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Item 2 — Management's Discussion and Analysis
Matador Resources Company · 10-Q · Q2 FY2026 · Period ended Jun 30, 2026
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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, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition (each as defined below); the operating results of and availability of any potential distributions from our joint ventures; weather conditions, environmental conditions and natural disasters; our ability to consummate the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to the satisfaction or waiver of the conditions to closing the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to obtaining the requisite regulatory approvals for the Paloma Acquisition and the Ridge Runner Acquisition; disruption from our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition; 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;
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•our financial strategy, budget, projections and operating results;
•the supply and demand of oil, natural gas and NGLs;
•oil, natural gas and NGL prices, including our realized prices thereof;
•the timing and amount of future production of oil and natural gas;
•the availability of drilling and production equipment;
•the availability of oil storage capacity;
•the availability 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, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, 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 Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, including the anticipated timing and benefits thereof;
•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.
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Second Quarter Highlights
For the three months ended June 30, 2026, our total oil equivalent production was 19.6 million BOE, and our average daily oil equivalent production was 215,631 BOE per day, of which 126,106 Bbl per day, or 58%, was oil and 537.1 MMcf per day, or 42%, was natural gas. Our average daily oil production of 126,106 Bbl per day for the three months ended June 30, 2026 increased 3% year-over-year from 122,875 Bbl per day for the three months ended June 30, 2025. Our average daily natural gas production of 537.1 MMcf per day for the three months ended June 30, 2026 increased 4% year-over-year from 516.8 MMcf per day for the three months ended June 30, 2025. The Delaware Basin contributed 100% of our daily oil production and 97% of our daily natural gas production in each of the second quarters of 2026 and 2025.
For the second quarter of 2026, we reported net income attributable to Matador shareholders of $390.7 million, or $3.15 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $150.2 million, or $1.21 per diluted common share, for the second quarter of 2025. For the second quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $781.0 million, as compared to Adjusted EBITDA of $594.2 million during the second quarter of 2025.
For the six months ended June 30, 2026, we reported net income attributable to Matador shareholders of $354.8 million, or $2.86 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $390.3 million, or $3.12 per diluted common share, for the six months ended June 30, 2025. For the six months ended June 30, 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $1.36 billion, as compared to Adjusted EBITDA of $1.24 billion for the six months ended June 30, 2025.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net 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 and six months ended June 30, 2026, see “—Results of Operations” below.
Acquisitions
In May 2026, we completed the acquisition of 5,154 net undeveloped acres in the core of the Delaware Basin in Southeast New Mexico for approximately $1.16 billion as part of the Bureau of Land Management Oil and Gas Lease Sale (the “BLM Acquisition”). The acquired acreage complements our existing acreage position, and as a result, includes proved undeveloped reserves in addition to unproved and unevaluated reserves.
Subsequent to the end of the reporting period, on July 22, 2026, we entered into a definitive agreement to acquire Paloma Permian, LLC (“Paloma”) from a portfolio company of EnCap Investments L.P. (“EnCap”), including certain proved undeveloped acreage and oil and natural gas producing properties located in Eddy and Lea Counties, New Mexico (the “Paloma Acquisition”). The consideration for the Paloma Acquisition will consist of a cash payment of $1.275 billion, subject to customary closing adjustments, including for working capital and for title and environmental defects. The consummation of the Paloma Acquisition is subject to the satisfaction or waiver of a number of customary closing conditions and is expected to close in the fourth quarter of 2026, with an effective date of June 1, 2026.
On July 22, 2026, we entered into a definitive agreement to acquire from subsidiaries of Ridge Runner Resources II, LLC, a portfolio company of EnCap, primarily undeveloped acreage and certain oil and natural gas producing properties located in the Woodford play in Lea County, New Mexico and Winkler and Ward Counties, Texas (the “Ridge Runner Acquisition”). The consummation of the Ridge Runner Acquisition is subject to the satisfaction or waiver of a number of customary closing conditions and is expected to close in the fourth quarter of 2026, with an effective date of June 1, 2026.
On July 31, 2026, San Mateo completed the acquisition of the operating subsidiaries of Cardinal Midstream Partners, LLC (“Cardinal”), a portfolio company of EnCap Flatrock Midstream, for total cash consideration of $752.0 million, subject to certain customary post-closing purchase price adjustments (the “Cardinal Acquisition”).
For discussion of the funding for these acquisitions, see “—Liquidity and Capital Resources” in Part I, Item 2 of this Quarterly Report.
2026 Capital Expenditure Budget
On August 5, 2026, we increased our estimated drilling, completing and equipping (“D/C/E”) capital expenditures for 2026 to a range of $1.48 to $1.56 billion from a range of $1.35 to $1.44 billion, which includes our expected D/C/E capital expenditures on acreage acquired in the BLM Acquisition and expected to be acquired in the Paloma Acquisition and Ridge Runner Acquisition. On August 5, 2026, we also adjusted our estimated midstream capital expenditures for 2026 to a range of $145.0 to $165.0 million from a range of $100.0 to $110.0 million, which includes 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.
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Critical Accounting Policies
There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.
Recent Accounting Pronouncements
There are no recent accounting pronouncements that are expected to have a material impact on our financial statements.
Results of Operations
Revenues
The following table summarizes our unaudited revenues and production data for the periods indicated:
Three Months Ended June 30,
2026 2025 $ Change % Change
Operating Data
Revenues (in thousands)(1)
Oil $ 1,126,425 $ 719,380 $ 407,045 57 %
Natural gas (38,841) 96,394 (135,235) (140) %
Total oil and natural gas revenues 1,087,584 815,774 271,810 33 %
Third-party midstream services revenues 44,593 42,007 2,586 6 %
Sales of purchased natural gas 41,246 67,897 (26,651) (39) %
Realized (loss) gain on derivatives (72,488) 6,947 (79,435) (1,143) %
Unrealized gain (loss) on derivatives 85,457 (37,313) 122,770 (329) %
Total revenues $ 1,186,392 $ 895,312 $ 291,080 33 %
Net Production Volumes(1)
Oil (MBbl) 11,476 11,182 294 3 %
Natural gas (Bcf) 48.9 47.0 1.9 4 %
Total oil equivalent (MBOE)(2) 19,622 19,020 602 3 %
Average daily production (BOE/d)(2) 215,631 209,013 6,618 3 %
Average Sales Prices
Oil, without realized derivatives (per Bbl) $ 98.16 $ 64.34 $ 33.82 53 %
Oil, with realized derivatives (per Bbl) $ 83.19 $ 64.34 $ 18.85 29 %
Natural gas, without realized derivatives (per Mcf) $ (0.79) $ 2.05 $ (2.84) (139) %
Natural gas, with realized derivatives (per Mcf) $ 1.24 $ 2.20 $ (0.96) (44) %
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(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.
Three Months Ended June 30, 2026 as Compared to Three Months Ended June 30, 2025
Oil and natural gas revenues. The increase in oil revenues resulted from the 53% increase in the weighted average oil price realized and the 3% increase in oil production. The decrease in natural gas revenues primarily resulted from the 139% decrease in the weighted average natural gas price realized and the 4% increase in natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”
Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $3.0 million increase in our third-party natural gas gathering and processing revenues, which was partially offset by a $0.7 million decrease in our third-party water disposal revenues.
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Sales of purchased natural gas. The decrease in sales of purchased natural gas was primarily the result of a 49% decrease in natural gas price realized, which was partially offset by a 20% increase in natural gas volumes sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties 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 interim unaudited condensed consolidated statements of operations.
Realized (loss) gain on derivatives. Our realized loss on derivatives was $72.5 million for the three months ended June 30, 2026, as compared to a realized gain of $6.9 million for the three months ended June 30, 2025. For the three months ended June 30, 2026, we recorded a net loss of $171.8 million related to our oil costless collars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $99.3 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the three months ended June 30, 2025, we recorded a net gain of $6.9 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $14.97 per Bbl produced during the three months ended June 30, 2026, as compared to no realized gains or losses from oil derivatives during the three months ended June 30, 2025. We realized an average gain on our natural gas derivatives of approximately $2.03 per Mcf produced during the three months ended June 30, 2026, as compared to an average gain of approximately $0.15 per Mcf produced during the three months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.
Unrealized gain (loss) on derivatives. During the three months ended June 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $136.0 million from a net liability of $221.4 million at March 31, 2026, resulting in an unrealized gain on derivatives of $85.5 million for the three months ended June 30, 2026. During the three months ended June 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net liability of $16.3 million from a net asset of $21.0 million at March 31, 2025, resulting in an unrealized loss on derivatives of $37.3 million for the three months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.
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Expenses
The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:
Three Months Ended June 30,
(In thousands, except expenses per BOE) 2026 2025 $ Change % Change
Expenses
Lease operating $ 106,948 $ 105,230 $ 1,718 2 %
Transportation and processing 18,934 16,451 2,483 15 %
Midstream operating 60,536 44,457 16,079 36 %
Purchased natural gas (38,912) 35,944 (74,856) (208) %
Depletion, depreciation and amortization 315,144 302,602 12,542 4 %
Taxes other than income 102,794 68,010 34,784 51 %
Accretion of asset retirement obligations 2,352 1,767 585 33 %
General and administrative 41,274 32,187 9,087 28 %
Total expenses 609,070 606,648 2,422 — %
Operating income 577,322 288,664 288,658 100 %
Other income (expense)
Interest expense (60,819) (53,345) (7,474) 14 %
Other income 3,986 3,502 484 14 %
Total other expense (56,833) (49,843) (6,990) 14 %
Income before income taxes 520,489 238,821 281,668 118 %
Income tax provision (benefit)
Current 226 23,089 (22,863) (99) %
Deferred 106,611 33,373 73,238 219 %
Total income tax provision 106,837 56,462 50,375 89 %
Net income 413,652 182,359 231,293 127 %
Net income attributable to non-controlling interest in subsidiaries (23,000) (32,134) 9,134 (28) %
Net income attributable to Matador Resources Company shareholders $ 390,652 $ 150,225 $ 240,427 160 %
Expenses per BOE
Lease operating $ 5.45 $ 5.53 $ (0.08) (1) %
Transportation and processing $ 0.96 $ 0.86 $ 0.10 12 %
Midstream operating $ 3.09 $ 2.34 $ 0.75 32 %
Depletion, depreciation and amortization $ 16.06 $ 15.91 $ 0.15 1 %
Taxes other than income $ 5.24 $ 3.58 $ 1.66 46 %
General and administrative $ 2.10 $ 1.69 $ 0.41 24 %
Three Months Ended June 30, 2026 as Compared to Three Months Ended June 30, 2025
Lease operating. The increase in lease operating expense was primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest).
Transportation and processing. The increase in transportation and processing expenses is primarily due to the 3% increase in our total oil equivalent production and a change in the mix of revenue contracts between the periods.
Midstream operating. The increase in midstream operating expense was primarily attributable to a $9.3 million increase in pipeline operation expenses as a result of increased inlet connections and a $6.0 million increase in plant processing expenses as a result of increased gas gathering and processing volumes.
Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 910% in average Waha pricing resulting in negative prices during the current period, which was partially offset by a 55% increase in volumes purchased due to the weaker market pricing.
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Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 3% increase in our total oil equivalent production and the addition of $282.2 million of proved reserves to the full cost pool as a result of the BLM Acquisition.
Taxes other than income. The increase in taxes other than income is primarily due to the increase in oil revenues, partially offset by the decrease in natural gas revenues.
General and administrative. The increase in general and administrative expense was largely attributable to a $4.2 million increase in employee compensation costs as a result of increased headcount and a $1.4 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, general and administrative expense increased due to a $1.3 million increase in director and officer insurance and approximately $1.1 million in transaction costs associated with the Cardinal Acquisition.
Interest expense. The increase in interest expense for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was primarily due to a $164.5 million increase in average debt outstanding under the Credit Agreement, a $198.0 million increase in average debt outstanding under the San Mateo Credit Facility, and a $250.0 million increase in the weighted average of senior notes outstanding between the periods, partially offset by lower interest rates.
Income tax provision. The decrease in the current income tax provision and the increase in the deferred income tax provision were primarily due to the OBBBA. See Note 8, Income Taxes, of our Annual Report for further details of the provisions of the OBBBA that most significantly affect our income taxes. Additionally, the increase in the total income tax provision resulted from higher income before income taxes. Our effective income tax rate was 21% for the three months ended June 30, 2026. Our effective tax rate was 27% for the three months ended June 30, 2025, which differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico.
Revenues
The following table summarizes our unaudited revenues and production data for the periods indicated:
Six Months Ended June 30,
2026 2025 $ Change % Change
Operating Data
Revenues (in thousands)(1)
Oil $ 1,914,774 $ 1,468,701 $ 446,073 30 %
Natural gas (8,459) 256,991 (265,450) (103) %
Total oil and natural gas revenues 1,906,315 1,725,692 180,623 10 %
Third-party midstream services revenues 86,684 75,506 11,178 15 %
Sales of purchased natural gas 122,028 130,653 (8,625) (7) %
Realized (loss) gain on derivatives (86,981) 9,661 (96,642) (1,000) %
Unrealized loss on derivatives (170,017) (32,242) (137,775) 427 %
Total revenues $ 1,858,029 $ 1,909,270 $ (51,241) (3) %
Net Production Volumes(1)
Oil (MBbl) 22,301 21,535 766 4 %
Natural gas (Bcf) 96.0 92.2 3.8 4 %
Total oil equivalent (MBOE)(2) 38,305 36,897 1,408 4 %
Average daily production (BOE/d)(2) 211,635 203,851 7,784 4 %
Average Sales Prices
Oil, without realized derivatives (per Bbl) $ 85.86 $ 68.20 17.66 26 %
Oil, with realized derivatives (per Bbl) $ 75.83 $ 68.20 $ 7.63 11 %
Natural gas, without realized derivatives (per Mcf) $ (0.09) $ 2.79 $ (2.88) (103) %
Natural gas, with realized derivatives (per Mcf) $ 1.33 $ 2.89 $ (1.56) (54) %
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(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.
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Six Months Ended June 30, 2026 as Compared to Six Months Ended June 30, 2025
Oil and natural gas revenues. The increase in oil revenues resulted from the 26% increase in the weighted average oil price realized and the 4% increase in our oil production. The decrease in natural gas revenues primarily resulted from the 103% decrease in the weighted average natural gas price realized and the 4% increase in our natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”
Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $12.0 million increase in our third-party natural gas gathering and processing revenues, which was partially offset by a $1.3 million decrease in our third-party water disposal revenues.
Sales of purchased natural gas. The decrease in sales of purchased natural gas was primarily the result of a 37% decrease in natural gas price realized, which was partially offset by a 48% increase in natural gas volumes sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties 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 interim unaudited condensed consolidated statements of operations.
Realized loss on derivatives. Our realized loss on derivatives was $87.0 million for the six months ended June 30, 2026, as compared to a realized gain of $9.7 million for the six months ended June 30, 2025. For the six months ended June 30, 2026, we recorded a net loss of $223.6 million related to our oil costless collars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $136.7 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the six months ended June 30, 2025, we recorded a net gain of $9.7 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $10.03 per Bbl produced during the three months ended June 30, 2026, as compared to no realized gains or losses from oil derivatives during the six months ended June 30, 2025. We realized an average gain on our natural gas derivatives of approximately $1.42 per Mcf produced during the six months ended June 30, 2026, as compared to an average gain of approximately $0.10 per Mcf produced during the six months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.
Unrealized loss on derivatives. During the six months ended June 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $136.0 million from a net asset of $34.1 million at December 31, 2025, resulting in an unrealized loss on derivatives of $170.0 million for the six months ended June 30, 2026. During the six months ended June 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net liability of $16.3 million from a net asset of $16.0 million at December 31, 2024, resulting in an unrealized loss on derivatives of $32.2 million for the six months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.
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Expenses
The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:
Six Months Ended June 30,
(In thousands, except expenses per BOE) 2026 2025 $ Change % Change
Expenses
Lease operating $ 214,474 $ 209,641 $ 4,833 2 %
Transportation and processing 33,776 36,512 (2,736) (7) %
Midstream operating 115,763 96,260 19,503 20 %
Purchased natural gas 3,423 90,077 (86,654) (96) %
Depletion, depreciation and amortization 607,848 584,493 23,355 4 %
Taxes other than income 173,685 145,059 28,626 20 %
Accretion of asset retirement obligations 4,620 3,494 1,126 32 %
General and administrative 80,297 65,919 14,378 22 %
Total expenses 1,233,886 1,231,455 2,431 — %
Operating income 624,143 677,815 (53,672) (8) %
Other income (expense)
Interest expense (112,344) (102,834) (9,510) 9 %
Loss on debt extinguishment (15,587) — (15,587) 100 %
Loss on asset sales (578) — (578) 100 %
Other income 8,353 9,008 (655) (7) %
Total other expense (120,156) (93,826) (26,330) 28 %
Income before income taxes 503,987 583,989 (80,002) (14) %
Income tax provision (benefit)
Current 226 46,070 (45,844) (100) %
Deferred 105,927 93,313 12,614 14 %
Total income tax provision 106,153 139,383 (33,230) (24) %
Net income 397,834 444,606 (46,772) (11) %
Net income attributable to non-controlling interest in subsidiaries (43,054) (54,296) 11,242 (21) %
Net income attributable to Matador Resources Company shareholders $ 354,780 $ 390,310 $ (35,530) (9) %
Expenses per BOE
Lease operating $ 5.60 $ 5.68 $ (0.08) (1) %
Transportation and processing $ 0.88 $ 0.99 $ (0.11) (11) %
Midstream operating $ 3.02 $ 2.61 $ 0.41 16 %
Depletion, depreciation and amortization $ 15.87 $ 15.84 $ 0.03 — %
Taxes other than income $ 4.53 $ 3.93 $ 0.60 15 %
General and administrative $ 2.10 $ 1.79 $ 0.31 17 %
Six Months Ended June 30, 2026 as Compared to Six Months Ended June 30, 2025
Lease operating. The increase in lease operating expense was primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest).
Transportation and processing. The decrease in transportation and processing expenses is primarily due to additional allowable deductions identified in the state of New Mexico and a change in the mix of revenue contracts between the periods.
Midstream operating. The increase in midstream operating expense was primarily attributable to an $11.2 million increase in plant processing expenses as a result of increased gas gathering and processing volumes and a $9.5 million increase in pipeline operation expenses as a result of increased inlet connections.
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Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 520% in average Waha pricing, partially offset by a 30% increase in volumes purchased due to the weaker market pricing.
Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 4% increase in our total oil equivalent production and the addition of $282.2 million of proved reserves to the full cost pool as a result of the BLM Acquisition.
Taxes other than income. The increase in taxes other than income was primarily due to the increase in oil revenues, partially offset by the decrease in natural gas revenues.
General and administrative. The increase in general and administrative expense was largely attributable to a $14.2 million increase in employee compensation costs, as a result of increased headcount and an $8.2 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, the increase in general and administrative expense was due to a $1.3 million increase in director and officer insurance and approximately $1.1 million in transaction costs associated with the Cardinal Acquisition. These increases were partially offset by a $4.5 million increase in capitalized general and administrative expenses.
Interest expense. The increase in interest expense for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to a $175.8 million increase in average debt outstanding under the Credit Agreement, a $200.5 million increase in average debt outstanding under the San Mateo Credit Facility, and a $158.9 million increase in the weighted average of senior notes outstanding between the periods, partially offset by lower interest rates.
Loss on debt extinguishment. In connection with the 2028 Notes Tender Offer and 2028 Notes Redemption, both of which as defined in “—Liquidity and Capital Resources” below, we incurred a loss on debt extinguishment of $15.6 million, including a $9.7 million cash prepayment premium and a $5.9 million write-off of remaining unamortized deferred issuance costs and discounts.
Income tax provision. The decrease in the current income tax provision and the increase in the deferred income tax provisions were primarily due to the OBBBA. See Note 8, Income Taxes, of our Annual Report for further details of the provisions of the OBBBA that most significantly affect our income taxes. Additionally, the decrease in the total income tax provision resulted from lower income before income taxes. Our effective income tax rate of 23% for the six months ended June 30, 2026 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico, partially offset by the impact of permanent differences between book and tax income recognized discretely in the current period. Our effective tax rate of 26% for the six months ended June 30, 2025 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico.
Liquidity and Capital Resources
Our primary use of capital has been, and we expect will continue to be during the remainder of 2026 and for the foreseeable future, 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 or its affiliates. If capital expenditures were to exceed these sources of cash during the remainder of 2026, we expect to fund any such excess capital expenditures, including for significant acquisitions, through borrowings under our secured revolving credit facility (the “Credit Agreement”) or San Mateo’s secured revolving credit facility (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.
The table below reflects our sources and availability of liquidity at June 30, 2026. See Note 5, Debt, for further details.
(In thousands) Total Balance Availability
Cash $ 26,318 $ 26,318
Credit Agreement $ 939,000 $ 1,757,156 (1)
San Mateo Credit Facility $ 911,000 $ 173,600 (2)
6.500% senior notes due 2032 (the “2032 Notes”) $ 900,000 (3)
6.250% senior notes due 2033 (the “2033 Notes”) $ 750,000 (3)
6.000% senior notes due 2034 (the “2034 Notes”) $ 750,000 (3)
(1)Reduced by approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.
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(2)Reduced by approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.
(3)We believe we have access to additional financing and refinancing, if needed, although we can make no assurances as to the form or terms of such financing.
In March 2026, we completed the repurchase of an aggregate principal amount of $419.8 million of the $500.0 million of outstanding senior notes due 2028 (the “2028 Notes”) as part of our cash tender offer announced on February 26, 2026 (the “2028 Notes Tender Offer”). Additionally, in March 2026, we irrevocably deposited funds with the trustee to redeem the remaining aggregate principal amount of $80.2 million of 2028 Notes outstanding on April 15, 2026 (the “2028 Notes Redemption”), and as a result of such deposit, to satisfy and discharge our obligations under the indenture governing the 2028 Notes.
Additionally, in March 2026, we completed the sale of $750.0 million in aggregate principal amount of our 6.00% senior notes due 2034 (the “2034 Notes”). We used the net proceeds from the sale of the 2034 Notes (the “2034 Notes Offering”) of $737.9 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund the 2028 Notes Tender Offer and 2028 Notes Redemption and for general corporate purposes.
In June 2026, in connection with the regularly scheduled May 1 redetermination, the borrowing base of the Credit Agreement was reaffirmed at $3.25 billion. Additionally, we elected to, and the lenders agreed to, increase the borrowing commitments from $2.25 billion to $2.75 billion.
See Note 5, Debt, for further details of these debt transactions.
As further described in the Annual Report, we maintain a share repurchase program (the “Share Repurchase Program”) authorizing the repurchase of up to $400.0 million of common stock. During the three and six months ended June 30, 2026, we repurchased 225,000 and 242,702 shares of common stock, respectively, under the Share Repurchase Program at a weighted average price of $49.59 and $48.88 per common share, respectively, for a total cost of $11.2 million and $11.9 million, respectively.
Matador’s Board of Directors (the “Board”) declared and paid quarterly cash dividends of $0.375 per share of common stock in each of the first and second quarters of 2026. On July 22, 2026, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on September 8, 2026 to shareholders of record as of August 10, 2026.
The BLM Acquisition was funded through cash on hand and borrowings under our existing reserves-based Credit Agreement. The Paloma Acquisition and the Ridge Runner Acquisition are expected to be funded through cash on hand and borrowings under our existing reserves-based Credit Agreement, for which the elected commitment level was increased to $2.75 billion as discussed above.
In connection with the Cardinal Acquisition, on July 31, 2026, San Mateo entered into a $650.0 million term loan due July 30, 2027 under the San Mateo Credit Facility. The purchase price was additionally funded through capital contributions by Matador and Five Point to San Mateo of $51.0 million and $49.0 million, respectively, and cash on hand.
Since June 30, 2026, our borrowings increased $243.0 million under the Credit Agreement, and at August 5, 2026, we had $1.18 billion in borrowings outstanding. Since June 30, 2026, San Mateo’s borrowings increased $25.0 million under the San Mateo Credit Facility, and at August 5, 2026, San Mateo had $936.0 million in borrowings outstanding.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 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. On August 5, 2026, we increased our estimated drilling, completing and equipping (“D/C/E”) capital expenditures for 2026 to a range of $1.48 to $1.56 billion from a range of $1.35 to $1.44 billion, which includes our expected D/C/E capital expenditures on acreage acquired in the BLM Acquisition and expected to be acquired in the Paloma Acquisition and the Ridge Runner Acquisition. On August 5, 2026, we also adjusted our estimated midstream capital expenditures for 2026 to a range of $145.0 to $165.0 million from a range of $100.0 to $110.0 million, which includes 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 Delaware Basin operated drilling program for the remainder of 2026 is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.
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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 the remainder of 2026 is expected to come from producing wells and development activities on currently proved properties 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 further 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 8, Derivative Financial Instruments, in this Quarterly Report for a summary of our open derivative financial instruments.
Cash Flows
Our unaudited cash flows for the six months ended June 30, 2026 and 2025 are presented below:
Six Months Ended June 30,
(In thousands) 2026 2025 $ Change % Change
Net cash provided by operating activities $ 1,407,674 $ 1,228,906 $ 178,768 15 %
Net cash used in investing activities (2,057,908) (1,006,674) (1,051,234) 104 %
Net cash provided by (used in) financing activities 661,672 (230,188) 891,860 (387) %
Net change in cash and restricted cash $ 11,438 $ (7,956) $ 19,394 (244) %
Adjusted EBITDA attributable to Matador Resources Company shareholders(1) $ 1,358,179 $ 1,238,468 $ 119,711 10 %
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(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
Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $151.8 million to $1.33 billion for the six months ended June 30, 2026 from $1.18 billion for the six months ended June 30, 2025. This increase was primarily attributable to higher realized oil prices and increased oil production for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025, partially offset by lower realized natural gas prices and higher natural gas production. Changes in our operating assets and liabilities between the periods resulted in a $27.0 million increase in net cash provided by operating activities for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025.
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Net Cash Used in Investing Activities
The increase in net cash used in investing activities between the periods was primarily due to (i) a $1.10 billion increase in expenditures related to the acquisition of oil and natural gas properties, primarily the BLM Acquisition, (ii) a $37.6 million cash deposit related to the Cardinal Acquisition and (iii) a $21.4 million decrease in cash provided by proceeds from the sale of assets, partially offset by a $121.1 million decrease in midstream capital expenditures.
Net Cash Provided by (Used in) Financing Activities
The decrease in net cash used in financing activities between the periods was primarily due to (i) a $746.5 million increase in net borrowings under the Credit Agreement, (ii) $737.1 million of net proceeds received from the 2034 Notes Offering during the period, (iii) a $32.1 million decrease in repurchases of common stock, (iv) $23.7 million of net proceeds from a sale-leaseback financing obligation and (v) a $5.9 million increase in performance incentives received from Five Point, partially offset by (i) $509.7 million used to repurchase the principal amount of the 2028 Notes, (ii) a $135.0 million decrease in net borrowings under the San Mateo Credit Agreement and (iii) a $15.1 million increase in dividends paid.
See Note 5, Debt, in this Quarterly Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2032 Notes, the 2033 Notes and the 2034 Notes.
Non-GAAP Financial Measures
We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, non-cash stock-based compensation expense, loss on debt extinguishment, net gain or loss on asset sales and impairments and certain other non-cash items. Adjusted EBITDA is not a measure of net income 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 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 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.
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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.
Three Months Ended June 30, Six Months Ended June 30,
(In thousands) 2026 2025 2026 2025
Unaudited Adjusted EBITDA Reconciliation to Net Income
Net income attributable to Matador Resources Company shareholders $ 390,652 $ 150,225 $ 354,780 $ 390,310
Net income attributable to non-controlling interest in subsidiaries 23,000 32,134 43,054 54,296
Net income 413,652 182,359 397,834 444,606
Interest expense 60,819 53,345 112,344 102,834
Total income tax provision 106,837 56,462 106,153 139,383
Depletion, depreciation and amortization 315,144 302,602 607,848 584,493
Accretion of asset retirement obligations 2,352 1,767 4,620 3,494
Unrealized (gain) loss on derivatives (85,457) 37,313 170,017 32,242
Non-cash stock-based compensation expense 6,099 4,572 10,617 8,460
Loss on debt extinguishment — — 15,587 —
Loss on asset sales — — 578 —
Other non-recurring (income) expense (573) (2,300) 4,225 (5,586)
Consolidated Adjusted EBITDA 818,873 636,120 1,429,823 1,309,926
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (37,864) (41,875) (71,644) (71,458)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 781,009 $ 594,245 $ 1,358,179 $ 1,238,468
Three Months Ended June 30, Six Months Ended June 30,
(In thousands) 2026 2025 2026 2025
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities
Net cash provided by operating activities $ 937,128 $ 501,027 $ 1,407,674 $ 1,228,906
Net change in operating assets and liabilities (174,549) 65,540 (80,855) (53,845)
Interest expense, net of non-cash portion 57,289 49,672 105,276 95,498
Current income tax provision 226 23,089 226 46,070
Other non-cash and non-recurring income (1,221) (3,208) (2,498) (6,703)
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (37,864) (41,875) (71,644) (71,458)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 781,009 $ 594,245 $ 1,358,179 $ 1,238,468
Net income attributable to Matador shareholders increased $240.4 million for the three months ended June 30, 2026, as compared to the three months ended June 30, 2025. The increase in net income attributable to Matador shareholders primarily resulted from (i) higher realized oil prices, (ii) increased oil production, (iii) a $48.2 million increase in net sales of purchased natural gas and (iv) a $43.3 million decrease in net loss on realized and unrealized derivatives. These increases were partially offset by (i) a $50.4 million increase in the income tax provision, (ii) a $34.8 million increase in taxes other than income, (iii) a $16.1 million increase in midstream operating expenses, (iv) a $12.5 million increase in depletion, depreciation and amortization and (v) a $9.1 million increase in general and administrative expenses. See “—Results of Operations” for the three months ended June 30, 2026 as compared to the three months ended June 30, 2025 above for further discussion and analysis of these individual changes within net income.
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Net income attributable to Matador shareholders decreased $35.5 million for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025. The decrease in net income attributable to Matador shareholders primarily resulted from (i) a $234.4 million increase in net loss on realized and unrealized derivatives, (ii) a $28.6 million increase in taxes other than income, (iii) a $23.4 million increase in depletion, depreciation and amortization, (iv) a $19.5 million increase in midstream operating expenses, (v) a $15.6 million loss on debt extinguishment and (vi) a $9.5 million increase in interest expense. These decreases were partially offset by (i) higher realized oil prices, (ii) increased oil production, (iii) a $78.0 million increase in net sales of purchased natural gas and (iv) a $33.2 million decrease in the income tax provision. See “—Results of Operations” for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025, above for further discussion and analysis of these individual changes within net income.
Adjusted EBITDA, a non-GAAP financial measure, increased $186.8 million for the three months ended June 30, 2026 compared to the three months ended June 30, 2025. This increase was primarily attributable to (i) higher realized oil prices, (ii) increased oil production and (iii) a $48.2 million increase in net sales of purchased natural gas. These increases were partially offset by (i) lower realized natural gas prices and increased natural gas production, (ii) a $79.4 million decrease in realized gain on derivatives, (iii) a $34.8 million increase in taxes other than income, (iv) a $16.1 million increase in midstream operating expenses and (v) a $9.1 million increase in general and administrative expenses.
Adjusted EBITDA, a non-GAAP financial measure, increased $119.7 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025. This increase is primarily attributable to (i) higher realized oil prices, (ii) increased oil production and (iii) a $78.0 million increase in net sales of purchased natural gas. These increases were partially offset by (i) lower realized natural gas prices and increased natural gas production, (ii) a $96.6 million decrease in realized gain on derivatives, (iii) a $28.6 million increase in taxes other than income, (iv) a $19.5 million increase in midstream operating expenses and (v) a $14.4 million increase in general and administrative expenses.
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 June 30, 2026, 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, we have 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 10, Commitments and Contingencies, in this Quarterly Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.
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Obligations and Commitments
We had the following material contractual obligations and commitments at June 30, 2026:
Payments Due by Period
(In thousands) Total Less Than 1 Year 1 - 3 Years 3 - 5 Years More Than 5 Years
Contractual Obligations
Borrowings, including letters of credit(1) $ 1,919,244 $ — $ 992,844 $ 926,400 $ —
Senior unsecured notes(2) 2,400,000 — — — 2,400,000
Office leases 103,231 5,784 12,837 13,651 70,959
Non-operated drilling commitments(3) 47,706 47,706 — — —
Drilling rig contracts(4) 25,097 25,097 — — —
Asset retirement obligations(5) 159,074 3,883 9,892 1,889 143,410
Transportation, gathering, processing and disposal agreements with non-affiliates(6) 2,368,938 242,364 571,410 439,503 1,115,661
Transportation, gathering, processing and disposal agreements with San Mateo(7) 646,231 28,640 222,170 206,590 188,831
Midstream contracts(8) 85,797 71,631 14,166 — —
Seismic data contracts 15,750 15,750 — — —
Total contractual cash obligations $ 7,771,068 $ 440,855 $ 1,823,319 $ 1,588,033 $ 3,918,861
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(1)The amounts included in the table above represent principal maturities only. At June 30, 2026, we had $939.0 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 June 30, 2026, San Mateo had $911.0 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 5.65% and 5.88%, respectively, for the Credit Agreement and the San Mateo Credit Facility at June 30, 2026, the interest expense for such facilities is expected to be approximately $53.7 million and $54.3 million, respectively, each year until maturity.
(2)The amounts included in the table above represent principal maturities only. Interest expense on the $900.0 million of outstanding 2032 Notes as of June 30, 2026 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 June 30, 2026 is expected to be approximately $46.9 million each year until maturity. Interest expense on the $750.0 million of outstanding 2034 Notes as of June 30, 2026 is expected to be approximately $45.0 million each year until maturity.
(3)At June 30, 2026, 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.
(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at June 30, 2026.
(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 certain deficiency fees. See Note 10, Commitments and Contingencies, in this Quarterly 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 southern portion of the Arrowhead asset area (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. We also dedicated to San Mateo certain of our current and 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 10, Commitments and Contingencies, in this Quarterly Report for more information about these contractual commitments.
(8)At June 30, 2026, we had outstanding commitments for capital expenditures to be utilized in San Mateo’s operations.
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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 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 ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, geopolitical tensions involving Iran (including the potential for stricter U.S. sanctions on Iranian oil exports, regional conflicts and potential disruptions to shipping routes in the Strait of Hormuz), the actions of Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries, 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, and the repurchase of 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” in the Annual Report.
Oil prices were higher in the second quarter of 2026, as compared to the second quarter of 2025. For the three months ended June 30, 2026, oil prices averaged $92.70 per Bbl, ranging from a high of $112.95 per Bbl in early April to a low of $69.23 per Bbl in late June, based upon the West Texas Intermediate (“WTI”) oil futures contract price for the earliest delivery date. Oil prices averaged $63.68 per Bbl for the three months ended June 30, 2025. We realized a weighted average oil price of $98.16 per Bbl ($83.19 with realized losses from oil derivatives) for our oil production for the three months ended June 30, 2026, as compared to $64.34 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the three months ended June 30, 2025. Oil prices have remained volatile since June 30, 2026. At August 5, 2026, the WTI oil futures contract for the earliest delivery date had decreased from the average price for the second quarter of 2026 of $92.70 per Bbl, settling at $75.22 per Bbl.
Natural gas prices were lower in the second quarter of 2026, as compared to the second quarter of 2025. For the three months ended June 30, 2026, natural gas prices averaged $2.94 per MMBtu, ranging from a low of $2.52 per MMBtu in late April to a high of $3.34 per MMBtu in late June, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices averaged $3.51 per MMBtu for the three months ended June 30, 2025. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). We realized a weighted average natural gas price of $(0.79) per Mcf ($1.24 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended June 30, 2026, as compared to $2.05 per Mcf ($2.20 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended June 30, 2025. Certain volumes of our natural gas production are sold at prices established at the beginning of each month by the various markets where we sell our natural gas production, and certain volumes of our natural gas production are sold at daily market prices. At August 5, 2026, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from the average price for the second quarter of 2026 of $2.94 per MMBtu, to $2.69 per MMBtu.
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 June 30, 2026, 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.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At August 5, 2026, this oil price differential was positive at approximately +$0.35 per Bbl. At August 5, 2026, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2026.
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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 as a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($6.03) per MMBtu for the six months ended June 30, 2026. Between June 30, 2026 and August 5, 2026, this natural gas price differential narrowed to approximately ($0.82) 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. During 2023 and 2024, we typically realized a narrower differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 3% of our reported natural gas production for the six months ended June 30, 2026 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.
We secured 500,000 MMBtu per day of firm natural gas transportation on Energy Transfer’s new Hugh Brinson pipeline, which began flowing natural gas during the second quarter of 2026 and which Energy Transfer expects to be fully in-service by the end of the third quarter of 2026. The Hugh Brinson pipeline will provide Matador access to Henry Hub markets along the Louisiana Gulf Coast and to other opportunities such as liquefied natural gas (LNG) plants and export terminals along this pipeline route that have historically experienced more favorable pricing to the Waha hub.
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 first six months of 2026, we recorded a net loss of $223.6 million related to our oil costless collars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $136.7 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts.
We have at times, including in 2025 and 2026, 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 2025 and 2026, 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, 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.
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” in the Annual Report.
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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.
Regulatory Matters
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” in the Annual Report.