Matador Resources Company
10/24/2025 | Press release | Distributed by Public on 10/24/2025 14:19
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
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, 2024 (the "Annual Report") filed with the Securities and Exchange Commission (the "SEC") on February 25, 2025, 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.govand 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, (iii) references to "San Mateo" refer to San Mateo Midstream, LLC, collectively with its subsidiaries and (iv) references to the "Ameredev Acquisition" refer to the acquisition of Ameredev Stateline II, LLC from affiliates of EnCap Investments L.P., including (a) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (b) an approximate 19% stake in the parent company of Piñon Midstream, LLC, which was completed by a subsidiary of the Company on September 18, 2024. 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. Such statements are generally identifiable by the terminology used such as "anticipate," "believe," "continue," "could," "estimate," "expect," "forecasted," "hypothetical," "intend," "may," "might," "plan," "potential," "predict," "project," "should," "would" or other similar words, although not all forward-looking statements contain such identifying words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include those described in the "Risk Factors" section of the Annual Report, as well as the following factors, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids ("NGL") prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business's oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs; 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 and environmental conditions; disruption from our acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions; 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;
•the availability of drilling and production equipment;
•the availability of oil storage capacity;
•the availability of oil field labor;
•the amount, nature and timing of capital expenditures, including future exploration and development costs;
•the availability and terms of capital;
•our drilling of wells;
•our ability to negotiate and consummate acquisition and divestiture opportunities;
•the integration of acquisitions 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 Inflation Reduction Act of 2022;
•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.
Third Quarter Highlights
For the three months ended September 30, 2025, our total oil equivalent production was 19.2 million BOE, and our average daily oil equivalent production was 209,184 BOE per day, of which 119,556 Bbl per day, or 57%, was oil and 537.8 MMcf per day, or 43%, was natural gas. Our average daily oil production of 119,556 Bbl per day for the three months ended September 30, 2025 increased 19% year-over-year from 100,315 Bbl per day for the three months ended September 30, 2024. Our average daily natural gas production of 537.8 MMcf per day for the three months ended September 30, 2025 increased 26% year-over-year from 427.0 MMcf per day for the three months ended September 30, 2024.
The Delaware Basin contributed 100% of our daily oil production and approximately 94% of our daily natural gas production in the third quarter of 2025, as compared to approximately 99% of our daily oil production and approximately 95% of our daily natural gas production in the third quarter of 2024.
For the third quarter of 2025, we reported net income attributable to Matador shareholders of $176.4 million, or $1.42 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $248.3 million, or $1.99 per diluted common share, for the third quarter of 2024. For the third quarter of 2025, our Adjusted EBITDA, a non-GAAP financial measure, was $566.5 million, as compared to Adjusted EBITDA of $574.5 million during the third quarter of 2024.
For the nine months ended September 30, 2025, we reported net income attributable to Matador shareholders of $566.7 million, or $4.54 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $670.8 million, or $5.44 per diluted common share, for the nine months ended September 30, 2024. For the nine months ended September 30, 2025, our Adjusted EBITDA, a non-GAAP financial measure, was $1.80 billion, as compared to Adjusted EBITDA of $1.66 billion during the nine months ended September 30, 2024.
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 nine months ended September 30, 2025, see "-Results of Operations" below.
2025 Capital Expenditure Budget
On October 21, 2025, we increased our estimated drilling, completing and equipping ("D/C/E") capital expenditures for 2025 to a range of $1.47 to $1.55 billion from a range of $1.18 to $1.37 billion. On October 21, 2025, we also adjusted our estimated midstream capital expenditures for 2025 to a range of $155.0 to $175.0 million from a range of $120.0 to $180.0 million, which includes our proportionate share of San Mateo's estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. The midstream capital expenditure budget includes 51% of the costs associated with San Mateo's construction of an additional natural gas processing plant with a designed inlet capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, to expand its Marlan cryogenic natural gas processing plant (the "Marlan Processing Plant Expansion"), which came online in the second quarter of 2025.
Capital Resources Update
Matador's Board of Directors (the "Board") declared quarterly cash dividends of $0.3125 per share of common stock in each of the first, second and third quarters of 2025. On October 15, 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.375 per share of common stock for future dividend payments and also declared a quarterly cash dividend of $0.375 per share of common stock payable on December 5, 2025 to shareholders of record as of November 10, 2025.
On April 16, 2025, the Board authorized a share repurchase program (the "Share Repurchase Program") of up to $400.0 million of common stock. During the three and nine months ended September 30, 2025, the Company repurchased 137,161 and 1,232,828 shares of common stock under the Share Repurchase Program at a weighted average price of $47.06 and $41.11 per common share for a total cost of $6.5 million and $50.7 million, respectively.
At September 30, 2025, we had (i) $285.0 million in borrowings outstanding under our secured revolving credit facility (the "Credit Agreement"), (ii) approximately $54.0 million in outstanding letters of credit issued pursuant to the Credit Agreement, (iii) $500.0 million of outstanding 6.875% senior notes due 2028 (the "2028 Notes"), (iv) $900.0 million of outstanding 6.50% senior notes due 2032 (the "2032 Notes") and (v) $750.0 million of outstanding 6.25% senior notes due 2033 (the "2033 Notes").
In June 2025, San Mateo and certain of its lenders modified San Mateo's secured revolving credit facility (the "San Mateo Credit Facility") to (i) increase the lender commitments from $800.0 million to $850.0 million and (ii) add one new bank to San Mateo's lending group. At September 30, 2025, San Mateo had $815.0 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. Since September 30, 2025, San Mateo repaid $55.0 million of borrowings under the San Mateo Credit Facility, and at October 21, 2025, San Mateo had $760.0 million in borrowings outstanding under the San Mateo Credit Facility.
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
See Note 2 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a description of recent accounting pronouncements.
Results of Operations
Revenues
The following table summarizes our unaudited revenues and production data for the periods indicated:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Operating Data | |||||||||||||||||||||||
|
Revenues (in thousands)(1)
|
|||||||||||||||||||||||
| Oil | $ | 713,947 | $ | 698,391 | $ | 2,182,648 | $ | 2,002,454 | |||||||||||||||
| Natural gas | 96,294 | 71,764 | 353,285 | 247,520 | |||||||||||||||||||
| Total oil and natural gas revenues | 810,241 | 770,155 | 2,535,933 | 2,249,974 | |||||||||||||||||||
| Third-party midstream services revenues | 43,833 | 38,316 | 119,339 | 103,324 | |||||||||||||||||||
| Sales of purchased natural gas | 61,043 | 51,666 | 191,696 | 147,377 | |||||||||||||||||||
| Realized gain on derivatives | 3,946 | 4,528 | 13,607 | 8,573 | |||||||||||||||||||
| Unrealized gain (loss) on derivatives | 19,952 | 35,118 | (12,290) | 25,364 | |||||||||||||||||||
| Total revenues | $ | 939,015 | $ | 899,783 | $ | 2,848,285 | $ | 2,534,612 | |||||||||||||||
|
Net Production Volumes(1)
|
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|
Oil (MBbl)(2)
|
10,999 | 9,229 | 32,534 | 25,633 | |||||||||||||||||||
|
Natural gas (Bcf)(3)
|
49.5 | 39.3 | 141.7 | 110.2 | |||||||||||||||||||
|
Total oil equivalent (MBOE)(4)
|
19,245 | 15,776 | 56,142 | 43,992 | |||||||||||||||||||
|
Average daily production (BOE/d)(5)
|
209,184 | 171,480 | 205,648 | 160,555 | |||||||||||||||||||
| Average Sales Prices | |||||||||||||||||||||||
| Oil, without realized derivatives (per Bbl) | $ | 64.91 | $ | 75.67 | $ | 67.09 | $ | 78.12 | |||||||||||||||
| Oil, with realized derivatives (per Bbl) | $ | 64.91 | $ | 75.67 | $ | 67.09 | $ | 78.12 | |||||||||||||||
| Natural gas, without realized derivatives (per Mcf) | $ | 1.95 | $ | 1.83 | $ | 2.49 | $ | 2.25 | |||||||||||||||
| Natural gas, with realized derivatives (per Mcf) | $ | 2.03 | $ | 1.94 | $ | 2.59 | $ | 2.32 | |||||||||||||||
_________________
(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)One thousand Bbl of oil.
(3)One billion cubic feet of natural gas.
(4)One thousand Bbl of oil equivalent, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)Barrels of oil equivalent per day, estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Three Months Ended September 30, 2025 as Compared to Three Months Ended September 30, 2024
Oil and natural gas revenues. Our oil and natural gas revenues increased $40.1 million, or 5%, to $810.2 million for the three months ended September 30, 2025, as compared to $770.2 million for the three months ended September 30, 2024. Our oil revenues increased $15.6 million, or 2%, to $713.9 million for the three months ended September 30, 2025, as compared to $698.4 million for the three months ended September 30, 2024. The increase in oil revenues resulted from a 19% increase in our oil production to 11.0 million Bbl for the three months ended September 30, 2025, as compared to 9.2 million Bbl for the three months ended September 30, 2024, which was partially offset by a 14% decrease in the weighted average oil price realized for the three months ended September 30, 2025 to $64.91 per Bbl, as compared to $75.67 per Bbl for the three months ended September 30, 2024. Our natural gas revenues increased $24.5 million, or 34%, to $96.3 million for the three months ended September 30, 2025, as compared to $71.8 million for the three months ended September 30, 2024. The increase in natural gas revenues primarily resulted from a 26% increase in our natural gas production to 49.5 Bcf for the three months ended September 30, 2025, as compared to 39.3 Bcf for the three months ended September 30, 2024 and a 7% increase in the weighted average natural gas price realized for the three months ended September 30, 2025 to $1.95 per Mcf, as compared to a weighted average natural gas price of $1.83 per Mcf for the three months ended September 30, 2024.
Third-party midstream services revenues. Our third-party midstream services revenues increased $5.5 million, or 14%, to $43.8 million for the three months ended September 30, 2025, as compared to $38.3 million for the three months ended September 30, 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 $25.9 million for the three months ended September 30, 2025, as compared to $18.8 million for the three months ended September 30, 2024, and (ii) an increase in our oil transportation revenues to $6.4 million for the three months ended September 30, 2025, as compared to $4.1 million for the three months ended September 30, 2024, which were partially offset by a decrease in our third-party water disposal revenues to $11.5 million for the three months ended September 30, 2025, as compared to $15.4 million for the three months ended September 30, 2024.
Sales of purchased natural gas.Our sales of purchased natural gas increased $9.4 million, or 18%, to $61.0 million for the three months ended September 30, 2025, as compared to $51.7 million for the three months ended September 30, 2024. This increase was primarily the result of a 15% increase in natural gas volumes sold and a 3% increase in natural gas price realized in those sales. 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 income.
Realized gain on derivatives.Our realized gain on derivatives was $3.9 million for the three months ended September 30, 2025, as compared to a realized gain of $4.5 million for the three months ended September 30, 2024. We realized a net gain of $3.9 million and $4.5 million related to our natural gas basis differential swap contracts for the three months ended September 30, 2025 and 2024, respectively, 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 gain on our natural gas derivatives of approximately $0.08 per Mcf produced during the three months ended September 30, 2025, as compared to an average gain of approximately $0.11 per Mcf produced during the three months ended September 30, 2024.
Unrealized gain on derivatives.During the three months ended September 30, 2025, the aggregate net fair value of our open oil and natural gas costless collars and natural gas basis differential swap contracts changed to a net asset of $3.7 million from a net liability of $16.3 million at June 30, 2025, resulting in an unrealized gain on derivatives of $20.0 million for the three months ended September 30, 2025. During the three months ended September 30, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed to a net asset of $28.0 million from a net liability of $7.1 million at June 30, 2024, resulting in an unrealized gain on derivatives of $35.1 million for the three months ended September 30, 2024.
Nine Months Ended September 30, 2025 as Compared to Nine Months Ended September 30, 2024
Oil and natural gas revenues. Our oil and natural gas revenues increased $286.0 million, or 13%, to $2.54 billion for the nine months ended September 30, 2025, as compared to $2.25 billion for the nine months ended September 30, 2024. Our oil revenues increased $180.2 million, or 9%, to $2.18 billion for the nine months ended September 30, 2025, as compared to $2.00 billion for the nine months ended September 30, 2024. This increase in oil revenues resulted from a 27% increase in our oil production to 32.5 million Bbl for the nine months ended September 30, 2025, as compared to 25.6 million Bbl for the nine months ended September 30, 2024, which was partially offset by a 14% decrease in the weighted average oil price realized for the nine months ended September 30, 2025 to $67.09 per Bbl, as compared to $78.12 per Bbl for the nine months ended September 30, 2024. Our natural gas revenues increased by $105.8 million, or 43%, to $353.3 million for the nine months ended September 30, 2025, as compared to $247.5 million for the nine months ended September 30, 2024. The increase in natural gas revenues resulted from a 29% increase in our natural gas production to 141.7 Bcf for the nine months ended September 30, 2025, as compared to 110.2 Bcf for the nine months ended September 30, 2024, and an 11% increase in the weighted average natural gas price realized for the nine months ended September 30, 2025 to $2.49 per Mcf, as compared to a weighted average natural gas price of $2.25 per Mcf for the nine months ended September 30, 2024.
Third-party midstream services revenues. Our third-party midstream services revenues increased $16.0 million, or 15%, to $119.3 million for the nine months ended September 30, 2025, as compared to $103.3 million for the nine months ended September 30, 2024. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering and processing revenues to $64.8 million for the nine months ended September 30, 2025, as compared to $49.8 million for the nine months ended September 30, 2024, and (ii) an increase in our oil transportation revenues to $17.7 million for the nine months ended September 30, 2025, as compared to $10.6 million for the nine months ended September 30, 2024, which were partially offset by a decrease in our third-party water disposal revenues to $36.8 million for the nine months ended September 30, 2025, as compared to $42.9 million for the nine months ended September 30, 2024.
Sales of purchased natural gas.Our sales of purchased natural gas increased $44.3 million, or 30%, to $191.7 million for the nine months ended September 30, 2025, as compared to $147.4 million for the nine months ended September 30, 2024. This increase was the result of a 24% increase in natural gas price realized and a 5% increase in natural gas volumes sold.
Realized gain on derivatives. Our realized gain on derivatives was $13.6 million for the nine months ended September 30, 2025, as compared to a realized gain of $8.6 million for the nine months ended September 30, 2024. We realized a net gain of $13.6 million and $8.6 million related to our natural gas basis differential swap contracts for the nine months ended September 30, 2025 and 2024, respectively, resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized an average gain on our natural gas derivatives of approximately $0.10 per Mcf produced during the nine months ended September 30, 2025, as compared to an average gain of approximately $0.07 per Mcf produced during the nine months ended September 30, 2024.
Unrealized gain (loss) on derivatives. During the nine months ended September 30, 2025, the aggregate net fair value of our open oil and natural gas costless collars and natural gas basis differential swap contracts changed to a net asset of $3.7 million from a net asset of $16.0 million at December 31, 2024, resulting in an unrealized loss on derivatives of $12.3 million for the nine months ended September 30, 2025. During the nine months ended September 30, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed to a net asset of $28.0 million from a net asset of $2.7 million at December 31, 2023, resulting in an unrealized gain on derivatives of $25.4 million for the nine months ended September 30, 2024.
Expenses
The following table summarizes our unaudited operating expenses and other income (expense) for the periods indicated:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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| (In thousands, except expenses per BOE) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Expenses | |||||||||||||||||||||||
| Production taxes, transportation and processing | $ | 83,078 | $ | 72,737 | $ | 259,706 | $ | 219,702 | |||||||||||||||
|
Lease operating
|
107,483 | 86,808 | 319,769 | 242,133 | |||||||||||||||||||
| Plant and other midstream services operating | 50,525 | 43,695 | 149,083 | 120,576 | |||||||||||||||||||
| Purchased natural gas | 47,658 | 31,222 | 137,735 | 105,894 | |||||||||||||||||||
| Depletion, depreciation and amortization | 305,354 | 242,821 | 889,847 | 681,066 | |||||||||||||||||||
| Accretion of asset retirement obligations | 2,148 | 1,657 | 5,642 | 4,259 | |||||||||||||||||||
| General and administrative | 36,790 | 28,787 | 102,709 | 86,353 | |||||||||||||||||||
| Total expenses | 633,036 | 507,727 | 1,864,491 | 1,459,983 | |||||||||||||||||||
| Operating income | 305,979 | 392,056 | 983,794 | 1,074,629 | |||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Interest expense | (50,641) | (36,169) | (153,475) | (111,717) | |||||||||||||||||||
| Net loss on asset sales and impairment | (589) | - | (589) | - | |||||||||||||||||||
| Other income | 5,003 | 2,111 | 14,011 | 567 | |||||||||||||||||||
| Total other expense | (46,227) | (34,058) | (140,053) | (111,150) | |||||||||||||||||||
| Income before income taxes | 259,752 | 357,998 | 843,741 | 963,479 | |||||||||||||||||||
| Income tax provision (benefit) | |||||||||||||||||||||||
| Current | (39,335) | (21,096) | 6,735 | 26,280 | |||||||||||||||||||
| Deferred | 98,463 | 106,417 | 191,776 | 203,805 | |||||||||||||||||||
| Total income tax provision | 59,128 | 85,321 | 198,511 | 230,085 | |||||||||||||||||||
| Net income | 200,624 | 272,677 | 645,230 | 733,394 | |||||||||||||||||||
| Net income attributable to non-controlling interest in subsidiaries | (24,260) | (24,386) | (78,556) | (62,605) | |||||||||||||||||||
| Net income attributable to Matador Resources Company shareholders | $ | 176,364 | $ | 248,291 | $ | 566,674 | $ | 670,789 | |||||||||||||||
| Expenses per BOE | |||||||||||||||||||||||
| Production taxes, transportation and processing | $ | 4.32 | $ | 4.61 | $ | 4.63 | $ | 4.99 | |||||||||||||||
| Lease operating | $ | 5.58 | $ | 5.50 | $ | 5.70 | $ | 5.50 | |||||||||||||||
| Plant and other midstream services operating | $ | 2.63 | $ | 2.77 | $ | 2.66 | $ | 2.74 | |||||||||||||||
| Depletion, depreciation and amortization | $ | 15.87 | $ | 15.39 | $ | 15.85 | $ | 15.48 | |||||||||||||||
| General and administrative | $ | 1.91 | $ | 1.82 | $ | 1.83 | $ | 1.96 | |||||||||||||||
Three Months Ended September 30, 2025 as Compared to Three Months Ended September 30, 2024
Production taxes, transportation and processing.Our production taxes, transportation and processing expenses increased $10.3 million, or 14%, to $83.1 million for the three months ended September 30, 2025, as compared to $72.7 million for the three months ended September 30, 2024. The increase was primarily attributable to a $7.9 million increase in transportation and processing expenses to $20.5 million for the three months ended September 30, 2025, as compared to $12.6 million for the three months ended September 30, 2024, and a $2.4 million increase in production taxes to $62.6 million for the three months ended September 30, 2025, as compared to $60.2 million for the three months ended September 30, 2024. The increase in transportation and processing expenses is primarily due to a 22% increase in our total oil equivalent production and a change in the mix of revenue contracts between the periods. The increase in production taxes is primarily due to the increase in oil and natural gas revenues between the two periods. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 6% to $4.32 per BOE for the three months ended September 30, 2025, as compared to $4.61 per BOE for the three months ended September 30, 2024. This decrease per BOE was primarily attributable to a 14% decrease in realized oil prices and a 22% increase in our total oil equivalent production between the two periods.
Lease operating.Our lease operating expenses increased $20.7 million, or 24%, to $107.5 million for the three months ended September 30, 2025, as compared to $86.8 million for the three months ended September 30, 2024. Our lease operating expenses on a unit-of-production basis increased 1% to $5.58 per BOE for the three months ended September 30, 2025, as compared to $5.50 per BOE for the three months ended September 30, 2024. These increases were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and other operators (where we own a working interest) for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $6.8 million, or 16%, to $50.5 million for the three months ended September 30, 2025, as compared to $43.7 million for the three months ended September 30, 2024. This increase was primarily attributable to increased throughput volumes from Matador's wholly-owned midstream assets, which resulted in increased expenses associated with our expanded pipeline operations of $24.2 million for the three months ended September 30, 2025, as compared to $16.5 million for the three months ended September 30, 2024, which was partially offset by decreased expenses associated with our commercial produced water disposal operations of $14.8 million for the three months ended September 30, 2025, as compared to $16.7 million for the three months ended September 30, 2024.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $62.5 million, or 26%, to $305.4 million for the three months ended September 30, 2025, as compared to $242.8 million for the three months ended September 30, 2024, primarily as a result of a 22% increase in our total oil equivalent production for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 3% to $15.87 per BOE for the three months ended September 30, 2025, as compared to $15.39 per BOE for the three months ended September 30, 2024.
General and administrative. Our general and administrative expenses increased $8.0 million, or 28%, to $36.8 million for the three months ended September 30, 2025, as compared to $28.8 million for the three months ended September 30, 2024. Our general and administrative expenses increased by 5% on a unit-of-production basis to $1.91 per BOE for the three months ended September 30, 2025, as compared to $1.82 per BOE for the three months ended September 30, 2024. These increases were primarily due to increased compensation expenses for our existing employees as well as the addition of new employees to support the continued growth in our land, geoscience, drilling, completion, production, midstream and administration functions.
Interest expense. For the three months ended September 30, 2025, we incurred total interest expense of $59.0 million. We capitalized $8.4 million of our interest expense on certain qualifying projects for the three months ended September 30, 2025 and expensed the remaining $50.6 million to operations. For the three months ended September 30, 2024, we incurred total interest expense of $44.4 million. We capitalized $8.2 million of our interest expense on certain qualifying projects for the three months ended September 30, 2024 and expensed the remaining $36.2 million to operations. The increase in interest expense for the three months ended September 30, 2025 compared to the three months ended September 30, 2024 was primarily due to a $709.2 million increase in the weighted average of senior notes outstanding between the periods in connection with the Ameredev Acquisition in September 2024.
Income tax provision (benefit). We recorded a current income tax benefit of $39.3 million and a deferred income tax provision of $98.5 million for the three months ended September 30, 2025. We recorded a current income tax benefit of $21.1 million and a deferred income tax provision of $106.4 million for the three months ended September 30, 2024. The increase in the current income tax benefit 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, and for which our current estimates are reflected in the unaudited condensed consolidated financial statements for the period ended September 30, 2025, include (i) a permanent extension of 100% bonus depreciation for certain capital expenditures, (ii) immediate deduction of domestic research or experimental expenditures, (iii) acceleration of unamortized domestic research or development expenditures and (iv) elimination of the deduction for depreciation, amortization and depletion from the definition of "adjusted taxable income" for the purpose of calculating interest expense deductions. The effective income tax rate and the total income tax provision for the three months ended September 30, 2025 were not materially impacted by the enactment of the OBBBA. Our effective income tax rates of 25% and 26% for the three months ended September 30, 2025 and 2024, respectively, differed from the U.S. federal statutory rate due primarily to state taxes in New Mexico.
Nine Months Ended September 30, 2025 as Compared to Nine Months Ended September 30, 2024
Production taxes, transportation and processing. Our production taxes, transportation and processing expenses increased $40.0 million, or 18%, to $259.7 million for the nine months ended September 30, 2025, as compared to $219.7 million for the nine months ended September 30, 2024. This increase was primarily attributable to a $24.9 million increase in production taxes to $199.2 million for the nine months ended September 30, 2025, as compared to $174.3 million for the nine months ended September 30, 2024, and a $15.1 million increase in transportation and processing expenses to $60.5 million for the nine months ended September 30, 2025, as compared to $45.4 million for the nine months ended September 30, 2024. This increase in production taxes, transportation and processing expenses is primarily due to the increase in oil and natural gas revenues between the two periods. On a unit-of-production basis, our production taxes, transportation and processing expenses decreased 7% to $4.63 per BOE for the nine months ended September 30, 2025, as compared to $4.99 per BOE for the nine months ended September 30, 2024. This decrease per BOE was primarily attributable to a 14% decrease in realized oil prices.
Lease operating expenses. Our lease operating expenses increased $77.6 million, or 32%, to $319.8 million for the nine months ended September 30, 2025, as compared to $242.1 million for the nine months ended September 30, 2024. Our lease operating expenses per unit of production increased 4% to $5.70 per BOE for the nine months ended September 30, 2025, as compared to $5.50 per BOE for the nine months ended September 30, 2024. These increases were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and operated by other operators (where we own a working interest) for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $28.5 million, or 24%, to $149.1 million for the nine months ended September 30, 2025, as compared to $120.6 million for the nine months ended September 30, 2024. This increase was primarily attributable to increased throughput volumes from Matador's wholly-owned midstream assets, which resulted in increased expenses associated with our expanded pipeline operations of $73.6 million for the nine months ended September 30, 2025, as compared to $46.1 million for the nine months ended September 30, 2024.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $208.8 million, or 31%, to $889.8 million for the nine months ended September 30, 2025, as compared to $681.1 million for the nine months ended September 30, 2024, primarily as a result of the approximate 28% increase in our total oil equivalent production for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 2% to $15.85 per BOE for the nine months ended September 30, 2025, as compared to $15.48 per BOE for the nine months ended September 30, 2024, primarily as a result of the Ameredev Acquisition.
General and administrative. Our general and administrative expenses increased $16.4 million, or 19%, to $102.7 million for the nine months ended September 30, 2025, as compared to $86.4 million for the nine months ended September 30, 2024, primarily as a result of 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 decreased by 7% on a unit-of-production basis to $1.83 per BOE for the nine months ended September 30, 2025, as compared to $1.96 per BOE for the nine months ended September 30, 2024, primarily as a result of the approximate 28% increase in our total oil equivalent production between the two periods.
Interest expense. For the nine months ended September 30, 2025, we incurred total interest expense of approximately $176.8 million. We capitalized approximately $23.3 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2025 and expensed the remaining $153.5 million to operations. For the nine months ended September 30, 2024, we incurred total interest expense of approximately $135.1 million. We capitalized approximately $23.4 million of our interest expense on certain qualifying projects for the nine months ended September 30, 2024 and expensed the remaining $111.7 million to operations. The increase in interest expense for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024 was primarily due to an $804.5 million increase in the weighted average of senior notes outstanding between the periods in connection with the Ameredev Acquisition in September 2024.
Income tax provision. We recorded a current income tax provision of $6.7 million and a deferred income tax provision of $191.8 million for the nine months ended September 30, 2025. We recorded a current income tax provision of $26.3 million and a deferred income tax provision of $203.8 million for the nine months ended September 30, 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, and for which our current estimates are reflected in the unaudited condensed consolidated financial statements for the period ended September 30, 2025, include (i) a permanent extension of 100% bonus
depreciation for certain capital expenditures, (ii) immediate deduction of domestic research or experimental expenditures, (iii) acceleration of unamortized domestic research or development expenditures and (iv) elimination of the deduction for depreciation, amortization and depletion from the definition of "adjusted taxable income" for the purpose of calculating interest expense deductions. The effective income tax rate and the total income tax provision for the nine months ended September 30, 2025 were not materially impacted by the enactment of the OBBBA. Our effective income tax rates of 26% for each of the nine months ended September 30, 2025 and 2024 differed from the U.S. federal statutory rate due primarily 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 2025 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 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point Infrastructure LLC (previously, Five Point Energy LLC) or its affiliates. If capital expenditures were to exceed our operating cash flows during the remainder of 2025, we expect to fund any such 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.
The Board declared quarterly cash dividends of $0.3125 per share of common stock in each of the first, second and third quarters of 2025. On October 15, 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.375 per share of common stock for future dividend payments and also declared a quarterly cash dividend of $0.375 per share of common stock payable on December 5, 2025 to shareholders of record as of November 10, 2025.
On April 16, 2025, the Board authorized the Share Repurchase Program 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 purchase 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 the Company, if any. Depending on market conditions and other factors, these repurchases may be commenced or suspended at any time or periodically without prior notice, and the Share Repurchase Program does not obligate the Company to acquire any amount of common stock. During the three and nine months ended September 30, 2025, the Company repurchased 137,161 and 1,232,828 shares of common stock under the Share Repurchase Program at a weighted average price of $47.06 and $41.11 per common share for a total cost of $6.5 million and $50.7 million, respectively.
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 $150.0 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.5 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at September 30, 2025.
At September 30, 2025, we had cash totaling $20.2 million and restricted cash totaling $76.2 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 September 30, 2025, we had (i) $500.0 million of outstanding 2028 Notes, (ii) $900.0 million of outstanding 2032 Notes, (iii) $750.0 million of outstanding 2033 Notes, (iv) $285.0 million in borrowings outstanding under the Credit Agreement and (v) approximately $54.0 million in outstanding letters of credit issued pursuant to the Credit Agreement.
In June 2025, San Mateo and certain of its lenders modified the San Mateo Credit Facility to (i) increase the lender commitments from $800.0 million to $850.0 million and (ii) add one new bank to San Mateo's lending group. At September 30, 2025, San Mateo had $815.0 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. Since September 30, 2025, San Mateo repaid $55.0 million of borrowings under the San Mateo Credit Facility, and at October 21, 2025, San Mateo had $760.0 million in borrowings outstanding under the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments to up to $1.05 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. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at September 30, 2025.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 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. On October 21, 2025, we increased our estimated D/C/E capital expenditures for 2025 to a range of $1.47 to $1.55 billion from a range of $1.18 to $1.37 billion. On October 21, 2025, we also adjusted our estimated midstream capital expenditures for 2025 to a range of $155.0 to $175.0 million from a range of $120.0 to $180.0 million, which includes our proportionate share of San Mateo's estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. The midstream capital expenditure budget includes 51% of the costs associated with the Marlan Processing Plant Expansion, which came online in the second quarter of 2025. Substantially all of these 2025 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 2025 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.
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 2025.
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 2025.
Our 2025 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 2025 is expected to come from producing wells and development activities on currently proved properties in the Delaware Basin and the Haynesville shale in Northwest Louisiana. 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 2025 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 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for a summary of our open derivative financial instruments.
Our unaudited cash flows for the nine months ended September 30, 2025 and 2024 are presented below:
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Nine Months Ended September 30, |
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| (In thousands) | 2025 | 2024 | |||||||||
| Net cash provided by operating activities | $ | 1,950,566 | $ | 1,671,926 | |||||||
| Net cash used in investing activities | (1,569,635) | (3,280,718) | |||||||||
| Net cash (used in) provided by financing activities | (379,286) | 1,579,517 | |||||||||
| Net change in cash and restricted cash | $ | 1,645 | $ | (29,275) | |||||||
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Adjusted EBITDA attributable to Matador Resources Company shareholders(1)
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$ | 1,804,983 | $ | 1,657,927 | |||||||
__________________
(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 $278.6 million to $1.95 billion for the nine months ended September 30, 2025 from $1.67 billion for the nine months ended September 30, 2024. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $154.9 million to $1.77 billion for the nine months ended September 30, 2025 from $1.62 billion for the nine months ended September 30, 2024. This increase was primarily attributable to increased oil and natural gas production and higher realized natural gas prices for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024, partially offset by lower realized oil prices. Changes in our operating assets and liabilities between the periods resulted in a $123.7 million increase in net cash provided by operating activities for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024.
Net Cash Used in Investing Activities
Net cash used in investing activities decreased $1.71 billion to $1.57 billion for the nine months ended September 30, 2025 from $3.28 billion for the nine months ended September 30, 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 $60.0 million decrease in expenditures related to the acquisition of oil and natural gas properties and (iii) a $21.5 million increase in cash provided by proceeds from the sale of assets. These decreases in cash used in investing activities between the periods were partially offset by a $187.6 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 and an $18.2 million increase in midstream capital expenditures.
Net Cash (Used in) Provided by Financing Activities
Net cash used in financing activities increased $1.96 billion to $379.3 million for the nine months ended September 30, 2025 from net cash provided by financing activities of $1.58 billion for the nine months ended September 30, 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 $765.5 million increase in net repayments under the Credit Agreement, (iii) a $56.5 million increase in net distributions related to San Mateo, (iv) a $50.7 million increase in cash used to repurchase common stock in the current period and (v) a $43.2 million increase in dividends paid. These increases in net cash used in financing activities were partially offset by (i) a $196.0 million increase in net borrowings under the San Mateo Credit Facility, and (ii) a $25.4 million decrease in costs to amend credit facilities.
See Note 5 to the interim unaudited condensed consolidated financial statements in this Quarterly 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.
Non-GAAP Financial Measures
We define 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 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.
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.
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Three Months Ended September 30, |
Nine Months Ended September 30, |
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| (In thousands) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Unaudited Adjusted EBITDA Reconciliation to Net Income | |||||||||||||||||||||||
| Net income attributable to Matador Resources Company shareholders | $ | 176,364 | $ | 248,291 | $ | 566,674 | $ | 670,789 | |||||||||||||||
| Net income attributable to non-controlling interest in subsidiaries | 24,260 | 24,386 | 78,556 | 62,605 | |||||||||||||||||||
| Net income | 200,624 | 272,677 | 645,230 | 733,394 | |||||||||||||||||||
| Interest expense | 50,641 | 36,169 | 153,475 | 111,717 | |||||||||||||||||||
| Total income tax provision | 59,128 | 85,321 | 198,511 | 230,085 | |||||||||||||||||||
| Depletion, depreciation and amortization | 305,354 | 242,821 | 889,847 | 681,066 | |||||||||||||||||||
| Accretion of asset retirement obligations | 2,148 | 1,657 | 5,642 | 4,259 | |||||||||||||||||||
| Unrealized (gain) loss on derivatives | (19,952) | (35,118) | 12,290 | (25,364) | |||||||||||||||||||
| Non-cash stock-based compensation expense | 6,181 | 4,279 | 14,641 | 10,091 | |||||||||||||||||||
| Net loss on asset sales and impairment | 589 | - | 589 | - | |||||||||||||||||||
| Non-recurring (income) expense | (1,866) | 243 | (7,452) | 3,176 | |||||||||||||||||||
| Consolidated Adjusted EBITDA | 602,847 | 608,049 | 1,912,773 | 1,748,424 | |||||||||||||||||||
| Adjusted EBITDA attributable to non-controlling interest in subsidiaries | (36,332) | (33,565) | (107,790) | (90,497) | |||||||||||||||||||
| Adjusted EBITDA attributable to Matador Resources Company shareholders | $ | 566,515 | $ | 574,484 | $ | 1,804,983 | $ | 1,657,927 | |||||||||||||||
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Three Months Ended September 30, |
Nine Months Ended September 30, |
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| (In thousands) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 721,660 | $ | 610,437 | $ | 1,950,566 | $ | 1,671,926 | |||||||||||||||
| Net change in operating assets and liabilities (working capital) | (123,282) | (15,367) | (177,127) | (53,416) | |||||||||||||||||||
| Interest expense, net of non-cash portion | 46,948 | 33,469 | 142,446 | 99,431 | |||||||||||||||||||
| Current income tax (benefit) provision | (39,335) | (21,096) | 6,735 | 26,280 | |||||||||||||||||||
| Net loss on asset sales and impairment | 589 | - | 589 | - | |||||||||||||||||||
| Other non-cash and non-recurring (income) expense | (3,733) | 606 | (10,436) | 4,203 | |||||||||||||||||||
| Adjusted EBITDA attributable to non-controlling interest in subsidiaries | (36,332) | (33,565) | (107,790) | (90,497) | |||||||||||||||||||
| Adjusted EBITDA attributable to Matador Resources Company shareholders | $ | 566,515 | $ | 574,484 | $ | 1,804,983 | $ | 1,657,927 | |||||||||||||||
For the three months ended September 30, 2025, net income attributable to Matador shareholders decreased $71.9 million to $176.4 million, as compared to $248.3 million for the three months ended September 30, 2024. The decrease in net income attributable to Matador shareholders primarily resulted from a $62.5 million increase in depletion, depreciation and amortization expenses, a $20.7 million increase in lease operating expenses, a $14.5 million increase in interest expense and lower realized oil prices for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024. These decreases were partially offset by a $26.2 million decrease in the income tax provision, which was primarily due to the enactment of the OBBBA, increased oil and natural gas production and higher realized natural gas prices for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024.
For the nine months ended September 30, 2025, net income attributable to Matador shareholders decreased $104.1 million to $566.7 million, as compared to net income attributable to Matador shareholders of $670.8 million for the nine months ended September 30, 2024. The decrease in net income attributable to Matador shareholders primarily resulted from a $208.8 million increase in depletion, depreciation and amortization expenses, a $77.6 million increase in lease operating expenses, a $40.0 million increase in production taxes, transportation and processing expenses, a $41.8 million increase in interest expense, a $37.7 million increase in unrealized loss on derivatives, a $28.5 million increase in plant and other midstream services operating expenses and lower realized oil prices for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024. These decreases were partially offset by increased oil and natural gas production, higher realized natural gas prices and a $31.6 million decrease in the income tax provision, which was primarily due to the enactment of the OBBBA, for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024.
Adjusted EBITDA, a non-GAAP financial measure, decreased $8.0 million to $566.5 million for the three months ended September 30, 2025, as compared to $574.5 million for the three months ended September 30, 2024. This decrease was primarily attributable to a $20.7 million increase in lease operating expenses, a $14.5 million increase in interest expense and lower realized oil prices for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024. These decreases were partially offset by increased oil and natural gas production and higher realized natural gas prices for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024.
Adjusted EBITDA, a non-GAAP financial measure, increased $147.1 million to $1.80 billion for the nine months ended September 30, 2025, as compared to $1.66 billion for the nine months ended September 30, 2024. This increase is primarily attributable to increased oil and natural gas production and higher realized natural gas prices, partially offset by lower realized oil prices, for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024. These increases were partially offset by a $77.6 million increase in lease operating expenses, a $40.0 million increase in production taxes, transportation and processing expenses, a $28.5 million increase in plant and other midstream services operating expenses and lower realized oil prices for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 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 September 30, 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, 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 to the interim unaudited condensed consolidated financial statements in this Quarterly 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 September 30, 2025:
| 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)
|
$ | 1,169,353 | $ | - | $ | - | $ | 1,169,353 | $ | - | |||||||||||||||||||
|
Senior unsecured notes(2)
|
2,150,000 | - | 500,000 | - | 1,650,000 | ||||||||||||||||||||||||
| Office leases | 90,327 | 2,243 | 10,861 | 11,522 | 65,701 | ||||||||||||||||||||||||
|
Non-operated drilling commitments(3)
|
83,810 | 83,810 | - | - | - | ||||||||||||||||||||||||
|
Drilling rig contracts(4)
|
32,419 | 32,419 | - | - | - | ||||||||||||||||||||||||
|
Asset retirement obligations(5)
|
145,219 | 6,099 | 6,935 | 1,695 | 130,490 | ||||||||||||||||||||||||
|
Transportation, gathering, processing and disposal agreements with non-affiliates(6)
|
697,787 | 131,948 | 274,836 | 132,379 | 158,624 | ||||||||||||||||||||||||
|
Transportation, gathering, processing and disposal agreements with San Mateo(7)
|
758,227 | 56,812 | 272,571 | 201,383 | 227,461 | ||||||||||||||||||||||||
|
Midstream contracts(8)
|
22,660 | 22,660 | - | - | - | ||||||||||||||||||||||||
| Total contractual cash obligations | $ | 5,149,802 | $ | 335,991 | $ | 1,065,203 | $ | 1,516,332 | $ | 2,232,276 | |||||||||||||||||||
__________________
(1)The amounts included in the table above represent principal maturities only. At September 30, 2025, we had $285.0 million in borrowings outstanding under the Credit Agreement and approximately $54.0 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 September 30, 2025, San Mateo had $815.0 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 6.02% and 6.27% respectively, for the Credit Agreement and the San Mateo Credit Facility at September 30, 2025, the interest expense for such facilities is expected to be approximately $17.4 million and $51.8 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 September 30, 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 September 30, 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 September 30, 2025 is expected to be approximately $46.9 million each year until maturity.
(3)At September 30, 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.
(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at September 30, 2025.
(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. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 10 to the interim unaudited condensed consolidated financial statements 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. In 2024, 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. See Note 10 to the interim unaudited condensed consolidated financial statements in this Quarterly Report for more information about these contractual commitments.
(8)At September 30, 2025, we had outstanding commitments to purchase compressors to be utilized in San Mateo's operations.
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, the actions of Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries ("OPEC+"), weather, pipeline capacity constraints, inventory storage levels, domestic or global health concerns, 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 lower in the third quarter of 2025, as compared to the third quarter of 2024. For the three months ended September 30, 2025, oil prices averaged $64.97 per Bbl, ranging from a high of $70.00 per Bbl in late July to a low of $61.87 per Bbl in early September, based upon the West Texas Intermediate ("WTI") oil futures contract price for the earliest delivery date. Oil prices averaged $75.27 per Bbl for the three months ended September 30, 2024. We realized a weighted average oil price of $64.91 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the three months ended September 30, 2025, as compared to $75.67 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the three months ended September 30, 2024. Oil prices have remained volatile since September 30, 2025. At October 21, 2025, the WTI oil futures contract for the earliest delivery date had decreased from the average price for the third quarter of 2025 of $64.97 per Bbl, settling at $57.82 per Bbl.
Natural gas prices were higher in the third quarter of 2025, as compared to the third quarter of 2024. For the three months ended September 30, 2025, natural gas prices averaged $3.07 per MMBtu, ranging from a high of $3.57 per MMBtu in mid-July to a low of $2.70 per MMBtu in late August, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices averaged $2.23 per MMBtu for the three months ended September 30, 2024. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were lower for the third quarter of 2025, as compared to the third quarter of 2024, which partially offset the higher natural gas prices between the two periods. We realized a weighted average natural gas price of $1.95 per Mcf ($2.03 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended September 30, 2025, as compared to $1.83 per Mcf ($1.94 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended September 30, 2024. 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 October 21, 2025, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from the average price for the third quarter of 2025 of $3.07 per MMBtu, to $3.47 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 September 30, 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.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At October 21, 2025, this oil price differential was positive at approximately +$0.67 per Bbl. At October 21, 2025, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2025.
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 ($2.40) per MMBtu for the nine months ended September 30, 2025. Between September 30, 2025 and October 21, 2025, this natural gas price differential remained wide at approximately ($2.51) 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 4% of our reported natural gas production for the nine months ended September 30, 2025 was attributable to the Haynesville shale play, which is not exposed to Waha pricing. In addition, as a two-stream reporter, 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 first nine months of 2025, we realized a net gain on our natural gas basis differential derivative contracts of approximately $13.6 million, resulting primarily from 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 October 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, 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.
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.
Tariffs and Trading Relationships
In April 2025, the United States government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits, including China. Since that time, the United States has expanded tariffs on key industrial inputs, including tariffs on steel and aluminum imports. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the United States government has at times announced, rescinded, modified and temporarily suspended multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of raw materials, equipment and other inputs critical to our operations, and may contribute to inflation in the markets in which we operate. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.
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. The following disclosures about our regulatory matters include updates to, and should be read in conjunction with, the above referenced sections of the Annual Report.
On March 6, 2024, the SEC adopted a new set of rules that would require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant's business, results of operations or financial condition, Scope 1 and Scope 2 greenhouse gas emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Litigation challenging the rules was filed by multiple parties in multiple jurisdictions, which was consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC announced that it was voluntarily delaying the implementation of the climate disclosure rules while the Eighth Circuit considered the litigation. On March 27, 2025, the SEC voted to end the defense of the rules in the litigation, and on July 23, 2025, it filed a status report requesting that the Eighth Circuit proceed with the case and issue an opinion on the challenges to the climate disclosure rules. On September 12, 2025, the Eighth Circuit denied the SEC's request to proceed with the case and indicated that the case would be held in abeyance until the SEC either renews its defense of the rules or revises the rules via notice-and-comment rulemaking.
On November 18, 2024, the Environmental Protection Agency (the "EPA") published final rules under authority of the Inflation Reduction Act of 2022 that would impose a waste emissions charge on large emitters of waste methane from the oil and gas sector. On March 14, 2025, President Trump signed a Joint Resolution of Disapproval under the Congressional Review Act to nullify and prohibit the waste emissions charge rules from taking effect. In line with the Joint Resolution of Disapproval, the EPA issued a final rule on May 19, 2025, removing the waste emissions charge rules from the Code of Federal Regulations. However, the underlying law mandating the waste emissions charge remains in effect. The OBBBA delayed collection of the charge until 2034. On September 16, 2025, the EPA proposed a rule that would suspend the Greenhouse Gas Reporting Program for the petroleum and natural gas source category until 2034 as well. Additionally, on March 8, 2024, the EPA issued a final rule to regulate emissions from oil and natural gas sources that includes New Source Performance Standards to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources. Through an interim final rule issued on July 31, 2025, the EPA extended certain compliance deadlines contained in the final rule to various dates ranging from late 2025 to 2027.
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