit Facility to (i) increase the lender commitments from $850.0 million to $1.10 billion, (ii) reduce the borrowing rate and (iii) add one new bank to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments of up to $1.35 billion. The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2025. In February 2025, April 2025 and July 2025, our Board declared quarterly cash dividends of $0.3125 per share of common stock. In October 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.375 per share of common stock and also declared a quarterly cash dividend of $0.375 per share of common stock. In February 2026, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on March 10, 2026 to shareholders of record as of February 27, 2026. In April 2025, the Board approved the Share Repurchase Program authorizing the repurchase of up to $400.0 million of common stock. These repurchases may be conducted through a variety of methods including open market purchases, 10b5-1 trading plans, privately negotiated transactions or other means. The timing and number of shares that we may repurchase under the Share Repurchase Program is subject to a variety of factors, including our stock price, market conditions, trading volume and other uses for our free cash flow. There can be no assurance regarding the exact number of shares to be repurchased by us, if any. Depending on market conditions and other factors, these repurchases may be commenced or suspended at any time periodically without prior notice, and the Share Repurchase Program does not obligate us to acquire any amount of common 77 Table of Contents stock. During the year ended December 31, 2025, we repurchased 1,351,328 shares of common stock under the Share Repurchase Program at a weighted average price of $41.31 per common share for a total cost of $55.8 million. We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2026. 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. Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for D/C/E capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells. We intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. Purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2026. As we have done in recent years, we may divest portions of our non-core assets as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. Divestitures and other types of monetizations are difficult to estimate with any degree of certainty. Therefore, we have not provided estimated proceeds related to divestitures or monetizations for 2026. Our 2026 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2026 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin. Our existing operated and non-operated wells may not produce at the levels we are forecasting or may be temporarily shut in or restricted due to low commodity prices, and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2026 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2025. See “Risk Factors—Risks Related to our Financial Condition—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,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% 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.” 78 Table of Contents Our cash flows for the years ended December 31, 2025, 2024 and 2023 are presented below. Year Ended December 31, 2025 2024 2023 (In thousands) Net cash provided by operating activities $ 2,425,015  $ 2,246,885  $ 1,867,828  Net cash used in investing activities (2,157,682) (3,672,114) (3,211,192) Net cash (used in) provided by financing activities (282,598) 1,413,673  902,332  Net change in cash $ (15,265) $ (11,556) $ (441,032) Adjusted EBITDA attributable to Matador Resources Company shareholders(1) $ 2,294,551  $ 2,298,777  $ 1,849,547  __________________ (1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below. Net Cash Provided by Operating Activities Net cash provided by operating activities increased by $178.1 million to $2.43 billion for the year ended December 31, 2025 from $2.25 billion for the year ended December 31, 2024. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased by $15.0 million to $2.25 billion for the year ended December 31, 2025 from $2.23 billion for the year ended December 31, 2024. This increase was primarily attributable to a 21% increase in total oil equivalent production during 2025, as compared to 2024, partially offset by lower realized oil and natural gas prices. Changes in our operating assets and liabilities between the periods resulted in a $163.1 million increase in net cash provided by operating activities for the year ended December 31, 2025, as compared to the year ended December 31, 2024. Our operating cash flows are sensitive to a number of variables that are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “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.” Net Cash Used in Investing Activities Net cash used in investing activities decreased by $1.51 billion to $2.16 billion for the year ended December 31, 2025 from $3.67 billion for the year ended December 31, 2024. This decrease in net cash used in investing activities between the periods was primarily due to (i) a $1.83 billion decrease in expenditures related to the Ameredev Acquisition that occurred in September 2024, (ii) a $115.3 million decrease in expenditures related to the acquisition of oil and natural gas properties and (iii) a $10.1 million increase in cash provided by proceeds from the sale of assets. The decreases in cash used in investing activities between the periods were partially offset by (i) a $319.4 million increase in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin, (ii) a $110.3 million decrease in proceeds from the sale of an equity method investment in the parent company of Piñon Midstream, LLC, and (iii) a $13.9 million increase in midstream capital expenditures. Net Cash (Used in) Provided by Financing Activities Net cash used in financing activities increased by $1.70 billion to $282.6 million for the year ended December 31, 2025, from net cash provided by financing activities of $1.41 billion for the year ended December 31, 2024. This increase in net cash used in financing activities between the periods was primarily due to (i) a $1.27 billion decrease in net proceeds from debt and equity offerings in the prior period, (ii) a $293.0 million increase in net repayments under the Credit Agreement, (iii) a $44.7 million increase in net distributions related to San Mateo, (iv) a $58.2 million increase in dividends paid and (v) a $55.8 million increase in repurchases of common stock. These increases in net cash used in financing activities were partially offset by (i) a $175.0 million increase in net borrowings under the San Mateo Credit Facility and (ii) a $31.0 million decrease in costs to amend credit facilities. See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2028 Notes, the 2032 Notes and the 2033 Notes. 79 Table of Contents Non-GAAP Financial Measures We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively. Year Ended December 31, 2025 2024 2023 (In thousands) Unaudited Adjusted EBITDA Reconciliation to Net Income: Net income attributable to Matador Resources Company shareholders $ 759,221  $ 885,322  $ 846,074  Net income attributable to non-controlling interest in subsidiaries 101,548  86,021  64,285  Net income 860,769  971,343  910,359  Interest expense 208,520  171,687  121,520  Total income tax provision 172,675  292,364  186,026  Depletion, depreciation and amortization 1,195,358  974,300  716,688  Accretion of asset retirement obligations 7,846  6,027  3,943  Unrealized (gain) loss on derivatives (18,084) (13,299) 1,261  Non-cash stock-based compensation expense 18,327  14,982  13,661  Net loss on impairment 589  —  202  (Income) expense related to contingent consideration and other (7,338) 5,420  (6,038) Consolidated Adjusted EBITDA 2,438,662  2,422,824  1,947,622  Adjusted EBITDA attributable to non-controlling interest in subsidiaries (144,111) (124,047) (98,075) Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,294,551  $ 2,298,777  $ 1,849,547  Year Ended December 31, 2025 2024 2023 (In thousands) Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 2,425,015  $ 2,246,885  $ 1,867,828  Net change in operating assets and liabilities (176,189) (13,080) (50,027) Interest expense, net of non-cash portion 193,756  155,154  114,473  Current income tax provision 7,088  27,059  13,922  Net loss on asset sales and impairment 589  —  —  Other non-cash and non-recurring (income) expense (11,597) 6,806  1,426  Adjusted EBITDA attributable to non-controlling interest in subsidiaries (144,111) (124,047) (98,075) Adjusted EBITDA attributable to Matador Resources Company shareholders $ 2,294,551  $ 2,298,777  $ 1,849,547  80 Table of Contents For the year ended December 31, 2025, we reported net income attributable to Matador shareholders of $759.2 million, as compared to $885.3 million for the year ended December 31, 2024. This decrease primarily resulted from (i) a $221.1 million increase in depletion, depreciation and amortization expenses, (ii) a $90.7 million increase in lease operating expenses, (iii) a $40.7 million increase in midstream operating expenses, (iv) a $36.8 million increase in interest expense, (v) an $8.2 million increase in transportation and processing expenses and (vi) lower realized oil and natural gas prices for the year ended December 31, 2025, as compared to the year ended December 31, 2024. These expense increases were partially offset by (i) increased oil and natural gas production and (ii) a $119.7 million decrease in the income tax provision for the year ended December 31, 2025, as compared to the year ended December 31, 2024. Off-Balance Sheet Arrangements  From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2025, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. Obligations and Commitments We had the following material contractual obligations and commitments at December 31, 2025. Payments Due by Period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years (In thousands) Contractual Obligations: Borrowings, including letters of credit(1) $ 1,350,244  $ —  $ —  $ 1,350,244  $ —  Senior unsecured notes(2) 2,150,000  —  500,000  —  1,650,000  Office leases 101,390  3,542  12,339  13,091  72,418  Non-operated drilling commitments(3) 79,038  79,038  —  —  —  Drilling rig contracts(4) 22,622  22,622  —  —  —  Asset retirement obligations(5) 150,372  6,309  6,785  1,720  135,558  Transportation, gathering, processing and disposal agreements with non-affiliates(6) 2,320,113  144,567  582,695  452,288  1,140,563  Transportation, gathering, processing and disposal agreements with San Mateo(7) 743,907  56,812  279,080  206,590  201,425  Midstream contracts 11,638  11,638  —  —  —  Total contractual cash obligations $ 6,929,324  $ 324,528  $ 1,380,899  $ 2,023,933  $ 3,199,964  __________________ (1)The amounts included in the table above represent principal maturities only. At December 31, 2025, we had $398.0 million in borrowings outstanding under the Credit Agreement and approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The outstanding borrowings under the Credit Agreement mature on March 22, 2029. At December 31, 2025, San Mateo had $883.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. Assuming the amounts outstanding and interest rates of 5.63% and 5.72%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2025, the interest expense for such facilities is expected to be approximately $22.4 million and $50.5 million, respectively, each year until maturity. (2)The amounts included in the table above represent principal maturities only. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2025 is expected to be approximately $34.4 million each year until maturity. Interest expense on the $900.0 million of outstanding 2032 Notes as of December 31, 2025 is expected to be approximately $58.5 million each year until maturity. Interest expense on the $750.0 million of outstanding 2033 Notes as of December 31, 2025 is expected to be approximately $46.9 million each year until maturity. (3)At December 31, 2025, we had outstanding commitments to participate in the drilling and completion of various non-operated wells. (4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. (5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2025. 81 Table of Contents (6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments, including contracts related to firm transportation on Energy Transfer’s Hugh Brinson Pipeline. If we do not meet the minimum volume commitments under these agreements, we would be required to pay deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments. (7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. In connection with the Pronto Transaction, we dedicated to San Mateo our current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements with San Mateo whereby San Mateo will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments. General Outlook and Trends Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. For example, the current administration and Congress have altered, and may continue to alter, our current regulatory framework and may impact our business and the oil and natural gas industry generally. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, ongoing military conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt, the payment of cash dividends, if any, the repurchase of our common stock, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL 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 these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs 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. 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.” For the year ended December 31, 2025, oil prices averaged $64.73 per Bbl, as compared to $75.76 per Bbl in 2024, ranging from a high of $80.04 per Bbl in mid-January to a low of $55.27 per Bbl in mid-December, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $64.99 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2025, as compared to $75.89 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2024. At February 24, 2026, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2025, closing at $65.63 per Bbl, but was lower compared to $70.70 per Bbl on February 24, 2025. For the year ended December 31, 2025, natural gas prices averaged $3.62 per MMBtu, as compared to $2.40 per MMBtu in 2024, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2025, natural gas prices ranged from a low of $2.70 per MMBtu in late August to a high of $5.29 per MMBtu in early December. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2025 as compared to 2024, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2025. We realized a weighted average natural gas price of $2.08 per Mcf ($2.20 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2025, as compared to $2.38 per Mcf ($2.47 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2024. At February 24, 2026, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from year-end 2025, closing at $2.92 per MMBtu, and was lower as compared to $3.99 per MMBtu at February 24, 2025. The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the 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. At December 31, 2025, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas. 82 Table of Contents The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 24, 2026, this oil price differential was approximately +$0.66 per Bbl. At February 24, 2026, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2026. Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($2.96) per MMBtu for the year ended December 31, 2025. Between December 31, 2025 and February 24, 2026, this natural gas price differential remained wide at approximately ($5.11) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. For example, in the fourth quarter of 2025, the Company entered into an agreement to transport natural gas on Energy Transfer’s Hugh Brinson Pipeline. The Hugh Brinson Pipeline is expected to provide direct access from the Waha hub in the Permian Basin to Henry Hub markets along the Louisiana Gulf Coast. Further, approximately 4% of our reported natural gas production for the year ended December 31, 2025 was attributable to the Haynesville shale play, which is not exposed to Waha pricing. In addition, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During the year ended December 31, 2025, we realized gains on our natural gas basis differential derivative contracts of approximately $21.7 million resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We have at times, including in the fourth quarter of 2025, experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024 and 2025, we may again temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results. We have at times experienced inflation in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices increase, we may 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, tariffs and trade restrictions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Financial Condition—Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. 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” and “Risk Factors—Risks Related to Laws and Regulations—Changes in U.S. foreign trade policies, including the imposition of additional tariffs and other trade barriers, and efforts to withdraw from or materially modify international trade agreements, may materially and adversely affect our business, operations and financial condition.” 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 proposed or 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. For more information about the Company’s regulatory matters, see “Business—Regulation” and “Risk Factors—Risks Related to Laws and Regulations”. Certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social 83 Table of Contents and environmental considerations. See “Risk Factors—Risks Related to our Common Stock—Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price.” Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—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”. We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2025. Oil and Natural Gas Properties We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are depleted using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the depletable base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the depletable base. Exploratory dry holes are included in the depletable base immediately upon the determination that the well is not productive. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. 84 Table of Contents Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, development expenditures, operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.” Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. Income Taxes We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. 85 Table of Contents Purchase Accounting Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023 and the Ameredev Acquisition in 2024. In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition and the Ameredev Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage. Recent Accounting Pronouncements See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements.