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What changed in Matador Resources Co's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Matador Resources Co's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+635 added−714 removedSource: 10-K (2026-02-26) vs 10-K (2025-02-25)

Top changes in Matador Resources Co's 2025 10-K

635 paragraphs added · 714 removed · 552 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

221 edited+29 added−69 removed214 unchanged
Biggest changeCapital Resources and Financing Highlights During 2024, we achieved several significant and important capital resources objectives, which included: • the generation of free cash flow in all four quarters of 2024; • the amendment of our dividend policy in the fourth quarter of 2024, pursuant to which we increased the quarterly cash dividend from $0.20 per share of common stock to $0.25 per share of common stock; • the receipt of $219.8 million in special distributions from San Mateo as a result of the Pronto Transaction; and • the receipt of $23.8 million in performance incentives directly from Five Point.
Biggest changeCapital Resources and Financing Highlights During 2025, we achieved several significant and important capital resources objectives, which included: • the generation of free cash flow in all four quarters of 2025; • the amendment of our dividend policy two times during 2025, pursuant to which we increased the quarterly cash dividend from $0.25 per share of common stock in the fourth quarter of 2024 to $0.375 per share of common stock; 4 Table of Contents • the receipt of $136.7 million in cash distributions from San Mateo and $13.0 million in performance incentives directly from Five Point; • the implementation in April 2025 of a share repurchase program (the “Share Repurchase Program”) authorizing the repurchase of up to $400.0 million of common stock, and the purchase of 1,351,328 shares of common stock under the Share Repurchase Program in 2025 at a weighted average price of $41.31 per common share for a total cost of $55.8 million; • the amendment of San Mateo’s secured revolving credit facility (the “San Mateo Credit Facility”) in December 2025 to increase the lender commitments from $850.0 million to $1.10 billion, and to amend the accordion feature to provide for potential increases in lender commitments of up to $1.35 billion; and • an upgrade to our long-term issuer default rating by Fitch Ratings from ‘BB-’ to ‘BB’.
We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities.
We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities.
Ambassador to the United Nations to immediately submit formal written notification of the U.S.’s withdrawal from the Paris Agreement and any agreement, pact, accord or similar commitment made under the United Nations Framework Convention on Climate Change, which would include the Glasgow Climate Pact.
Ambassador to the United Nations to immediately submit formal written notification of the U.S.’s withdrawal from the Paris Agreement and any agreement, pact, accord or similar commitment made under the United Nations Framework Convention on Climate Change, which would include the Glasgow Climate Pact, and the U.S.
On March 8, 2024, the EPA issued a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources.
For example, on March 8, 2024, the EPA issued a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources.
We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”).
We improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”).
In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. 25 Table of Contents Land Stewardship When feasible, we attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S.
In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations. 23 Table of Contents Land Stewardship When feasible, we attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S.
We plan to achieve our goal by, among other items, executing the following business strategies: • focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; • identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; • continue to improve operational and cost efficiencies; • identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Matador; • maintain our financial discipline; • return capital to shareholders through our dividend policy; • pursue opportunistic acquisitions, divestitures and joint ventures; and • provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.
We plan to achieve our goal by, among other items, executing the following business strategies: • focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; • identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; • continue to improve operational and cost efficiencies; • identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Matador; • maintain our financial discipline; • return capital to shareholders; • pursue opportunistic acquisitions, divestitures and joint ventures; and • provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.
Undeveloped Acreage Expiration The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2024 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term.
Undeveloped Acreage Expiration The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2025 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term.
See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance.
See “Risk Factors—Risks Related to Laws and Regulations—Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in 30 Table of Contents preparing for or responding to those effects” and “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.” In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance.
In connection with the Pronto Transaction, Matador 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 our operated wells in northern Lea County, New Mexico.
In connection with the Pronto Transaction, Matador dedicated to San Mateo 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 San Mateo will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico.
At December 31, 2024, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow.
At December 31, 2025, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow.
During 2024, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions.
During 2025, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions.
Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations.
Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. For example, in recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations.
See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Environmental, Health and Safety Regulation The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations.
See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” 28 Table of Contents Environmental, Health and Safety Regulation The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations.
Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2024, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling.
Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2025, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage further, we anticipate that we may identify additional locations for future drilling.
See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” 24 Table of Contents Competition The oil and natural gas industry is highly competitive.
See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” 22 Table of Contents Competition The oil and natural gas industry is highly competitive.
Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing and setbacks, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells.
The states in which we operate also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing and setbacks, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells.
In addition, at December 31, 2024, San Mateo had NGL pipeline connections at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners L.P. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck.
In addition, at December 31, 2025, San Mateo had NGL pipeline connections at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners L.P. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck.
We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024.
We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2025.
See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Pipeline Regulation Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation.
See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and 25 Table of Contents mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Pipeline Regulation Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation.
(“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and • Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
(“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and • Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 195 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
At December 31, 2024, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2024 within five years of booking these reserves.
At December 31, 2025, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2025 within five years of booking these reserves.
At December 31, 2024, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area.
At December 31, 2025, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area.
Southeast New Mexico/West Texas South Texas Northwest Louisiana Delaware Basin Eagle Ford (1) Haynesville Cotton Valley (2) Total Annual Net Production Volumes Oil (MBbl) 36,265 263 — 2 36,530 Natural gas (Bcf) 147.5 0.6 6.3 1.4 155.8 Total oil equivalent (MBOE) (3) 60,856 361 1,046 232 62,495 Percentage of total annual net production 97.4 % 0.6 % 1.7 % 0.3 % 100.0 % Average Net Daily Production Volumes Oil (Bbl/d) 99,086 719 — 3 99,808 Natural gas (MMcf/d) 403.1 1.6 17.2 3.8 425.7 Total oil equivalent (BOE/d) 166,273 986 2,859 633 170,751 Average Sales Prices (4) Oil (per Bbl) $ 75.90 $ 75.64 $ — $ 70.13 $ 75.89 Natural gas (per Mcf) $ 2.40 $ 4.19 $ 1.95 $ 2.02 $ 2.38 Total oil equivalent (per BOE) $ 51.05 $ 61.97 $ 11.67 $ 12.33 $ 50.31 Production Costs (5) Lease operating, transportation and processing (per BOE) $ 5.87 $ 36.68 $ 6.10 $ 8.00 $ 6.23 __________________ (1) Includes 61 gross (41.0 net) wells from the Eagle Ford formation that were divested in 2024 and one well producing oil from the Austin Chalk formation in La Salle County, Texas that was divested in November 2024.
Southeast New Mexico/West Texas South Texas Northwest Louisiana Delaware Basin Eagle Ford (1) Haynesville Cotton Valley (2) Total Annual Net Production Volumes Oil (MBbl) 36,265 263 — 2 36,530 Natural gas (Bcf) 147.5 0.6 6.3 1.4 155.8 Total oil equivalent (MBOE) (3) 60,856 361 1,046 232 62,495 Percentage of total annual net production 97.4 % 0.6 % 1.7 % 0.3 % 100.0 % Average Net Daily Production Volumes Oil (Bbl/d) 99,086 719 — 3 99,808 Natural gas (MMcf/d) 403.1 1.6 17.2 3.8 425.7 Total oil equivalent (BOE/d) 166,273 986 2,859 633 170,751 Average Sales Prices (4) Oil (per Bbl) $ 75.90 $ 75.64 $ — $ 70.13 $ 75.89 Natural gas (per Mcf) $ 2.40 $ 4.19 $ 1.95 $ 2.02 $ 2.38 Total oil equivalent (per BOE) $ 51.05 $ 61.97 $ 11.67 $ 12.33 $ 50.31 Production Costs (5) Lease operating, transportation and processing (per BOE) $ 5.97 $ 36.44 $ 5.46 $ 8.00 $ 6.14 _________________ (1) Includes 61 gross (41.0 net) wells from the Eagle Ford formation that were divested in 2024 and one well producing oil from the Austin Chalk formation in La Salle County, Texas that was divested in November 2024.
(2) Includes the Cotton Valley formation and shallower zones. Estimated Proved Reserves The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2024, 2023 and 2022. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas.
(2) Includes the Cotton Valley formation and shallower zones. Estimated Proved Reserves The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2025, 2024 and 2023. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas.
Natural Gas Gathering and Processing Assets The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production.
Natural Gas Gathering and Processing Assets The Black River Processing Plant and associated gathering system (the “Black River Gathering System”) were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production.
These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2024.
These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2025.
In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses.
In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases that were subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses.
These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on 7 Table of Contents available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
These locations have been identified for potential future drilling and were not producing at December 31, 2024. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations.
These locations have been identified for potential future drilling and were not producing at December 31, 2025. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations.
In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down a portion of the borrowings that funded the Advance Acquisition and Ameredev Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC or its affiliates (“Five Point”), our joint venture partner in San Mateo.
In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down a portion of the borrowings that funded the Ameredev Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Infrastructure, LLC or its affiliates (previously, Five Point Energy LLC) (“Five Point”), our joint venture partner in San Mateo.
At December 31, 2024, we had assigned no proved undeveloped reserves to our leasehold in Northwest Louisiana. (2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
At December 31, 2025, we had assigned no proved undeveloped reserves to our leasehold in Northwest Louisiana. (2) These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Produced Water Gathering and Disposal Assets At December 31, 2024, San Mateo had four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area.
Produced Water Gathering and Disposal Assets At December 31, 2025, San Mateo had four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area.
While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves.
While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an 6 Table of Contents effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves.
Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2025.
Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2026.
The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2024. Producing Total Identified Estimated Net Proved Wells Drilling Locations (1) Reserves (2) Avg.
The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2025. Producing Total Identified Estimated Net Proved Wells Drilling Locations (1) Reserves (2) Avg.
In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Ameredev” refer to Ameredev Stateline II, LLC, (iv) references to “Piñon” refer to Piñon Midstream, LLC, (v) references to the “Ameredev Acquisition” refer to the acquisition of Ameredev 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, which was completed by a subsidiary of the Company on September 18, 2024, (vi) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (vii) references to the “Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, and the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico on December 1, 2023, (viii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries (including, as of December 18, 2024, Pronto), and (ix) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary.
In this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to 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, (iv) references to the “Advance Acquisition” refer to the acquisition of Advance Energy Partners Holdings, LLC from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, and the acquisition of additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico on December 1, 2023, (v) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries (including, as of December 18, 2024, Pronto), and (vi) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary.
Our PV-10 at December 31, 2024, 2023 and 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
Our PV-10 at December 31, 2025, 2024 and 2023 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
Air permits are required for the construction of new oil and gas production facilities or the modification of existing facilities in New Mexico. Whether this announcement will result in meaningful delays or cancelation of our permit applications is uncertain.
Air permits are required for the construction of new oil and gas production facilities or the modification of existing facilities in New Mexico. Whether this announcement will result in meaningful delays or cancellation of our permit applications is uncertain.
At December 31, 2024, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles).
At December 31, 2025, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles).
The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. 35 Table of Contents
The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. 32 Table of Contents
See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” For the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues.
See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” For the years ended December 31, 2025, 2024 and 2023, we had three significant purchasers that accounted for approximately 72%, 79% and 76%, respectively, of our total oil, natural gas and NGL revenues.
The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2024, was also gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area.
The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2025, was also gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area.
Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation.
Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause 27 Table of Contents earthquakes (induced seismicity) as a result of flawed well design or operation.
Southeast New Mexico/West Texas South Texas Northwest Louisiana Delaware Basin Eagle Ford (1) Haynesville Cotton Valley (2) Total Annual Net Production Volumes Oil (MBbl) 27,264 276 — 2 27,542 Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 Total oil equivalent (MBOE) (3) 46,253 390 1,373 96 48,112 Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % Average Net Daily Production Volumes Oil (Bbl/d) 74,697 755 — 5 75,457 Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 Average Sales Prices (4) Oil (per Bbl) $ 77.90 $ 76.10 $ — $ 74.53 $ 77.88 Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 Production Costs (5) Lease operating, transportation and processing (per BOE) $ 5.99 $ 32.78 $ 4.59 $ 17.79 $ 6.19 _________________ (1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
Southeast New Mexico/West Texas South Texas Northwest Louisiana Delaware Basin Eagle Ford (1) Haynesville Cotton Valley (2) Total Annual Net Production Volumes Oil (MBbl) 27,264 276 — 2 27,542 Natural gas (Bcf) 113.9 0.7 8.2 0.6 123.4 Total oil equivalent (MBOE) (3) 46,253 390 1,373 96 48,112 Percentage of total annual net production 96.1 % 0.8 % 2.9 % 0.2 % 100.0 % Average Net Daily Production Volumes Oil (Bbl/d) 74,697 755 — 5 75,457 Natural gas (MMcf/d) 312.1 1.9 22.6 1.5 338.1 Total oil equivalent (BOE/d) 126,720 1,068 3,761 264 131,813 Average Sales Prices (4) Oil (per Bbl) $ 77.9 $ 76.1 $ — $ 74.53 $ 77.88 Natural gas (per Mcf) $ 3.32 $ 3.54 $ 2.23 $ 2.09 $ 3.25 Total oil equivalent (per BOE) $ 54.10 $ 60.01 $ 13.39 $ 13.61 $ 52.91 Production Costs (5) Lease operating, transportation and processing (per BOE) $ 5.88 $ 32.56 $ 4.56 $ 17.53 $ 6.08 _________________ (1) Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
Our engineered well locations, at December 31, 2024, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location.
Our engineered well locations, at December 31, 2025, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location.
Our activities are subject to a variety of environmental laws and regulations, including: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations.
Our activities are subject to a variety of environmental laws and regulations, including: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the CAA and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations.
The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we earned $108.2 million in performance incentives through September 30, 2024.
The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we earned $108.2 million in performance 9 Table of Contents incentives through September 30, 2024.
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, we received a special distribution from San Mateo of approximately $219.8 million.
On December 18, 2024, we completed a transaction with Five Point in 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 (the “Pronto Transaction”). In connection with the Pronto Transaction, we received a special distribution from San Mateo of approximately $219.8 million.
The following table sets forth, since 2021, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
The following table sets forth, since 2022, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs.
These situations, if they 21 Table of Contents occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs.
Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 85% in all wells that we operated at December 31, 2024. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%.
Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 85% in all wells that we operated at December 31, 2025. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 9%.
The scientific community and regulatory agencies at all levels are studying the possible 30 Table of Contents linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity.
The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity.
Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr.
Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum 2 Table of Contents Corporation upon its formation by Mr. Foran in 1988. Mr.
Acreage Summary The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2024.
Acreage Summary The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2025.
At December 31, 2024, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play.
At December 31, 2025, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,800 gross (14,800 net) acres in the Cotton Valley play.
In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment.
In the course of such evaluations, an agency will prepare an 24 Table of Contents environmental assessment of impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that were turned to sales in 2024.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2025, although we did participate in the drilling and completion of 12 gross (0.1 net) non-operated Haynesville shale wells that were turned to sales in 2025.
The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with 28 Table of Contents FERC and posted publicly.
The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly.
Exploration and Production Segment Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Exploration and Production Segment Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement.
The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our secured revolving credit facility (the “Credit Agreement”).
We have no assurance that more 33 Table of Contents stringent environmental laws and regulations will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The overall trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment.
We have no assurance that more stringent environmental laws and regulations will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The overall trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment.
(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. 14 Table of Contents The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
(5) Excludes midstream operating expenses, ad valorem taxes and oil and natural gas production taxes. 13 Table of Contents The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
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.
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.
Persons who are responsible for releases of 31 Table of Contents hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources.
Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties 29 Table of Contents for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website.
Also, the charters of our Audit Committee, Executive Committee, Nominating and Corporate Governance Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our sustainability practices, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website.
Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo as of December 31, 2024. Operating Summary The following table sets forth certain unaudited production and operating data for the years ended December 31, 2024, 2023 and 2022.
Our midstream assets in Northwest Louisiana are not part of San Mateo as of December 31, 2025. Operating Summary The following table sets forth certain unaudited production and operating data for the years ended December 31, 2025, 2024 and 2023.
Our PV-10 at December 31, 2024 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024 were approximately $1.86 billion.
Our PV-10 at December 31, 2025 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2025 were approximately $1.25 billion.
The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System.
The Department of Transportation, through PHMSA, has established rules regarding integrity 26 Table of Contents management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System.
At December 31, 2024, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems.
At December 31, 2025, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems.
See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” Office Location Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Human Capital At December 31, 2024, we had 452 full-time employees. We believe that our relationships with our employees are satisfactory.
See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” 31 Table of Contents Office Location Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Human Capital At December 31, 2025, we had 483 full-time employees. We believe that our relationships with our employees are satisfactory.
At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included: • 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 southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); • Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 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 Marketing, L.P.
At December 31, 2025, San Mateo’s midstream system included: • Natural Gas Assets : 720 MMcf per day of designed natural gas cryogenic processing capacity and approximately 340 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”); • Oil Assets : three oil central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 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 Marketing, L.P.
At December 31, 2024, San Mateo was gathering or transporting almost all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area.
At December 31, 2025, San Mateo was gathering or transporting almost all our operated natural gas 10 Table of Contents production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area.
As of December 31, 2024, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 22 Table of Contents ten years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests.
As of December 31, 2025, our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of ten years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests.
This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.
This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects subject to review under NEPA.
At December 31, 2024, we had identified 5,080 gross (1,869 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon, Yeso and Avalon formations.
At December 31, 2025, we had identified 5,295 gross (1,802 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon, Yeso and Avalon formations.
NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions 26 Table of Contents having the potential to significantly impact the environment.
NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment.
This increased production was primarily attributable to the Ameredev Acquisition and to our delineation and development operations in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana.
This increased production was primarily due to the Ameredev Acquisition and to our delineation and development operations in the Delaware Basin throughout 2024, which offset our declining production in the Eagle Ford shale.
The increases in our Standardized Measure and PV-10 were primarily a result of a 33% increase in our total proved oil and natural gas reserves at December 31, 2024, as compared to December 31, 2023, partially offset by the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2024, as compared to December 31, 2023.
The decreases in our Standardized Measure and PV-10 were primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2025, as compared to December 31, 2024, partially offset by a 9% increase in our total proved oil and natural gas reserves at December 31, 2025, as compared to December 31, 2024.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

160 edited+36 added−40 removed365 unchanged
Biggest changeAs we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan.
Biggest changeThere is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value. 47 Table of Contents As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value.
Risks Related to our Operations • Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. • Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. • Our reserves and production are concentrated in a few core areas. • There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. • Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. • Multi-well pad drilling may result in volatility in our operating results. • The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. • We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. • Midstream projects are subject to risks of construction delays and cost over-runs. 36 Table of Contents • Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. • The seismic data and other technologies we use cannot eliminate exploration risk.
Risks Related to our Operations • Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. • Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. • Our reserves and production are concentrated in a few core areas. • There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. • Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. • Multi-well pad drilling may result in volatility in our operating results. • The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. • We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. 33 Table of Contents • Midstream projects are subject to risks of construction delays and cost over-runs. • Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. • The seismic data and other technologies we use cannot eliminate exploration risk.
If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility).
If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) Term SOFR (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility).
Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition.
Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have at times proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition.
Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital.
Unfavorable ESG ratings and activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital.
If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement.
If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) Term SOFR (as defined in the Credit Agreement) for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement.
If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio.
If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) Term SOFR for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio.
The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations.
The operating and financial restrictions and covenants in these debt agreements and any future debt agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations.
From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering, treating, compression or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo and its subsidiaries, including Pronto.
From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering, treating, compression or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo and its subsidiaries.
However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under Federal leases. Under the authority of the IRA, on April 10, 2024, BLM finalized new regulations to reduce the waste of natural gas from venting, flaring and leaks during oil and natural gas production activities on Federal and Indian leases.
The IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under federal leases. Under the authority of the IRA, on April 10, 2024, BLM finalized new regulations to reduce the waste of natural gas from venting, flaring and leaks during oil and natural gas production activities on Federal and Indian leases.
We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited.
We also have other non-operated acreage positions in Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited.
We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions.
We believe it is likely that scientific, public and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions.
General Risk Factors • We may have difficulty managing growth in our business. • The loss of any key personnel or Board member could disrupt our business operations. • A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. • Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. • We operate in a litigious environment and may be involved in legal proceedings. 37 Table of Contents Risks Related to our Financial Condition Our success is dependent on the prices of oil, natural gas and NGLs.
General Risk Factors • We may have difficulty managing growth in our business. • The loss of any key personnel or Board member could disrupt our business operations. • A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss. • Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control. • We operate in a litigious environment and may be involved in legal proceedings. 34 Table of Contents Risks Related to our Financial Condition Our success is dependent on the prices of oil, natural gas and NGLs.
There have also been efforts in recent years to influence the investment community, including investment advisors, investment fund managers, pension funds, sovereign wealth funds, university endowments, individual investors and family foundations, to divest, or limit investment in, fossil fuel equities.
There have also been efforts in recent years to influence the investment community, including investment advisors, investment fund managers, pension funds, sovereign wealth funds, university endowments, individual investors and family foundations, to divest, or limit investment in, fossil fuel-related equities.
The productivity and profitability of a well may be negatively affected by a number of additional factors, including: • general economic and industry conditions, including the prices received for oil and natural gas; • shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; • limited access to electrical power sources or other infrastructure used in our operations; • potential drainage of oil and natural gas from our properties by operations on adjacent properties; • the existence or magnitude of faults or unanticipated geological features; • loss of or damage to oilfield development and service tools; • accidents, equipment failures or mechanical problems; • title defects of the underlying properties; • increases in severance taxes; 47 Table of Contents • adverse weather conditions that delay drilling activities or cause producing wells to be shut in; • inflation in exploration, drilling, completion and production costs; • domestic and foreign governmental regulations; and • proximity to and capacity of gathering, processing, transportation and disposal facilities.
The productivity and profitability of a well may be negatively affected by a number of additional factors, including: • general economic and industry conditions, including the prices received for oil and natural gas; • shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; • limited access to electrical power sources or other infrastructure used in our operations; • potential drainage of oil and natural gas from our properties by operations on adjacent properties; • the existence or magnitude of faults or unanticipated geological features; • loss of or damage to oilfield development and service tools; • accidents, equipment failures or mechanical problems; • title defects of the underlying properties; • increases in severance taxes; • adverse weather conditions that delay drilling activities or cause producing wells to be shut in; • inflation in exploration, drilling, completion and production costs; • domestic and foreign governmental regulations; and • proximity to and capacity of gathering, processing, transportation and disposal facilities.
Risks Related to our Financial Condition • Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. • Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. • We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and in the Middle East. • Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. • Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. • Approximately 41% of our total proved reserves at December 31, 2024 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. • Unless we replace our oil and natural gas reserves, our reserves and production will decline. • We may be required to write down the carrying value of our proved properties under accounting rules. • Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. • Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. • Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. • We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. • We may incur losses or costs as a result of title deficiencies in the properties in which we invest. • Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.
Risks Related to our Financial Condition • Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. • Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. • We cannot predict the impact of armed conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East. • Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. • Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. • Approximately 39% of our total proved reserves at December 31, 2025 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. • Unless we replace our oil and natural gas reserves, our reserves and production will decline. • We may be required to write down the carrying value of our proved properties under accounting rules. • Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. • Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. • Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. • We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. • We may incur losses or costs as a result of title deficiencies in the properties in which we invest. • Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.
Potential difficulties that may be encountered in the integration process include, among others: • the inability to successfully integrate our acquisitions operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from such acquisitions; • not realizing anticipated operating synergies; and • potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions.
Potential difficulties that may be encountered in the integration process include, among others: • the inability to successfully integrate our acquisitions operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from such acquisitions; • not realizing anticipated operating synergies; and • potential environmental issues, unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions.
Certain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock.
In addition, certain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock.
Our actual drilling activities may be materially 51 Table of Contents different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. 49 Table of Contents Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless.
If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests were purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless.
We may not be able to compete 54 Table of Contents successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing 52 Table of Contents hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
For further discussion of these federal and state regulations, see “Business—Regulation—Environmental, Health and Safety Regulation.” In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes, droughts, floods and freezes), sea levels, the arability of farmland and water availability and quality.
For further discussion of these federal and state regulations, see “Business—Regulation—Environmental, Health and Safety Regulation.” In a 2010 interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes, droughts, floods and freezes), sea levels, the arability of farmland and water availability and quality.
Risks Related to our Liquidity • We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. • The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. • The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations. • Our credit rating may be downgraded, which could reduce our financial flexibility. • Dividend payments are at the discretion of our Board of Directors and subject to numerous factors.
Risks Related to our Liquidity • We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility. • The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility. • The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations. • Our credit rating may be downgraded, which could reduce our financial flexibility. • Dividend payments and repurchases of common stock are at the discretion of our Board of Directors and subject to numerous factors.
These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not 38 Table of Contents pursuant to long-term fixed price contracts.
These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not 35 Table of Contents pursuant to long-term fixed price contracts.
Our federal and state income tax liabilities in 2025 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods.
Our federal and state income tax liabilities in 2026 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods.
These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to these regulations.
These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to any such regulations.
As required by SEC rules and regulations, the estimated 40 Table of Contents discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.
As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.
A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. 41 Table of Contents Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
As our wells produce over time and more data becomes available, the estimated proved reserves will be 37 Table of Contents redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
The passage of any such legislation or any other similar change in U.S. federal income or state tax law could 57 Table of Contents affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.
The passage of any such legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.
Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective.
Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that these individuals could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective.
In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. and global economy and in the oil and natural gas industry may limit our ability to procure the necessary 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, have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, supply chain disruptions and other inflationary pressures affecting the U.S. and global economy and 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, have a material adverse effect on our business, financial condition, results of operations and cash flows.
If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected.
If 46 Table of Contents any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected.
For further discussion of these international commitments, see “Business—Regulation—Environmental, Health and Safety Regulation.” On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels.
For further discussion of these international commitments, see “Business—Regulation—Environmental, Health and Safety Regulation.” On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, impose a waste emissions charge on greenhouse gas emissions from certain facilities that exceed specified emissions levels.
While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.
While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in curtailment of injection operations, the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.
We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and in the Middle East and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business.
We cannot predict the impact of armed conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business.
In addition, non-cash write-downs may occur if we have: • downward adjustments to our estimated proved reserves; • increases in our estimates of development costs; or • deterioration in our exploration and development results. We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules.
In addition, non-cash write-downs may occur if we have: • downward adjustments to our estimated proved reserves; • increases in our estimates of development costs; or 38 Table of Contents • deterioration in our exploration and development results. We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules.
If we have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan.
If we have outstanding borrowings under 42 Table of Contents our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan.
In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in 50 Table of Contents the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us.
In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us.
Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations.
Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets, the syndicated bank market and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations.
In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations.
In addition, a number of states and local regulatory authorities are considering or have 55 Table of Contents implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations.
We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2025.
We may experience similar interruptions and processing capacity constraints in the future as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.
For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas.
For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event 58 Table of Contents of a leak or rupture, could affect high-consequence areas.
In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies.
In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies.
The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth.
The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt, the payment of cash dividends, if any, the repurchase of our common stock, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth.
Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no 43 Table of Contents obvious deficiencies in title to the well.
Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well.
Some of these third parties are not subject to minimum 53 Table of Contents volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products.
Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s gathering systems and the utilization rate at its other midstream facilities, San Mateo must continually obtain new sources of products.
Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream 59 Table of Contents companies, service companies or suppliers with whom we have a business relationship.
Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship.
Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties.
Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate 50 Table of Contents trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties.
These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection.
These operations are also subject to BLM rules regarding engineering and construction specifications for 53 Table of Contents production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection.
At this time, we cannot predict the cost of 61 Table of Contents such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. Several states have also passed legislation or promulgated rules to address pipeline safety.
At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. Several states have also passed legislation or promulgated rules to address pipeline safety.
If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased 48 Table of Contents expenses or the curtailment of our oil and natural gas production.
If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production.
The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations related to the environment have 56 Table of Contents changed frequently and the changes often include increasingly stringent requirements.
The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations related to the environment have changed frequently and the changes often include increasingly stringent requirements.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2025.
In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, mitigation and notification, which could lead to increased regulatory compliance costs, insurance coverage cost or 66 Table of Contents capital expenditures.
In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, mitigation and notification, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures.
Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement, the San Mateo Credit Facility or otherwise may not be sufficient to fund all of our future capital expenditures or future acquisitions.
Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement, the San Mateo Credit 36 Table of Contents Facility or otherwise may not be sufficient to fund all of our future capital expenditures or future acquisitions.
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.
The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.35 billion.
San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities.
San Mateo’s ability to obtain additional 51 Table of Contents sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities.
For each of the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that collectively accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production.
For each of the years ended December 31, 2025, 2024 and 2023, we had three significant purchasers that collectively accounted for approximately 72%, 79% and 76%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production.
There can be no assurance that such changes in U.S. or foreign trade policy or in laws and policies governing foreign trade, and any resulting negative sentiments towards the United States as a result of such changes, would not materially and adversely affect our business, financial condition and results of operations.
There can be no assurance that such changes in U.S. or foreign trade policy or tariffs or in laws and policies governing foreign trade, and any resulting negative sentiments or retaliatory trade practices towards the United States as a result of such changes, would not materially and adversely affect our business, financial condition, results of operations and liquidity.
For a summary of these financial restrictions and other covenants in our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes, see Note 7 to the consolidated financial statements in this Annual Report.
For a summary of these financial restrictions and other covenants 43 Table of Contents in our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes, see Note 7 to the consolidated financial statements in this Annual Report.
Our cash flows from operations and access to capital are subject to a number of variables, including: • our estimated proved oil and natural gas reserves; • the amount of oil and natural gas we produce; • the prices at which we sell our production; • the costs of developing and producing our oil and natural gas reserves; • the costs of constructing, operating and maintaining our midstream facilities; 39 Table of Contents • our ability to attract third-party customers for our midstream services; • our ability to acquire, locate and produce new reserves; • the ability and willingness of banks or other financial institutions to lend to us; and • our ability to access the equity and debt capital markets.
Our cash flows from operations and access to capital are subject to a number of variables, including: • our estimated proved oil and natural gas reserves; • the amount of oil and natural gas we produce; • the prices at which we sell our production and prevailing basis differentials; • the costs of developing and producing our oil and natural gas reserves; • the costs of constructing, operating and maintaining our midstream facilities; • our ability to attract third-party customers for our midstream services; • our ability to acquire, locate and produce new reserves; • the ability and willingness of banks or other financial institutions to lend to us; and • our ability to access the equity and debt capital markets.
We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future.
We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production, acquiring new properties or securing necessary services and labor in this area and may experience such difficulty in other areas in the future.
In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event.
These protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity to the seismic event.
Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating to cybersecurity issues.
Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to 63 Table of Contents our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating to cybersecurity issues.
Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana.
Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas and the Haynesville shale in Northwest Louisiana.
The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural 52 Table of Contents gas and NGLs and the proximity of reserves to pipelines and terminal facilities.
The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities.
Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are 55 Table of Contents subject to change.
Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change.
In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 97% of our total oil and natural gas production for 2024 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin.
In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 98% of our total oil and natural gas production for 2025 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin.
Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. As of February 18, 2025, our directors and executive officers beneficially owned approximately 5.8% of our outstanding common stock.
Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. As of February 24, 2026, our directors and executive officers beneficially owned approximately 5.8% of our outstanding common stock.
On March 6, 2024, the SEC adopted new rules that require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements (the “SEC Climate Disclosure Rules”).
On March 6, 2024, the SEC adopted new rules that would require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and greenhouse gas emissions, information about 57 Table of Contents climate-related targets and goals, transition plans, if any, and extensive attestation requirements (the “SEC Climate Disclosure Rules”).
Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may 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.
Should we experience future periods of negative pricing for 39 Table of Contents 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.
Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and such ratings are used by some investors to inform their investment and voting decisions.
Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and such ratings are used by some investors to 61 Table of Contents inform their investment and voting decisions.
We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.
We may not be able to consummate those dispositions, and the proceeds of any such 41 Table of Contents disposition may not be adequate to meet any debt service obligations then due.
The listing of the dunes sagebrush lizard as endangered, participation in such candidate conservation agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows.
For example, our participation in candidate conservation agreements or the USFWS’s designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows.
See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms, floods and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the 49 Table of Contents inability to receive equipment or access personnel and products at affected job sites in a timely manner.
See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” Our operations may also be adversely affected by weather conditions and events such as floods, fires, tornadoes, droughts, hurricanes, tropical storms and severe cold weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner.
Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures being experienced throughout the United States and global economy may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.
Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures affecting the United States and global economy and the oil and natural gas industry may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.
Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2024, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $1.50 billion over the terms of the agreements.
Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2025, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $3.06 billion over the terms of the agreements.
We cannot predict what additional changes to trade policy will be made by the Trump administration or Congress, including whether existing tariff policies will be maintained or modified, what products may be subject to such policies or whether the entry into new bilateral or multilateral trade agreements will occur, nor can we predict the effects that any such changes would have on our business.
We cannot predict what additional changes to trade policy or tariffs will be made by the Trump administration, Congress or other governments, including whether existing or new tariff policies will be maintained or modified, what materials or products may be subject to such policies or whether the entry into new bilateral or multilateral trade agreements, or the amendment or termination of existing trade agreements, will occur, nor can we predict the effects that any such changes would have on our business.
For example, in the fourth quarter of 2024, we experienced temporary natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 3,000 BOE per day of less production.
For example, in the fourth quarter of 2025, we experienced temporary oil and natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 3,600 BOE per day of less production.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

6 edited+0 added−0 removed13 unchanged
Biggest changeThe Senior Vice President of Information Technology, the Executive Vice President and Chief Accounting Officer (“CAO”) and the Executive Vice President, General Counsel and Head of M&A (“GC”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year.
Biggest changeThe Senior Vice President of Information Technology, the Executive Vice President and Chief Financial Officer (“CFO”) and the Co-President, Chief Legal Officer and Head of M&A (“CLO”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year.
Oversee Third-Party Risk 67 Table of Contents Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement.
Oversee Third-Party Risk 64 Table of Contents Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement.
In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CAO and GC maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive.
In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CFO and CLO maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive.
Risks from Cybersecurity Threats As of February 18, 2025, we were not aware of any cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations or financial standing.
Risks from Cybersecurity Threats As of February 24, 2026, we were not aware of any cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations or financial standing.
Reporting to the Board The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and GC of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the 68 Table of Contents cybersecurity posture and potential risks facing the Company.
Reporting to the Board The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and Chief Legal Officer of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the cybersecurity posture and potential risks facing the Company.
Furthermore, significant cybersecurity matters and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues. Monitor Cybersecurity Incidents The Senior Vice President of Information Technology monitors the latest developments in cybersecurity, including potential threats and innovative risk management techniques.
Furthermore, significant cybersecurity matters and 65 Table of Contents strategic risk management decisions are escalated to the Board, ensuring the Board has comprehensive oversight and can provide guidance on critical cybersecurity issues. Monitor Cybersecurity Incidents The Senior Vice President of Information Technology monitors the latest developments in cybersecurity, including potential threats and innovative risk management techniques.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+3 added−6 removed4 unchanged
Biggest changeFor a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. 70 Table of Contents Share Performance Graph The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2019 through December 31, 2024, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period.
Biggest changeEquity Compensation Plan Information Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” in Part III, Item 12 of this Annual Report and is incorporated herein by reference. 67 Table of Contents Share Performance Graph The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2020 through December 31, 2025, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period.
Dividends In each of the first, second and third quarters of 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.
Dividends In each of the first, second and third quarters of 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.
Prior to trading on the NYSE, there was no established public trading market for our common stock. On February 18, 2025, we had 125,207,212 shares of common stock outstanding held by approximately 396 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
Prior to trading on the NYSE, there was no established public trading market for our common stock. On February 24, 2026, we had 124,249,941 shares of common stock outstanding held by approximately 444 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
Comparison of Cumulative Total Return Among Matador Resources Company, the Russell 2000 Index and the Russell 2000 Energy Index 71 Table of Contents Repurchase of Equity by the Company or Affiliates During the quarter ended December 31, 2024, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
Comparison of Cumulative Total Return Among Matador Resources Company, the Russell 2000 Index and the Russell 2000 Energy Index 68 Table of Contents Repurchase of Equity by the Company or Affiliates The following table contains information about our acquisition of common stock during the quarter ended December 31, 2025.
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.
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. We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
Removed
We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future. Equity Compensation Plan Information The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2024.
Added
Period Total Number of Shares Purchased (1)(2) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2) Maximum Number (or Approximate Dollar Value in thousands) of Shares that May Yet Be Purchased under the Plans or Programs (2) October 1, 2025 to October 31, 2025 98,564 $ 44.41 98,500 344,916 November 1, 2025 to November 30, 2025 20,402 38.28 20,000 344,150 December 1, 2025 to December 31, 2025 394 45.22 — 344,150 Total 119,360 $ 43.36 118,500 _________________ (1) During the fourth quarter of 2025, the Company re-acquired 860 shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
Removed
Equity Compensation Plan Information Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans Equity compensation plans approved by security holders (1)(2)(3) 1,090,557 $ 14.80 7,850,907 Equity compensation plans not approved by security holders — — — Total 1,090,557 $ 14.80 7,850,907 __________________ (1) Our Board has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).
Added
(2) In April 2025, the Board approved the Share Repurchase Program authorizing the repurchase of up to $400.0 million of common stock.
Removed
(2) The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report.
Added
During the fourth quarter of 2025, the Company repurchased 118,500 shares of common stock under the Share Repurchase Program at a weighted average price of $43.38 per common share for a total cost of $5.1 million, excluding accrued excise tax of $0.1 million. 69 Table of Contents
Removed
(3) The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board in April 2022 and approved by our shareholders on June 10, 2022.
Removed
Period Total Number of Shares Purchased (1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs October 1, 2024 to October 31, 2024 41,958 $ 54.68 — — November 1, 2024 to November 30, 2024 99 52.11 — — December 1, 2024 to December 31, 2024 638 57.03 — — Total 42,695 $ 54.71 — — _________________ (1) The shares were not re-acquired pursuant to any repurchase plan or program.
Removed
The Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock. 72 Table of Contents

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

151 edited+15 added−46 removed70 unchanged
Biggest changeYear Ended December 31, 2024 2023 2022 (In thousands, except expenses per BOE) Expenses: Production taxes, transportation and processing $ 306,751 $ 264,493 $ 282,193 Lease operating 341,544 243,655 157,105 Plant and other midstream services operating 171,492 128,910 95,522 Purchased natural gas 142,715 129,401 178,937 Depletion, depreciation and amortization 974,300 716,688 466,348 Accretion of asset retirement obligations 6,027 3,943 2,421 General and administrative 127,454 110,373 116,229 Total expenses 2,070,283 1,597,463 1,298,755 Operating income 1,434,698 1,209,322 1,759,270 Other income (expense): Net loss on asset sales and impairment — (202) (1,311) Interest expense (171,687) (121,520) (67,164) Other income (expense) 696 8,785 (5,121) Total other expense (170,991) (112,937) (73,596) Income before income taxes 1,263,707 1,096,385 1,685,674 Income tax provision (benefit) Current 27,059 13,922 54,877 Deferred 265,305 172,104 344,480 Total income tax provision 292,364 186,026 399,357 Net income attributable to non-controlling interest in subsidiaries (86,021) (64,285) (72,111) Net income attributable to Matador Resources Company shareholders $ 885,322 $ 846,074 $ 1,214,206 Expenses per BOE: Production taxes, transportation and processing $ 4.91 $ 5.50 $ 7.33 Lease operating $ 5.47 $ 5.06 $ 4.08 Plant and other midstream services operating $ 2.74 $ 2.68 $ 2.48 Depletion, depreciation and amortization $ 15.59 $ 14.90 $ 12.11 General and administrative $ 2.04 $ 2.29 $ 3.02 Year Ended December 31, 2024 as Compared to Year Ended December 31, 2023 Production taxes, transportation and processing.
Biggest changeYear Ended December 31, 2025 2024 2023 (In thousands, except expenses per BOE) Expenses: Lease operating $ 415,810 $ 325,145 $ 232,521 Transportation and processing 66,787 58,593 59,912 Midstream operating 208,142 167,400 124,021 Purchased natural gas 163,094 142,715 129,401 Depletion, depreciation and amortization 1,195,358 974,300 716,688 Taxes other than income 275,629 268,649 220,604 Accretion of asset retirement obligations 7,846 6,027 3,943 General and administrative 137,069 127,454 110,373 Total expenses 2,469,735 2,070,283 1,597,463 Operating income 1,226,542 1,434,698 1,209,322 Other income (expense): Net loss on asset sales and impairment (589) — (202) Interest expense (208,520) (171,687) (121,520) Other income 16,011 696 8,785 Total other expense (193,098) (170,991) (112,937) Income before income taxes 1,033,444 1,263,707 1,096,385 Income tax provision (benefit) Current 7,088 27,059 13,922 Deferred 165,587 265,305 172,104 Total income tax provision 172,675 292,364 186,026 Net income attributable to non-controlling interest in subsidiaries (101,548) (86,021) (64,285) Net income attributable to Matador Resources Company shareholders $ 759,221 $ 885,322 $ 846,074 Expenses per BOE: Lease operating $ 5.50 $ 5.20 $ 4.83 Transportation and processing $ 0.88 $ 0.94 $ 1.25 Midstream operating $ 2.75 $ 2.68 $ 2.58 Depletion, depreciation and amortization $ 15.82 $ 15.59 $ 14.90 Taxes other than income $ 3.65 $ 4.30 $ 4.59 General and administrative $ 1.81 $ 2.04 $ 2.29 Year Ended December 31, 2025 as Compared to Year Ended December 31, 2024 Lease operating expenses.
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 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 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 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.
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.
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.
If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
If capital expenditures were to exceed our operating cash flows in 2026, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
As of December 31, 2024, 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.
As of December 31, 2025, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures.
See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” 82 Table of Contents Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below.
See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” 78 Table of Contents Our cash flows for the years ended December 31, 2025, 2024 and 2023 are presented below.
In connection with the Pronto Transaction, we dedicated to Pronto our current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements with Pronto whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico.
In connection with the Pronto Transaction, we dedicated to San Mateo our current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements with San Mateo whereby San Mateo will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico.
Interest expense on the $750.0 million of outstanding 2033 Notes as of December 31, 2024 is expected to be approximately $46.9 million each year until maturity. (3) At December 31, 2024, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.
Interest expense on the $750.0 million of outstanding 2033 Notes as of December 31, 2025 is expected to be approximately $46.9 million each year until maturity. (3) At December 31, 2025, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.
Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may 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.
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.
This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base.
This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the depletable base.
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 a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below.
Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2026 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below.
We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2024.
We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2025.
At both December 31, 2024 and December 31, 2023, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
At both December 31, 2025 and December 31, 2024, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
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.
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.
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.
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.
A significant portion of our anticipated cash flows from operations for 2025 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin.
A significant portion of our anticipated cash flows from operations for 2026 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin.
Revenues associated with NGLs are included with our natural gas revenues. (2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Year Ended December 31, 2024 as Compared to Year Ended December 31, 2023 Oil and natural gas revenues .
Revenues associated with NGLs are included with our natural gas revenues. (2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Year Ended December 31, 2025 as Compared to Year Ended December 31, 2024 Oil and natural gas revenues .
Certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.
Certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social 83 Table of Contents and environmental considerations.
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.
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.
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.
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.
Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2024 is expected to be approximately $34.4 million each year until maturity. Interest expense on the $900.0 million of outstanding 2032 Notes as of December 31, 2024 is expected to be approximately $58.5 million each year until maturity.
Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2025 is expected to be approximately $34.4 million each year until maturity. Interest expense on the $900.0 million of outstanding 2032 Notes as of December 31, 2025 is expected to be approximately $58.5 million each year until maturity.
Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 89 Table of Contents Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues.
Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues.
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.
Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties 73 Table of Contents whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers.
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 and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth.
The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt, the payment of cash dividends, if any, the repurchase of our common stock, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2025.
NGL prices were also lower in 2024 as compared to 2023, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2024.
NGL prices were also lower in 2025 as compared to 2024, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2025.
At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
At December 31, 2025, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production 88 Table of Contents declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions.
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.
Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.
Capitalized costs of oil and natural gas properties are depleted using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the depletable base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.
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. 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 includes an accordion feature, which provides for potential increases in lender commitments of up to $1.35 billion. The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property.
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.
In addition, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices.
See “Cautionary Note Regarding Forward-Looking Statements.” For a comparison of our results of operations for the years ended December 31, 2023 and December 31, 2022, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 27, 2024.
See “Cautionary Note Regarding Forward-Looking Statements.” For a comparison of our results of operations for the years ended December 31, 2024 and December 31, 2023, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 25, 2025.
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.
Substantially all of our 2025 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.
Our 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.
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.
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.
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.
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.
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.
Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.
Exploratory dry holes are included in the depletable base immediately upon the determination that the well is not productive.
During the year ended December 31, 2024, we realized gains on our natural gas basis differential derivative contracts of approximately $12.7 million resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts.
During the year ended December 31, 2025, we realized gains on our natural gas basis differential derivative contracts of approximately $21.7 million resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts.
See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. 85 Table of Contents Obligations and Commitments We had the following material contractual obligations and commitments at December 31, 2024.
See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. Obligations and Commitments We had the following material contractual obligations and commitments at December 31, 2025.
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 remain at their current levels or 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.
We have at times experienced inflation in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells.
For the year ended December 31, 2024, natural gas prices averaged $2.40 per MMBtu, as compared to $2.66 per MMBtu in 2023, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
For the year ended December 31, 2025, natural gas prices averaged $3.62 per MMBtu, as compared to $2.40 per MMBtu in 2024, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved.
Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. 84 Table of Contents Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment.
Our 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. Interest expense.
Our general and administrative expenses on a unit-of-production basis decreased 11% to $1.81 per BOE for the year ended December 31, 2025, as compared to $2.04 per BOE for the year ended December 31, 2024, primarily as a result of the 21% increase in our total oil equivalent production between the two periods. Interest expense.
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 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.
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.
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.
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.
The increase in natural gas revenues resulted from a 23% increase in natural gas production for the year ended December 31, 2025 noted above, which was partially offset by a decrease in our weighted average realized natural gas price of $2.08 per Mcf in 2025, as compared to $2.38 per Mcf in 2024.
We realized a weighted average oil price of $75.89 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2024, as compared to $77.88 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2023.
We realized a weighted average oil price of $64.99 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2025, as compared to $75.89 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2024.
At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included: • 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; • 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 • 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. 75 Table of Contents 2025 Capital Expenditure Budget 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.
At December 31, 2025, San Mateo’s midstream system included: • Natural Gas Assets : 720 MMcf per day of designed natural gas cryogenic processing capacity and approximately 340 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico; • Oil Assets : three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 120 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and • Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 195 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas. 71 Table of Contents 2026 Capital Expenditure Budget We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2026.
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.
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.
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.
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.
Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, ongoing military conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, oil and natural gas price differentials and other factors.
Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, ongoing military conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors.
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 $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.
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.
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.
We realized a weighted average natural gas price of $2.38 per Mcf ($2.47 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2024, as compared to $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2023.
We realized a weighted average natural gas price of $2.08 per Mcf ($2.20 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2025, as compared to $2.38 per Mcf ($2.47 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2024.
At 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).
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 believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024. In February 2024, April 2024 and July 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock.
San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2025. In February 2025, April 2025 and July 2025, our Board declared quarterly cash dividends of $0.3125 per share of common stock.
Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 million, which was primarily associated with San Mateo.
Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. At December 31, 2025, we had cash totaling $15.3 million and restricted cash totaling $64.2 million, which was primarily associated with San Mateo.
Oil production comprised 58% and 57% of our total production for the years ended December 31, 2024 and 2023, respectively. 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.
Oil production comprised 58% of our total production for each of the years ended December 31, 2025 and 2024. For the year ended December 31, 2025, our oil and natural gas revenues were $3.24 billion, an increase of 3% from oil and natural gas revenues of $3.14 billion for the year ended December 31, 2024.
At December 31, 2024 San Mateo had $615.0 million of 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. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029.
At December 31, 2025, San Mateo had $883.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029.
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. 78 Table of Contents Expenses The following table summarizes our operating expenses and other income (expense) for the periods indicated.
During the year ended December 31, 2024, the aggregate net fair value of our open oil and natural gas derivative contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. 74 Table of Contents Expenses The following table summarizes our operating expenses and other income (expense) for the periods indicated.
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.
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.
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, 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.
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.
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.
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.
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.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” Net Cash Used in Investing Activities Net cash used in investing activities 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.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” Net Cash Used in Investing Activities Net cash used in investing activities decreased by $1.51 billion to $2.16 billion for the year ended December 31, 2025 from $3.67 billion for the year ended December 31, 2024.
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 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.
Assuming the amounts outstanding and interest rates of 6.19% and 6.44%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2024, the interest expense for such facilities is expected to be approximately $37.4 million and $40.2 million, respectively, each year until maturity. (2) The amounts included in the table above represent principal maturities only.
Assuming the amounts outstanding and interest rates of 5.63% and 5.72%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2025, the interest expense for such facilities is expected to be approximately $22.4 million and $50.5 million, respectively, each year until maturity. (2) The amounts included in the table above represent principal maturities only.
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 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 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.
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.
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.
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.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” For the year ended December 31, 2024, oil prices averaged $75.76 per Bbl, as compared to $77.60 per Bbl in 2023, ranging from a high of $86.91 per Bbl in early April to a low of $65.75 per Bbl in mid-September, based upon the WTI oil futures contract price for the earliest delivery date.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” For the year ended December 31, 2025, oil prices averaged $64.73 per Bbl, as compared to $75.76 per Bbl in 2024, ranging from a high of $80.04 per Bbl in mid-January to a low of $55.27 per Bbl in mid-December, based upon the WTI oil futures contract price for the earliest delivery date.
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.
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.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” At December 31, 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.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” At December 31, 2025, our estimated total proved oil and natural gas reserves were 667.0 million BOE, including 376.0 million Bbl of oil and 1.75 Tcf of natural gas, with a Standardized Measure of $6.99 billion and a PV-10 of $8.24 billion.
We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024. 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.
We were in compliance with the terms of the Credit Agreement at December 31, 2025. At December 31, 2025, San Mateo had $883.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.
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.
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.
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.
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.
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.
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.
For example, the recent election of President Trump and a Republican-controlled Congress may alter our current regulatory framework and 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.
For example, the current administration and Congress have altered, and may continue to alter, our current regulatory framework and may impact our business and the oil and natural gas industry generally. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations.
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.
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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeAt December 31, 2024, we had various costless collar contracts open and in place to mitigate our exposure to oil price volatility, each with an established price floor and ceiling.
Biggest changeAdditionally, we have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments. At December 31, 2025, we had various costless collar contracts open and in place to mitigate our exposure to oil price volatility, each with an established price floor and ceiling.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. Such information is incorporated herein by reference. Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2025. Such information is incorporated herein by reference. Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use.
In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative 91 Table of Contents arrangements in the future.
In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. 86 Table of Contents In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.
We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play.
We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin and the Haynesville shale play.
At December 31, 2024, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. We had no open contracts associated with NGL prices at December 31, 2024.
At December 31, 2025, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. We had no open contracts associated with NGL prices at December 31, 2025.
In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities.
In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. We record all derivative financial instruments at fair value, which is determined using purchase and sale information available for similarly traded securities.
At December 31, 2024, we had $595.5 million of outstanding borrowings under our Credit Agreement at an interest rate of 6.19%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875%, $900.0 million of outstanding 2032 Notes at a coupon rate of 6.500%, $750.0 million of outstanding 2033 Notes at a coupon rate of 6.250% and $615.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 6.44%.
At December 31, 2025, we had $398.0 million of outstanding borrowings under our Credit Agreement at an interest rate of 5.63%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875%, $900.0 million of outstanding 2032 Notes at a coupon rate of 6.500%, $750.0 million of outstanding 2033 Notes at a coupon rate of 6.250% and $883.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 5.72%.
The counterparties on our derivative financial instruments in place at February 18, 2025 were Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof), which are all lenders under our Credit Agreement. Impact of inflation .
The counterparties on our derivative financial instruments in place at February 24, 2026 were Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank, BOKF (or affiliates thereof), The Toronto Dominion Bank, J.P. Morgan Chase Bank and Wells Fargo Bank, which are all lenders under our Credit Agreement. Impact of inflation .
Inflation in the United States has become much more significant in recent years. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward.
Although inflation in the U.S. softened in 2024 and 2025, prices for many services, materials and equipment have remained elevated relative to pre-2022 levels. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward.
Removed
At December 31, 2024, Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof) were the counterparties for our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments.

Other MTDR 10-K year-over-year comparisons