Matador Resources Co
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
MTDR$50.41+1.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-25.
0001520006-25-000066
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 140 previous paragraphs and 129 current paragraphs.
68 unchanged; 55 reworded; 4 added; 16 removed; 1 previous and 2 current paragraphs rearranged.
Tables are not compared: 6 previous and 6 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (4)
Current report
Taxes other than income. Our taxes other than income increased $7.0 million, or 3%, to $275.6 million for the year ended December 31, 2025, as compared to $268.6 million for the year ended December 31, 2024. This increase in taxes other than income is primarily due to the increase in oil and natural gas revenues between the two periods. On a unit-of-production basis, our taxes other than income decreased 15% to $3.65 per BOE for the year ended December 31, 2025, as compared to $4.30 per BOE for the year ended December 31, 2024. This decrease per BOE was primarily attributable to a 14% decrease in realized oil prices between the two periods.
Current report
Total income tax provision. We recorded a current income tax provision of $7.1 million and a deferred income tax provision of $165.6 million for the year ended December 31, 2025. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. The decrease in the current income tax provision between the periods was primarily the result of the OBBBA, which made permanent, extended or modified certain provisions under the 2017 Tax Cuts and Jobs Act, among other things. The provisions of the OBBBA that are expected to most significantly impact us include (i) a permanent extension of 100% bonus depreciation for certain capital expenditures, (ii) an immediate deduction of domestic research and experimental expenditures, (iii) an acceleration of deductions for unamortized domestic research or development expenditures and (iv) an elimination of the deduction for depreciation, amortization and depletion from the definition of “adjusted taxable income” for the purpose of calculating limitations on interest expense deductions. The effective income tax rate and the total income tax provision for the year ended December 31, 2025 were not materially impacted by the enactment of the OBBBA.
Current report
In April 2025, the Board approved the Share Repurchase Program authorizing the repurchase of up to $400.0 million of common stock. These repurchases may be conducted through a variety of methods including open market purchases, 10b5-1 trading plans, privately negotiated transactions or other means. The timing and number of shares that we may repurchase under the Share Repurchase Program is subject to a variety of factors, including our stock price, market conditions, trading volume and other uses for our free cash flow. There can be no assurance regarding the exact number of shares to be repurchased by us, if any. Depending on market conditions and other factors, these repurchases may be commenced or suspended at any time periodically without prior notice, and the Share Repurchase Program does not obligate us to acquire any amount of common stock. During the year ended December 31, 2025, we repurchased 1,351,328 shares of common stock under the Share Repurchase Program at a weighted average price of $41.31 per common share for a total cost of $55.8 million.
Current report
For the year ended December 31, 2025, we reported net income attributable to Matador shareholders of $759.2 million, as compared to $885.3 million for the year ended December 31, 2024. This decrease primarily resulted from (i) a $221.1 million increase in depletion, depreciation and amortization expenses, (ii) a $90.7 million increase in lease operating expenses, (iii) a $40.7 million increase in midstream operating expenses, (iv) a $36.8 million increase in interest expense, (v) an $8.2 million increase in transportation and processing expenses and (vi) lower realized oil and natural gas prices for the year ended December 31, 2025, as compared to the year ended December 31, 2024. These expense increases were partially offset by (i) increased oil and natural gas production and (ii) a $119.7 million decrease in the income tax provision for the year ended December 31, 2025, as compared to the year ended December 31, 2024.
Removed paragraphs (16)
Previous report
On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, the Company received a special distribution from San Mateo of approximately $219.8 million. In addition, the Company has the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by the Company and 49% by Five Point.
Previous report
In connection with the Pronto Transaction, the Company dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from the Company’s operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing.
Previous report
In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024.
Previous report
During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin.
Previous report
increased compensation expenses for our existing employees as well as the addition of new employees to support the continued
Previous report
On March 22, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.50 billion, (ii) increase the elected borrowing commitment from $1.325 billion to $1.50 billion, (iii) increase the maximum facility amount from $2.00 billion to $3.50 billion, (iv) extend the maturity date from October 31, 2026 to March 22, 2029, (v) appoint PNC Bank, National Association as administrative agent thereunder and (vi) add five new banks to the lending group. This March 2024 redetermination constituted the regularly scheduled May 1 redetermination.
Previous report
On March 28, 2024, we completed the 2024 Equity Offering and used the net proceeds for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.
Previous report
On April 2, 2024, we completed the 2032 Notes Offering and used the net proceeds to fund the 2026 Notes Repurchase and for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.
Previous report
On September 18, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitment from $1.50 billion to $2.25 billion.
Previous report
On September 25, 2024, we completed the 2033 Notes Offering and used the net proceeds to partially repay borrowings outstanding under the Credit Agreement including all of the $250.0 million in outstanding borrowings under the term loan.
Previous report
On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. During the fourth quarter of 2024, we received $113.6 million from the sale of Piñon resulting from our approximate 19% interest in the parent company of Piñon that we acquired as part of the Ameredev Acquisition and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025.
Previous report
On November 21, 2024, we received notice from PNC Bank, National Association, as administrative agent under the Credit Agreement, that the lenders under the Credit Agreement completed their scheduled semi-annual review of our proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $2.50 billion to $3.25 billion. We chose to maintain the elected borrowing commitments at $2.25 billion.
Previous report
For the year ended December 31, 2024, we reported net income attributable to Matador shareholders of $885.3 million, as compared to $846.1 million for the year ended December 31, 2023. This increase primarily resulted from significantly higher oil and natural gas production for the year ended December 31, 2024, as compared to the year ended December 31, 2023. These increases were partially offset by increased depletion, depreciation and amortization expenses of $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, increased interest expense of $171.7 million for the year ended December 31, 2024, as compared to $121.5 million for the year ended December 31, 2023, an increased income tax provision of $292.4 million for the year ended December 31, 2024, as compared to an income tax provision of $186.0 million for the year ended December 31, 2023 and by lower realized oil and natural gas prices between the periods.
Previous report
Adjusted EBITDA, a non-GAAP financial measure, increased $449.2 million to $2.30 billion for the year ended December 31, 2024, as compared to $1.85 billion for the year ended December 31, 2023. This increase was primarily attributable to higher oil and natural gas production noted above, partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Previous report
(8)At December 31, 2024, we had outstanding commitments related to the construction and installation of San Mateo’s Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase compressors to be utilized in San Mateo operations.
Previous report
We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. At February 18, 2025, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2025 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2025. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income.
Reworded paragraphs (55)
Previous wording
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, 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.
Current wording
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Previous wording
During the year ended December 31, 2024, we completed and began producing oil and natural gas from 124 gross (101.9 net) operated and 127 gross (8.3 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024.
Current wording
During the year ended December 31, 2025, we completed and began producing oil and natural gas from 151 gross (121.2 net) operated and 107 gross (8.1 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2025, although we did participate in the drilling and completion of 12 gross (0.1 net) non-operated Haynesville shale wells that began producing in 2025.
Previous wording
We began 2024 operating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024.
Current wording
We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2025 of $1.53 billion, which was within our estimated range for 2025 D/C/E capital expenditures of $1.47 to $1.55 billion, as provided on October 21, 2025.
Previous wording
Substantially all of our 2024 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition.
Current wording
Substantially all of our 2025 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.
Previous wording
Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. Our average daily oil production in 2024 was 99,808 Bbl of oil per day, an increase of 32%, as compared to 75,457 Bbl of oil per day in 2023. This increase in oil production was primarily a result of the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf per day, an increase of 26%, as compared to 338.1 MMcf per day in 2023. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% and 57% of our total production for the years ended December 31, 2024 and 2023, respectively.
Current wording
Our average daily oil equivalent production for the year ended December 31, 2025 was 207,070 BOE per day, including 119,723 Bbl of oil per day and 524.1 MMcf of natural gas per day, an increase of 21%, as compared to 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, for the year ended December 31, 2024. Our average daily oil production in 2025 was 119,723 Bbl of oil per day, an increase of 20%, as compared to 99,808 Bbl of oil per day in 2024. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2025 was 524.1 MMcf per day, an increase of 23%, as compared to 425.7 MMcf per day in 2024. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% of our total production for each of the years ended December 31, 2025 and 2024.
Previous wording
For the year ended December 31, 2024, our oil and natural gas revenues were $3.14 billion, an increase of 24% from oil and natural gas revenues of $2.55 billion for the year ended December 31, 2023. Our oil revenues increased 29% to 2.77 billion, as compared to $2.14 billion for the year ended December 31, 2023. The increase in oil revenues resulted from the 33% increase in our oil production noted above, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. Our natural gas revenues decreased 7% to $371.5 million, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above.
Current wording
For the year ended December 31, 2025, our oil and natural gas revenues were $3.24 billion, an increase of 3% from oil and natural gas revenues of $3.14 billion for the year ended December 31, 2024. Our oil revenues increased 2% to $2.84 billion, as compared to $2.77 billion for the year ended December 31, 2024. The increase in oil revenues resulted from the 20% increase in our oil production noted above, which was partially offset by a 14% decrease in the weighted average oil price realized for the year ended December 31, 2025 to $64.99 per Bbl, as compared to $75.89 per Bbl realized for the year ended December 31, 2024. Our natural gas revenues increased 7% to $398.6 million, as compared to $371.5 million for the year ended December 31, 2024. The increase in natural gas revenues resulted from a 23% increase in natural gas production for the year ended December 31, 2025 noted above, which was partially offset by a decrease in our weighted average realized natural gas price of $2.08 per Mcf in 2025, as compared to $2.38 per Mcf in 2024.
Previous wording
We reported net income attributable to Matador shareholders of approximately $885.3 million, or $7.14 per diluted common share, on a GAAP basis for the year ended December 31, 2024, as compared to a net income of $846.1 million, or $7.05 per diluted common share, for the year ended December 31, 2023. Adjusted EBITDA for the year ended December 31, 2024 was $2.30 billion, as compared to Adjusted EBITDA of $1.85 billion for the year ended December 31, 2023. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
Current wording
We reported net income attributable to Matador shareholders of approximately $759.2 million, or $6.09 per diluted common share, on a GAAP basis for the year ended December 31, 2025, as compared to a net income of $885.3 million, or $7.14 per diluted common share, for the year ended December 31, 2024. Adjusted EBITDA for the year ended December 31, 2025 was $2.29 billion, as compared to Adjusted EBITDA of $2.30 billion for the year ended December 31, 2024. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
Previous wording
At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. Our estimated total proved reserves of 611.5 million BOE at December 31, 2024 represented a 33% year-over-year increase, as compared to 460.1 million BOE at December 31, 2023. Our estimated proved oil reserves were 361.8 million Bbl at December 31, 2024, an increase of 33%, as compared to 272.3 million Bbl at December 31, 2023, and our estimated proved natural gas reserves were 1.50 Tcf at December 31, 2024, an increase of 33%, as compared to 1.13 Tcf at December 31, 2023. Proved oil reserves comprised 59% of our total proved reserves at each of December 31, 2024 and 2023. At December 31, 2024, 60% of our total proved reserves were proved developed reserves, as compared to 63% at December 31, 2023. At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
Current wording
At December 31, 2025, our estimated total proved oil and natural gas reserves were 667.0 million BOE, including 376.0 million Bbl of oil and 1.75 Tcf of natural gas, with a Standardized Measure of $6.99 billion and a PV-10 of $8.24 billion. At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. Our estimated total proved reserves of 667.0 million BOE at December 31, 2025 represented a 9% year-over-year increase, as compared to 611.5 million BOE at December 31, 2024. Our estimated proved oil reserves were 376.0 million Bbl at December 31, 2025, an increase of 4%, as compared to 361.8 million Bbl at December 31, 2024, and our estimated proved natural gas reserves were 1.75 Tcf at December 31, 2025, an increase of 17%, as compared to 1.50 Tcf at December 31, 2024. Proved oil reserves comprised 56% of our total proved reserves at December 31, 2025, as compared to 59% at December 31, 2024. At December 31, 2025, 61% of our total proved reserves were proved developed reserves, as compared to 60% at December 31, 2024. At December 31, 2025, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
Previous wording
Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day.
Current wording
During the second quarter of 2025, San Mateo completed the expansion of the Marlan Processing Plant by adding a designed inlet capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities. This expansion increased the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day.
Previous wording
At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included:
Current wording
At December 31, 2025, San Mateo’s midstream system included:
Previous wording
•Natural Gas Assets: 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;
Current wording
•Natural Gas Assets: 720 MMcf per day of designed natural gas cryogenic processing capacity and approximately 340 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;
Previous wording
•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and
Current wording
•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 120 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and
Previous wording
•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
Current wording
•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 195 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
Previous wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025 and currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects 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. 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 2025 Delaware Basin operated drilling program 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.
Current wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for D/C/E capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.
Previous wording
At December 31, 2024, we had $23.0 million in cash (excluding restricted cash) and $1.60 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
Current wording
At December 31, 2025, we had $15.3 million in cash (excluding restricted cash) and $1.80 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2026 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2026, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
Previous wording
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and 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 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.
Current wording
We intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. Purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2026.
Previous wording
Oil and natural gas revenues. Our oil and natural gas revenues increased $598.2 million, or 24%, to $3.14 billion for the year ended December 31, 2024, as compared to $2.55 billion for the year ended December 31, 2023. Our oil revenues increased $627.5 million, or 29%, to $2.77 billion for the year ended December 31, 2024, as compared to $2.14 billion for the year ended December 31, 2023. This increase in oil revenues resulted from a 33% increase in our oil production to 36.5 million Bbl of oil for the year ended December 31, 2024, as compared to 27.5 million Bbl of oil for the year ended December 31, 2023, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. The increase in oil production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $29.2 million, or 7%, to $371.5 million for the year ended December 31, 2024, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues was primarily attributable to the 27% decrease in the weighted average natural gas price realized for the year ended December 31, 2024 to $2.38 per Mcf, as compared to $3.25 per Mcf realized for the year ended December 31, 2023, which was partially offset by a 26% increase in our natural gas production to 155.8 Bcf for the year ended December 31, 2024, as compared to 123.4 Bcf for the year ended December 31, 2023. The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Current wording
Oil and natural gas revenues. Our oil and natural gas revenues increased $94.9 million, or 3%, to $3.24 billion for the year ended December 31, 2025, as compared to $3.14 billion for the year ended December 31, 2024. Our oil revenues increased $67.8 million, or 2%, to $2.84 billion for the year ended December 31, 2025, as compared to $2.77 billion for the year ended December 31, 2024. This increase in oil revenues resulted from a 20% increase in our oil production to 43.7 million Bbl of oil for the year ended December 31, 2025, as compared to 36.5 million Bbl of oil for the year ended December 31, 2024, which was partially offset by a 14% decrease in the weighted average oil price realized for the year ended December 31, 2025 to $64.99 per Bbl, as compared to $75.89 per Bbl realized for the year ended December 31, 2024. Our natural gas revenues increased by $27.1 million, or 7%, to $398.6 million for the year ended December 31, 2025, as compared to $371.5 million for the year ended December 31, 2024. The increase in natural gas revenues was primarily attributable to a 23% increase in our natural gas production to 191.3 Bcf for the year ended December 31, 2025, as compared to 155.8 Bcf for the year ended December 31, 2024, which was partially offset by a 13% decrease in the weighted average natural gas price realized for the year ended December 31, 2025 to $2.08 per Mcf, as compared to $2.38 per Mcf realized for the year ended December 31, 2024.
Previous wording
Third-party midstream services revenues. Our third-party midstream services revenues increased $18.9 million, or 15%, to $141.0 million for the year ended December 31, 2024, as compared to $122.2 million for the year ended December 31, 2023. 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 third-party produced water disposal revenues to $56.3 million for the year ended December 31, 2024, as compared to $45.3 million for the year ended December 31, 2023 and (ii) an increase in our oil transportation revenues to $17.3 million for the year ended December 31, 2024, as compared to $11.0 million for the year ended December 31, 2023.
Current wording
Third-party midstream services revenues. Our third-party midstream services revenues increased $23.7 million, or 17%, to $164.7 million for the year ended December 31, 2025, as compared to $141.0 million for the year ended December 31, 2024. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering and processing revenues to $90.3 million for the year ended December 31, 2025, as compared to $67.5 million for the year ended December 31, 2024, (ii) an increase in our oil transportation revenues to $23.7 million for the year ended December 31, 2025, as compared to $17.3 million for the year ended December 31, 2024, which were partially offset by (iii) a decrease in third-party produced water disposal revenues to $50.7 million for the year ended December 31, 2025, as compared to $56.3 million for the year ended December 31, 2024.
Previous wording
Sales of purchased natural gas. Our sales of purchased natural gas increased $44.2 million, or 30%, to $194.1 million for the year ended December 31, 2024, as compared to $149.9 million for the year ended December 31, 2023. This increase was primarily the result of a 45% increase in natural gas volumes sold, which was partially offset by an 11% decrease in natural gas prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.
Current wording
Sales of purchased natural gas. Our sales of purchased natural gas increased $58.9 million, or 30%, to $253.0 million for the year ended December 31, 2025, as compared to $194.1 million for the year ended December 31, 2024. This increase was primarily the result of a 21% increase in natural gas volumes sold and an 8% increase in natural gas prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.
Previous wording
Realized gain (loss) on derivatives. Our realized net gain on derivatives was $12.7 million for the year ended December 31, 2024, as compared to a realized net loss of approximately $9.6 million for the year ended December 31, 2023. We realized a net gain of approximately $12.7 million related to our natural gas basis differential swap contracts for the year ended December 31, 2024, resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average gain on our natural gas derivatives of approximately $0.09 per Mcf of natural gas produced during the year ended December 31, 2024, as compared to an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023.
Current wording
Realized gain (loss) on derivatives. Our realized net gains on derivatives were $21.7 million and $12.7 million for the years ended December 31, 2025 and 2024, respectively. These realized net gains were related to natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized average gains on our natural gas derivatives of approximately $0.12 and $0.09 per Mcf of natural gas produced during the years ended December 31, 2025 and 2024, respectively.
Previous wording
Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $13.3 million for the year ended December 31, 2024, as compared to an unrealized loss of $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023.
Current wording
Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.1 million for the year ended December 31, 2025, as compared to an unrealized gain of $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2025, the aggregate net fair value of our open oil and natural gas costless collars and natural gas basis differential swap contracts changed from a net asset of approximately $16.0 million to a net asset of approximately $34.1 million, resulting in an unrealized gain on derivatives of approximately $18.1 million for the year ended December 31, 2025. During the year ended December 31, 2024, the aggregate net fair value of our open oil and natural gas derivative contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024.
Previous wording
Lease operating expenses. Our lease operating expenses increased $97.9 million, or 40%, to $341.5 million for the year ended December 31, 2024, as compared to $243.7 million for the year ended December 31, 2023. On a unit-of-production basis, our lease operating expenses increased 8% to $5.47 per BOE for the year ended December 31, 2024, as compared to $5.06 per BOE for the year ended December 31, 2023. These increases for the year ended December 31, 2024 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) and to operating cost inflation during the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Current wording
Lease operating expenses. Our lease operating expenses increased $90.7 million, or 28%, to $415.8 million for the year ended December 31, 2025, as compared to $325.1 million for the year ended December 31, 2024. On a unit-of-production basis, our lease operating expenses increased 6% to $5.50 per BOE for the year ended December 31, 2025, as compared to $5.20 per BOE for the year ended December 31, 2024. These increases were primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) for the year ended December 31, 2025, as compared to the year ended December 31, 2024.
Previous wording
Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $42.3 million, or 16%, to $306.8 million for the year ended December 31, 2024, as compared to $264.5 million for the year ended December 31, 2023. This increase was primarily attributable to the $43.4 million increase in our production taxes to $243.6 million for the year ended December 31, 2024, as compared to $200.2 million for the year ended December 31, 2023, primarily due to the $598.2 million increase in oil and natural gas revenues for the year ended December 31, 2024, as compared to the year ended December 31, 2023. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $4.91 per BOE for the year ended December 31, 2024, as compared to $5.50 per BOE for the year ended December 31, 2023. This decrease was primarily attributable to a decrease in transportation and processing expense per BOE that resulted from a mix of revenue contracts, including from San Mateo, between the two periods.
Current wording
Transportation and processing. Our transportation and processing expenses increased $8.2 million, or 14%, to $66.8 million for the year ended December 31, 2025, as compared to $58.6 million for the year ended December 31, 2024. This increase in transportation and processing expenses is primarily due to the 21% increase in our total oil equivalent production between the two periods. On a unit-of-production basis, our transportation and processing expenses decreased 6% to $0.88 per BOE for the year ended December 31, 2025, as compared to $0.94 per BOE for the year ended December 31, 2024. This decrease per BOE primarily resulted from the mix of revenue contracts, including from San Mateo, between the two periods.
Previous wording
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $42.6 million, or 33%, to $171.5 million for the year ended December 31, 2024, as compared to $128.9 million for the year ended December 31, 2023. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations, including assets acquired in the Ameredev Acquisition, of $73.9 million for the year ended December 31, 2024, as compared to $41.4 million for the year ended December 31, 2023 and (ii) increased expenses associated with our commercial produced water disposal operations of $63.0 million for the year ended December 31, 2024, as compared to $53.6 million for the year ended December 31, 2023.
Current wording
Midstream operating. Our midstream operating expenses increased $40.7 million, or 24%, to $208.1 million for the year ended December 31, 2025, as compared to $167.4 million for the year ended December 31, 2024. This increase was primarily attributable to the expansion of the Marlan Processing Plant and increased throughput volumes from Matador’s wholly-owned midstream assets, which resulted in (i) increased expenses associated with our expanded pipeline operations of $100.9 million for the year ended December 31, 2025, as compared to $73.9 million for the year ended December 31, 2024 and (ii) increased expenses associated with plant processing of $52.7 million for the year ended December 31, 2025, as compared to $34.6 million for the year ended December 31, 2024, which was partially offset by (iii) decreased expenses associated with our commercial produced water disposal operations of $59.5 million for the year ended December 31, 2025, as compared to $63.0 million for the year ended December 31, 2024.
Previous wording
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $257.6 million, or 36%, to $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition and a 30% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 5% to $15.59 per BOE for the year ended December 31, 2024, as compared to $14.90 per BOE for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition.
Current wording
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $221.1 million, or 23%, to $1.20 billion for the year ended December 31, 2025, as compared to $974.3 million for the year ended December 31, 2024, primarily as a result of the 21% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 1% to $15.82 per BOE for the year ended December 31, 2025, as compared to $15.59 per BOE for the year ended December 31, 2024.
Previous wording
General and administrative. Our general and administrative expenses increased $17.1 million, or 15%, to $127.5 million for the year ended December 31, 2024, as compared to $110.4 million for the year ended December 31, 2023, primarily due to
Current wording
General and administrative. Our general and administrative expenses increased $9.6 million, or 8%, to $137.1 million for the year ended December 31, 2025, as compared to $127.5 million for the year ended December 31, 2024, primarily due to
Previous wording
growth in our land, geoscience, drilling, completion, production, midstream and administration functions. Our general and administrative expenses on a unit-of-production basis decreased 11% to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30% increase in our total oil equivalent production between the two periods.
Current wording
increased payroll for our existing employees as well as with additional employees joining Matador to support our increased land, geoscience, drilling, completion, production, midstream and administration functions as a result of our continued growth. Our general and administrative expenses on a unit-of-production basis decreased 11% to $1.81 per BOE for the year ended December 31, 2025, as compared to $2.04 per BOE for the year ended December 31, 2024, primarily as a result of the 21% increase in our total oil equivalent production between the two periods.
Previous wording
Interest expense. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. The increase in interest expense for the year ended December 31, 2024 was primarily attributable to an increase in our average debt outstanding between the two periods. In April 2024, we completed the 2026 Notes Repurchase and the 2032 Notes Offering and in September 2024 we completed the 2033 Notes Offering, resulting in a net increase in our total senior notes outstanding to $2.15 billion at December 31, 2024 as compared to $1.20 billion at December 31, 2023. In connection with the 2026 Notes Repurchase, the amendment of our Credit Agreement in March 2024 and the amendment of the San Mateo Credit Facility in November 2024, we also incurred a loss of approximately $6.2 million included in interest expense for the year ended December 31, 2024.
Current wording
Interest expense. For the year ended December 31, 2025, we incurred total interest expense of approximately $237.3 million. We capitalized approximately $28.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2025 and expensed the remaining $208.5 million to operations. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. The increase in interest expense for the year ended December 31, 2025 was primarily attributable to a $602.3 million increase in the weighted average of senior notes outstanding between the periods in connection with the Ameredev Acquisition in September 2024.
Previous wording
Total income tax provision. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico.
Current wording
Our effective income tax rate of 19% for the year ended December 31, 2025 differed from the U.S. federal statutory rate due primarily to a benefit recognized as a result of the remeasurement of deferred income taxes associated with changes in state apportionment rates following the Company’s filings of its 2024 tax returns, partially offset by state taxes in New Mexico. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes in New Mexico. Our effective income tax rate excluding the effect of net income attributable to non-controlling interest in subsidiaries was 17% and 23% for the years ended December 31, 2025 and 2024, respectively, as disclosed in Note 8 to the consolidated financial statements.
Previous wording
At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 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.
Current wording
At December 31, 2025, we had cash totaling $15.3 million and restricted cash totaling $64.2 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
Previous wording
At December 31, 2024, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 2032 Notes, (iii) $750.0 million of outstanding 2033 Notes, (iv) $595.5 million of borrowings outstanding under the Credit Agreement and (v) approximately $52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement.
Current wording
At December 31, 2025, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 6.500% senior notes due 2032 (the “2032 Notes”), (iii) $750.0 million of outstanding 6.250% senior notes due 2033 (the “2033 Notes”), (iv) $398.0 million of borrowings outstanding under the Credit Agreement and (v) approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.
Previous wording
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024.
Current wording
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We were in compliance with the terms of the Credit Agreement at December 31, 2025.
Previous wording
At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. On November 26, 2024, San Mateo and its lenders entered into an amendment to the San Mateo Credit Facility to, among other things: (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $535.0 million to $800.0 million and (iii) add six new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05 billion.
Current wording
At December 31, 2025, San Mateo had $883.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In December 2025, San Mateo and certain of its lenders amended the San Mateo Credit Facility to (i) increase the lender commitments from $850.0 million to $1.10 billion, (ii) reduce the borrowing rate and (iii) add one new bank to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments of up to $1.35 billion.
Previous wording
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 December 31, 2024.
Current wording
The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2025.
Previous wording
In February 2024, April 2024 and July 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025.
Current wording
In February 2025, April 2025 and July 2025, our Board declared quarterly cash dividends of $0.3125 per share of common stock. In October 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.375 per share of common stock and also declared a quarterly cash dividend of $0.375 per share of common stock. In February 2026, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on March 10, 2026 to shareholders of record as of February 27, 2026.
Previous wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025. We currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects 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. 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 2025 Delaware Basin operated drilling program 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.
Current wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for D/C/E capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2026 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.
Previous wording
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and 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 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.
Current wording
We intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. Purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these capital expenditures with any degree of certainty; therefore, we have not provided estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2026.
Previous wording
Net cash provided by operating activities increased by $379.1 million to $2.25 billion for the year ended December 31, 2024, as compared to net cash provided by operating activities of $1.87 billion for the year ended December 31, 2023. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023. This increase was primarily attributable to the 30% increase in total oil equivalent production during 2024, as compared to 2023, which was partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023. Changes in our operating assets and liabilities between December 31, 2023 and December 31, 2024 resulted in a net decrease of approximately $36.9 million in net cash provided by operating activities for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Current wording
Net cash provided by operating activities increased by $178.1 million to $2.43 billion for the year ended December 31, 2025 from $2.25 billion for the year ended December 31, 2024. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased by $15.0 million to $2.25 billion for the year ended December 31, 2025 from $2.23 billion for the year ended December 31, 2024. This increase was primarily attributable to a 21% increase in total oil equivalent production during 2025, as compared to 2024, partially offset by lower realized oil and natural gas prices. Changes in our operating assets and liabilities between the periods resulted in a $163.1 million increase in net cash provided by operating activities for the year ended December 31, 2025, as compared to the year ended December 31, 2024.
Previous wording
Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
Current wording
Our operating cash flows are sensitive to a number of variables that are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
Previous wording
Net cash used in investing activities increased by $460.9 million to $3.67 billion for the year ended December 31, 2024 from $3.21 billion for the year ended December 31, 2023. This increase in net cash used in investing activities was primarily due to (i) expenditures related to the Ameredev Acquisition of $1.83 billion in 2024, which was $155.1 million higher than expenditures related to the Advance Acquisition of $1.68 billion in 2023, (ii) an increase between the periods of $266.8 million in acquisitions of oil and natural gas properties, (iii) an increase between the periods of $118.2 million in midstream capital expenditures and (iv) an increase of $30.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin. These increases were partially offset by proceeds from the sale of our equity method investment in Piñon of $113.6 million for the year ended December 31, 2024.
Current wording
Net cash used in investing activities decreased by $1.51 billion to $2.16 billion for the year ended December 31, 2025 from $3.67 billion for the year ended December 31, 2024. This decrease in net cash used in investing activities between the periods was primarily due to (i) a $1.83 billion decrease in expenditures related to the Ameredev Acquisition that occurred in September 2024, (ii) a $115.3 million decrease in expenditures related to the acquisition of oil and natural gas properties and (iii) a $10.1 million increase in cash provided by proceeds from the sale of assets. The decreases in cash used in investing activities between the periods were partially offset by (i) a $319.4 million increase in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin, (ii) a $110.3 million decrease in proceeds from the sale of an equity method investment in the parent company of Piñon Midstream, LLC, and (iii) a $13.9 million increase in midstream capital expenditures.
Showing the first 40 of 55 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
As we have done in recent years, we may divest portions of our non-core assets as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. Divestitures and other types of monetizations are difficult to estimate with any degree of certainty. Therefore, we have not provided estimated proceeds related to divestitures or monetizations for 2026.
Current report — wording carried from elsewhere
As we have done in recent years, we may divest portions of our non-core assets as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. Divestitures and other types of monetizations are difficult to estimate with any degree of certainty. Therefore, we have not provided estimated proceeds related to divestitures or monetizations for 2026.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($2.20) per MMBtu for the year ended December 31, 2024. Between December 31, 2024 and February 18, 2025, this natural gas price differential widened to approximately ($2.70) per MMBtu. A significant portion of our