Matador Resources Co (MTDR) Business

Item 1. Business.

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. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.

General

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

We are a Texas corporation founded in July 2003 by Joseph Wm. 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

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Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million.

On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.

Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. 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.

The successful execution of our business strategies led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2025. 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”). We also secured firm transportation on Energy Transfer’s Hugh Brinson Pipeline, which is expected to come online in the fourth quarter of 2026, to move 500,000 MMBtu per day of natural gas production out of the Permian Basin to East Texas and markets along the Gulf Coast where demand and pricing have historically been significantly higher than at the Waha Hub.

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.

San Mateo also achieved important milestones in 2025, including the construction of an additional natural gas processing plant with a designed inlet capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, to expand its Marlan cryogenic natural gas processing plant (the “Marlan Processing Plant”). The Marlan Processing Plant expansion came online in the second quarter of 2025 and increased San Mateo’s total natural gas cryogenic processing capacity 38% to 720 MMcf per day.

2025 Highlights

Increased Oil, Natural Gas and Oil Equivalent Production

For the year ended December 31, 2025, we achieved record oil, natural gas and average daily oil equivalent production. In 2025, we produced 43.7 million Bbl of oil, an increase of 20%, as compared to 36.5 million Bbl of oil produced in 2024. We also produced 191.3 Bcf of natural gas, an increase of 23% from 155.8 Bcf of natural gas produced in 2024. Our average daily oil equivalent production for the year ended December 31, 2025 was 207,070 BOE per day, including 119,723 Bbl of oil per day and 524.1 MMcf of natural gas per day, an increase of 21%, as compared to 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, for the year ended December 31, 2024. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2025, which offset our declining production in the Eagle Ford shale in South Texas that was divested in the first quarter of 2025. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2025 and 2024.

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Increased Oil, Natural Gas and Oil Equivalent Reserves

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, an increase of 9% from 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, at December 31, 2024. The Standardized Measure of our total proved oil and natural gas reserves decreased 5% from $7.38 billion at December 31, 2024 to $6.99 billion at December 31, 2025. The PV-10 of our total proved oil and natural gas reserves decreased 11% from $9.23 billion at December 31, 2024 to $8.24 billion at December 31, 2025. 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. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”

At December 31, 2025, estimated proved developed reserves included 223.0 million Bbl of oil and 1.11 Tcf of natural gas, and estimated proved undeveloped reserves included 153.0 million Bbl of oil and 636.6 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 61% and 56%, respectively, of our total proved oil and natural gas reserves at December 31, 2025. Proved developed reserves and proved oil reserves comprised 60% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2024.

Operational Highlights

We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. 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.

We completed and began producing oil and natural gas from 258 gross (129.3 net) horizontal wells in the Delaware Basin in 2025, including 151 gross (121.2 net) operated and 107 gross (8.1 net) non-operated wells. At December 31, 2025, our total acreage position in the Delaware Basin was approximately 354,600 gross (212,500 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving, Ward and Winkler Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. We expect our Delaware Basin production to increase in 2026 as we continue the delineation and development of these asset areas.

During 2025, we achieved several operational highlights in the Delaware Basin. These highlights (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) included:

•improved well performance and cost efficiencies through large-scale batch developments. For example, during the second half of 2025, we turned to sales a 17-well batch development, one of the largest developments in our history, on our John Callahan unit in the Antelope Ridge asset area in Lea County, New Mexico targeting multiple horizons in the Bone Springs and Wolfcamp formations;

•reduced drilling and completion costs per lateral foot, including increased efficiencies and capital savings through the continued use of Simul-Frac and Trimul-Frac;

•continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2025 of approximately 10,400 feet; and

•capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) for 2025 of $1.53 billion, which was within our estimated range for 2025 D/C/E capital expenditures of $1.47 to $1.55 billion, as provided on October 21, 2025.

Capital 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;

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•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’.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information.

Midstream Highlights

Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point.

San Mateo achieved strong operating results in 2025, highlighted by (i) free cash flow generation, (ii) expansion of the Marlan Processing Plant (iii) increased midstream services revenues, including those from third-party customers, and (iv) increased natural gas gathering and processing volumes.

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. (“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.

Sustainability Practices

We are committed to creating value for our shareholders in a responsible manner. Our aim is to reliably and profitably provide the oil and gas that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and the highest applicable regulatory and legal standards. We also communicate our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by the Sustainability Accounting Standards Board (SASB).

Highlights from our sustainability efforts are noted below. The data utilized in calculating the below metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. The emissions-related metrics for 2025 were not readily available prior to the filing of this Annual Report and, therefore, are presented as related to our 2024 operations. As of the date of this Annual Report, we are not aware of any material changes to the emissions-related metrics subsequent to the publishing of the 2024 Sustainability Report, assuming the calculation methodology remains consistent for the 2025 reporting year. All other metrics are presented as related to our 2025 operations. The metrics reflect both Matador’s gross operated exploration and production operations and gross operated midstream operations (which includes San Mateo) on a consolidated basis, except where otherwise noted or immaterial in scope.

•decreased Matador’s direct greenhouse gas emissions intensity by 65% in 2024, as compared to 2019;

•decreased Matador’s methane emissions intensity by 88% in 2024, as compared to 2019;

•decreased Matador’s flaring intensity by 84% in 2024, as compared to 2019;

•utilized non-fresh water in 98% of total water consumption in 2025;

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•utilized recycled produced water for 72% of total water consumption in hydraulic fracturing operations in 2025;

•transported 99% of operated produced water and 97% of operated produced oil by pipeline in 2025; and

•provided approximately 26,800 hours of employee continuing education, equating to approximately 56 hours per employee in 2025.

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. 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.

The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2025.

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(1)Identified and engineered drilling 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. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2025, approximately 76% of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 91% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2025, these engineered drilling locations included 522 gross (255 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon and Avalon formations, in the Delaware Basin. 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. For additional information regarding our oil and natural gas reserves, see “—Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.

(3)Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon, Yeso and Avalon plays on our acreage in the Delaware Basin at December 31, 2025.

(5)During the first quarter of 2025, the Company sold its remaining South Texas assets in the Eagle Ford shale.

(6)Includes the Cotton Valley formation and shallower zones.

(7)Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana. This total includes acreage that we are producing from or that we believe to be prospective for these formations.

We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2025, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2025, we also operated approximately 51% of our Northwest Louisiana acreage.

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

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effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.

Southeast New Mexico and West Texas — Delaware Basin

The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations.

In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.

At December 31, 2025, our total acreage position in Southeast New Mexico and West Texas was approximately 354,600 gross (212,500 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving, Ward and Winkler Counties, Texas. These acreage totals included approximately 75,200 gross (42,800 net) acres in our Ranger asset area in Lea County, 61,400 gross (26,300 net) acres in our Arrowhead asset area in Eddy County, 47,000 gross (26,600 net) acres in our Rustler Breaks asset area in Eddy County, 77,000 gross (59,000 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 57,000 gross (32,100 net) acres in our Twin Lakes asset area in Lea County and 33,500 gross (22,300 net) acres in our West Texas asset area in Loving, Ward and Winkler Counties at December 31, 2025. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2025, our acreage position in the Delaware Basin was approximately 81% held by existing production. Excluding the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 90% held by existing production at December 31, 2025.

During the year ended December 31, 2025, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 258 gross (129.3 net) horizontal wells in the Delaware Basin, including 151 gross (121.2 net) operated horizontal wells and 107 gross (8.1 net) non-operated horizontal wells, throughout our various asset areas. 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.

At December 31, 2025, approximately 99% of our estimated total proved oil and natural gas reserves, or 662.2 million BOE, was attributable to the Delaware Basin, including approximately 376.0 million Bbl of oil and 1.72 Tcf of natural gas, a 9% increase, as compared to 606.2 million BOE for the year ended December 31, 2024. Our Delaware Basin proved reserves at December 31, 2025 and 2024 comprised approximately 100% of our proved oil reserves and 98% of our proved natural gas reserves.

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. At December 31, 2025, these locations had a total net lateral length of approximately 19.1 million feet, or 3,801 miles, an increase of 4% as compared to the total net lateral length of approximately 18.3 million feet, or 3,680 miles, as of December 31, 2024. These locations include 2,492 gross (1,599 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2025, approximately 76% of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 91% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. 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

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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. 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. 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. At December 31, 2025, these potential future drilling locations included 522 gross (255 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon and Avalon, to which we have assigned proved undeveloped reserves.

Antelope Ridge Asset Area - Lea County, New Mexico

In the Antelope Ridge asset area, we turned to sales 84 gross (73.2 net) operated wells and 27 gross (0.5 net) non-operated wells during 2025.

In the second half of 2025, we turned to sales 17 gross (13.7 net) operated wells on our John Callahan unit in the Antelope Ridge asset area in Lea County, which is one of the largest developments in our history. These wells, which included four First Bone Spring, three Third Bone Spring, one Third Bone Spring Carbonate, three Wolfcamp A-XY, three Wolfcamp A and three Wolfcamp B completions, have produced in aggregate approximately 2.1 million BOE in approximately four months of production. These 17 wells had average completed lateral lengths of approximately 10,300 feet.

We turned to sales an additional 67 gross (59.5 net) operated Antelope Ridge wells. These 67 wells, which included six First Bone Spring, six Second Bone Spring, 12 Third Bone Spring, eight Third Bone Spring Carbonate, 20 Wolfcamp A-XY, eight Wolfcamp A and seven Wolfcamp B completions, have produced in aggregate approximately 9.0 million BOE in an average of approximately seven months of production. These 67 wells had average completed lateral lengths of approximately 10,600 feet.

Ranger and Twin Lakes Asset Areas - Lea County, New Mexico

In the Ranger asset area, we turned to sales nine gross (7.5 net) operated wells and 22 gross (2.8 net) non-operated wells during 2025.

In total, these nine Ranger operated wells, which included five Second Bone Spring and four Wolfcamp D completions, have produced in aggregate approximately 0.7 million BOE in an average of approximately five months of production. These nine wells had average completed lateral lengths of approximately 10,600 feet.

In the Twin Lakes asset area, we turned to sales one gross (0.5 net) operated well, and we did not turn to sales or participate in any non-operated wells during 2025.

Arrowhead Asset Area - Eddy County, New Mexico

We turned to sales 22 gross (12.0 net) operated wells in the Arrowhead asset area during 2025. These wells, which included 14 Second Bone Spring and eight Wolfcamp A-XY completions, have produced in aggregate approximately 5.5 million BOE in approximately seven months of production. These 22 wells had average completed lateral lengths of approximately 10,000 feet.

We also turned to sales 21 gross (2.4 net) non-operated wells in the Arrowhead asset area during 2025.

Rustler Breaks Asset Area - Eddy County, New Mexico

We turned to sales 26 gross (19.3 net) operated wells in the Rustler Breaks asset area during 2025. In total, these 26 Rustler Breaks wells, which included seven First Bone Spring, five Second Bone Spring, four Third Bone Spring, six Third Bone Spring Carbonate, three Wolfcamp A-XY and one Wolfcamp B completions, have produced in aggregate approximately 4.3 million BOE in an average of approximately six months of production. These 26 wells had average completed lateral lengths of approximately 10,100 feet.

We also turned to sales 36 gross (2.2 net) non-operated wells in the Rustler Breaks asset area during 2025.

Stateline Asset Area - Eddy County, New Mexico

We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in the Stateline asset area during 2025.

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West Texas Asset Area - Loving, Ward and Winkler Counties, Texas

We turned to sales nine gross (8.7 net) operated wells in the West Texas asset area during 2025. In total, these nine West Texas wells, which included two Third Bone Spring, one Wolfcamp A and six Wolfcamp B completions, have produced in aggregate approximately 0.4 million BOE in approximately three months of production. These nine wells had average completed lateral lengths of approximately 10,100 feet.

We also turned to sales one gross (0.2 net) non-operated well in the West Texas asset area during 2025.

South Texas — Eagle Ford Shale and Other Formations

During the first quarter of 2025, the Company sold its remaining South Texas assets in the Eagle Ford shale for $22.2 million.

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.

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. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. 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.

For the year ended December 31, 2025, approximately 2% of our average daily oil equivalent production, or 3,635 BOE per day, including one Bbl of oil per day and 21.8 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2024, approximately 2% of our average daily oil equivalent production, or 3,492 BOE per day, including three Bbl of oil per day and 21.0 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2025, approximately 4% of our daily natural gas production, or 21.8 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2024, approximately 5% of our daily natural gas production, or 21.0 MMcf of natural gas per day, was attributable to these properties. At December 31, 2025, less than 1% of our estimated total proved reserves, or 4.8 million BOE, was attributable to our properties in Northwest Louisiana.

Midstream Segment

Our midstream segment conducts midstream operations in support of, and provides flow assurance for, our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

Southeast New Mexico and West Texas — Delaware Basin

On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area; and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and earned all of the potential $73.5 million in performance incentives through January 31, 2023. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement.

On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. 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

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incentives through September 30, 2024. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements.

Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area.

On June 30, 2022, we acquired Pronto, including the Marlan Processing Plant (prior to expansion), three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico.

On April 13, 2023, we completed the Advance Acquisition, which included one commercial salt water disposal well, approximately 28 miles of water gathering assets and approximately 17 miles of natural gas gathering pipelines.

On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of natural gas gathering, water gathering and oil transportation and gathering pipeline assets.

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. In addition, we have the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period, of which $13.0 million and $1.3 million was paid by Five Point during the years ended December 31, 2025 and 2024, respectively. San Mateo continues to be owned 51% by us and 49% by Five Point.

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. In addition, San Mateo entered into certain agreements with Northwind Midstream Partners LLC (“Northwind”), previously an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by San Mateo in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from San Mateo and other third-party customers to San Mateo for processing.

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. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks.

In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. 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. The Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area.

In March 2024, we completed our natural gas pipeline connections between Pronto and the Black River Gathering System and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas.

Subsequent to the Pronto Transaction, San Mateo now owns and operates the expanded Marlan Processing Plant, which has a designed inlet capacity of 260 MMcf of natural gas per day, and operates Pronto’s six compressor stations and approximately 150 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. The expanded Marlan Processing Plant came online in the second quarter of 2025 and increased San Mateo’s total natural gas cryogenic processing capacity to 720 MMcf of natural gas per day.

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). At December 31, 2025, San Mateo was gathering or transporting almost all our operated natural gas

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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.

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. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise.

In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines.

At December 31, 2025, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2025, San Mateo gathered an average of approximately 517 MMcf of natural gas per day, an increase of 21% as compared to 426 MMcf of natural gas per day gathered during the year ended December 31, 2024. In addition, during the year ended December 31, 2025, San Mateo processed approximately 502 MMcf of natural gas per day at the Black River Processing Plant, an increase of 25%, as compared to 403 MMcf of natural gas per day processed during the year ended December 31, 2024.

Crude Oil Gathering and Transportation Assets

San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.

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. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2025, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline.

At December 31, 2025, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2025, the San Mateo Oil Pipeline Systems had throughput of approximately 52,900 Bbl of oil per day, an increase of 1%, as compared to throughput of approximately 52,600 Bbl of oil per day during the year ended December 31, 2024.

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. At December 31, 2025, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day. In addition, at December 31, 2025, Matador had three commercial salt water disposal wells and associated facilities with a designed inlet capacity of 87,500 Bbl of produced water per day.

During the year ended December 31, 2025, San Mateo handled approximately 418,000 Bbl of produced water per day, a decrease of 10%, as compared to approximately 462,400 Bbl of produced water per day handled during the year ended December 31, 2024, primarily due to lower volumes from Matador and third-party customers.

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Northwest Louisiana

In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. 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.

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(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2025 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.

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(1)Includes 41 gross (32.3 net) wells from the Eagle Ford formation that were divested in the first quarter of 2025.

(2)Includes the Cotton Valley formation and shallower zones.

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(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes midstream operating expenses, ad valorem taxes and oil and natural gas production taxes.

The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2024 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.

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(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.

(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes midstream operating expenses, ad valorem taxes and oil and natural gas production taxes.

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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.

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(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.

(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023.

(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Excludes impact of derivative settlements.

(5)Excludes midstream operating expenses, ad valorem taxes and oil and natural gas production taxes.

Our total oil equivalent production of approximately 75.6 million BOE for the year ended December 31, 2025 increased 21% from our total oil equivalent production of approximately 62.5 million BOE for the year ended December 31, 2024. This increased production was primarily attributable to our delineation and development operations in the Delaware Basin throughout 2025, which offset our declining production in the Eagle Ford shale that was divested in the first quarter of 2025. Our average daily oil equivalent production for the year ended December 31, 2025 was 207,070 BOE per day, as compared to 170,751 BOE per day for the year ended December 31, 2024. Our average daily oil production for the year ended December 31, 2025 was 119,723 Bbl of oil per day, an increase of 20% from 99,808 Bbl of oil per day for the year ended December 31, 2024. Our average daily natural gas production for the year ended December 31, 2025 was 524.1 MMcf of natural gas per day, an increase of 23% from 425.7 MMcf of natural gas per day for the year ended December 31, 2024.

Our total oil equivalent production of approximately 62.5 million BOE for the year ended December 31, 2024 increased 30% from our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023. 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. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, as compared to 131,813 BOE per day for the year ended December 31, 2023. Our average daily oil production for the year ended December 31, 2024 was 99,808 Bbl of oil per day, an increase of 32% from 75,457 Bbl of oil per day for the year ended December 31, 2023. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf of natural gas per day, an increase of 26% from 338.1 MMcf of natural gas per day for the year ended December 31, 2023.

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Producing Wells

The following table sets forth information relating to producing wells at December 31, 2025. 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%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells.

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(1)Includes 199 gross (76.4 net) vertical wells that were primarily acquired in multiple transactions.

(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. Where we produce liquids-rich natural gas, primarily in the Delaware Basin, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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(1)Numbers in table may not total due to rounding.

(2)Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2025 were $61.82 per Bbl for oil and $3.39 per MMBtu for natural gas, for the 12 months ended December 31, 2024 were $71.96 per Bbl for oil and $2.13 per MMBtu for natural gas and for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.

(3)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(4)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

(5)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. 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. 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. The discounted future income taxes at December 31, 2025, 2024 and 2023 were $1.25 billion, $1.86 billion and $1.59 billion, respectively.

Our estimated total proved oil and natural gas reserves increased 9% from 611.5 million BOE at December 31, 2024 to 667.0 million BOE at December 31, 2025. Our proved oil and natural gas reserves increased by 131.1 million BOE and we produced 75.6 million BOE during the year ended December 31, 2025. This increase in proved oil and natural gas reserves was primarily attributable to our delineation and development operations in the Delaware Basin during 2025. We increased our total proved oil and natural gas reserves by 3.3 million BOE as a result of acquisitions, divestitures and trades during 2025. We also added 135.0 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2025, of which 23.0 million BOE resulted from new well locations turned to sales during 2025 to establish proved developed reserves and 112.0 million BOE resulted from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2025. Additionally, we realized approximately 7.2 million BOE in net downward revisions of prior estimates of proved reserves in 2025, which primarily included the removal of 22.8 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin, and 5.6 million BOE resulting from pricing updates, including the 14% decrease in oil prices, which was partially offset by the 59% increase in natural gas prices used to estimate total proved reserves at December 31, 2025, as compared to December 31, 2024, and 2.9 million BOE in expense updates. As we continue to develop our Delaware Basin assets, we may reclassify some or all of the 22.8 million BOE to proved reserves at a future date. These downward revisions at December 31, 2025 were partially offset by positive forecast updates of 24.1 million BOE.

Our proved oil reserves grew 4% from approximately 361.8 million Bbl at December 31, 2024 to approximately 376.0 million Bbl at December 31, 2025. Our proved natural gas reserves increased 17% from 1.50 Tcf at December 31, 2024 to 1.75

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Tcf at December 31, 2025. Our proved reserves to production ratio at December 31, 2025 was 8.8, a decrease of 10% from 9.8 at December 31, 2024.

The Standardized Measure of our total proved oil and natural gas reserves decreased 5% from $7.38 billion at December 31, 2024 to $6.99 billion at December 31, 2025. The PV-10 of our total proved oil and natural gas reserves decreased 11% from $9.23 billion at December 31, 2024 to $8.24 billion at December 31, 2025. The decreases in our Standardized Measure and PV-10 are primarily a result of the lower unweighted arithmetic average oil prices, which were partially offset by the higher unweighted arithmetic average 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. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2025 were $61.82 per Bbl and $3.39 per MMBtu, a decrease of 14% and an increase of 59%, respectively, as compared to average oil and natural gas prices of $71.96 per Bbl and $2.13 per MMBtu used to estimate proved reserves at December 31, 2024. Our total proved reserves were made up of 56% oil and 44% natural gas at December 31, 2025 and 59% oil and 41% natural gas at December 31, 2024. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table.

The following table summarizes changes in our estimated proved developed reserves at December 31, 2025.

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(1)    Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved developed oil and natural gas reserves increased 11% from 366.8 million BOE at December 31, 2024 to 408.0 million BOE at December 31, 2025. Our proved developed oil and natural gas reserves increased by 116.8 million BOE and we produced 75.6 million BOE during the year ended December 31, 2025, resulting in a net increase of 41.2 million BOE. We added 23.0 million BOE in proved developed reserves through extensions and discoveries during 2025, which resulted from new well locations drilled during 2025 to establish proved reserves. In addition, during 2025, we converted 77.6 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 3.4 million BOE at December 31, 2025 as a result of net property acquisitions, divestitures and trades completed during 2025. Additionally, we realized approximately 12.8 million BOE in net upward revisions of prior estimates of proved developed reserves in 2025, including positive forecast updates of 16.7 million BOE and ownership updates of 3.2 million BOE. These upward revisions were partially offset by downward revisions of 4.2 million BOE and 2.9 million BOE attributable to certain pricing and expense updates used to estimate proved developed reserves at December 31, 2025 and 2024, respectively.

Our proved developed oil reserves increased 8% from 206.3 million Bbl at December 31, 2024 to 223.0 million Bbl at December 31, 2025. Our proved developed natural gas reserves increased 15% from 963.2 Bcf at December 31, 2024 to 1.11 Tcf at December 31, 2025. Proved developed reserves constituted 61% of our total proved oil and natural gas reserves at December 31, 2025, as compared to 60% at December 31, 2024.

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The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2025.

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(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Our proved undeveloped oil and natural gas reserves increased 6% from 244.7 million BOE at December 31, 2024 to 259.1 million at December 31, 2025. We added 112.0 million BOE in proved undeveloped reserves through extensions and discoveries during 2025, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2025. We also decreased our proved undeveloped reserves by 0.1 million BOE at December 31, 2025 as a result of net property acquisitions, divestitures and trades completed during 2025. Additionally, we realized approximately 20.0 million BOE in net downward revisions of prior estimates of proved undeveloped reserves in 2025, which included the removal of 22.8 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin and the removal of 3.2 million BOE and 1.4 million BOE for certain ownership and pricing updates at December 31, 2025 and 2024, respectively. These downward revisions were partially offset by positive forecast updates of 7.4 million BOE.

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. 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).

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(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2025.

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(1)Numbers in table may not total due to rounding.

(2)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.

(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. 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. 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.

(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

(5)Includes the Cotton Valley formation and shallower zones.

Technology Used to Establish Reserves

Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods.

Internal Control Over Reserves Estimation Process

We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. 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. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum

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Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well.

Acreage Summary

The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2025.

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(1)Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.

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. Undeveloped acreage expiring in 2031 and beyond totals 3,400 net acres, all of which is in the Delaware Basin. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2025.

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(1)Approximately 60% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable.

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect in most cases until the cessation of production in commercial quantities. We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of such lease. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. 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. At December 31, 2025, less than 1% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage.

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Drilling Results

The following table summarizes our drilling activity for the years ended December 31, 2025, 2024 and 2023.

(1)All of these wells are extension wells.

(2)Includes three gross (1.5 net) vertical wells in 2024 and one gross (0.5 net) vertical well in 2023. We did not drill any vertical wells in 2025.

At December 31, 2025, we had a total of 150 gross (52.1 net) development wells and 11 gross (1.0 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations.

Marketing and Customers

Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids.

Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.

The prices we receive for our oil, natural gas and NGL production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports and exports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of, and other financial market conditions affecting, oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel and energy sources; weather conditions and natural disasters, including floods, fires, tornadoes, droughts, hurricanes, tropical storms and severe cold weather; political conditions or conflicts in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; the threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing, flaring, venting and produced water handling and disposal activities; the level of global oil, natural gas and NGL inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; tariffs, trade restrictions and other supply chain constraints; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they

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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. 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.”

The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. 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. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference.

Title to Properties

We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. While we rely upon the judgment of oil and natural gas lease brokers and landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors—Risks Related to our Financial Condition—We may incur losses or costs as a result of title deficiencies in the properties in which we invest.”

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. 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.”

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Competition

The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability.

Many of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.

Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations.

The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors—Risks Related to Third Parties—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.”

Environmental

Emissions Mitigation

We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines that we expect to have sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities.

Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require.

Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions.

Water Management

Using improving technologies, where feasible, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. 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.

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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. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations.

During 2025, 97% of our gross operated oil production and 99% of our gross operated water production were connected to pipelines. In addition to the financial benefits to us and our stakeholders of connecting oil and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water.

Regulation

Oil and Natural Gas Regulation

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.

The states in which we operate require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. 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. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. 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 rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business.

Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an

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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. The NEPA evaluation process at the Department of the Interior has followed regulations issued by the Council on Environmental Quality (“CEQ”) for many years. However, recent court rulings, including a 2024 decision by the United States Court of Appeals for the District of Columbia, have held that CEQ lacks legal authority to issue binding regulations governing the NEPA process. In addition, CEQ rescinded its NEPA regulations in February 2025, and as a result, each government agency impacted by NEPA is establishing its own processes and procedures. 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.

In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico (the “Lease Sale Litigation”). The Lease Sale Litigation challenged the BLM’s decision to hold the lease sales based on alleged defects in the NEPA reviews conducted in conjunction with those sales. These lawsuits were dismissed in 2021 and 2022. 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. In September 2025, the BLM issued a Supplemental NEPA Analysis, which has not yet been finalized, proposing to uphold the previously issued leases. The outcome of BLM’s NEPA review and any future litigation regarding the leases at issue and any related drilling permits is uncertain. In addition, in February 2023, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review, and BLM agreed to conduct additional NEPA analysis in response to this litigation. Each of these pending lawsuits and NEPA reviews, as well as any process changes that the BLM may implement in response, could delay lease sales and the approval of drilling permits, though the ultimate impact is uncertain.

In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. However, in January 2025, the Trump administration revoked the Biden administration’s executive order regarding the social cost of greenhouse gases, withdrew the social cost of greenhouse gases estimates and directed the EPA administrator to consider issuing guidance eliminating the social cost of carbon calculation from any federal permitting or regulatory decision. In March 2025, the EPA administrator announced that the EPA is reconsidering the social cost of greenhouse gases estimates, and in May 2025, the White House Office of Management and Budget directed agencies to limit their consideration of greenhouse gas emissions only to that plainly required in their governing statutes. Future EPA rulemakings may reestablish the previous social cost of greenhouse gases estimates or incorporate new estimates developed in the future and potentially result in more stringent rules and regulations affecting the oil and gas sector.

On February 18, 2026, the EPA published a final rule rescinding its prior 2009 finding that six greenhouse gases in the atmosphere—carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride—may reasonably be anticipated to endanger public health and welfare under the Clean Air Act (the “CAA”), commonly known as the “Endangerment Finding,” which underpins the EPA’s regulation of greenhouse gas emissions. The rescission has been challenged in court, which could result in the rescission being stayed, overturned or limited in scope or effect. If the rescission remains in effect, the EPA may seek in the future to repeal or lessen the stringency of regulations affecting the oil and natural gas industry that are based, at least in part, on the Endangerment Finding. Further, it is possible that efforts to regulate greenhouse gases at the national level in the United States, which could include reconsidering the Endangerment Finding, could occur in the future. The ultimate outcome and long-term effect of the rescission of the Endangerment Finding, as well as its impact on regulation of the oil and natural gas industry, remains uncertain.

In April 2024, the BLM finalized a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. Enforcement of the rule in Texas, North Dakota, Montana, Wyoming, and Utah was enjoined by the North Dakota federal district court, and the appeal of that injunction to the U.S. Court of Appeals for the Eighth Circuit has been held in abeyance since February 14, 2025. The Department of the Interior announced it is evaluating whether to suspend, revise, or rescind the 2024 waste rule, and in November 2025, announced that it will delay enforcement of provisions of the rule that had been scheduled to take effect in December 2025. The ultimate outcome of this process, including possible financial costs and any adverse impacts on our oil and natural gas operations, is uncertain.

The impact of these and similar federal actions related to the oil and natural gas industry remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and

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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. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. San Mateo’s crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico and the Greater Stebbins Area (the “Rustler Breaks Oil Pipeline System”), which includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. Our crude oil gathering and transportation pipelines with origin points from Lea County, New Mexico to various interconnections with third parties (the “Trophy Pipeline System”) are also subject to FERC jurisdiction. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction.

In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.

The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. 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. The EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative.

The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.

In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder.

The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to PHMSA oversight. The Department of Transportation, through PHMSA, has established rules regarding integrity

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management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. To enact the changes outlined in the notice of proposed rulemaking, PHMSA enacted three separate rules (together known as the “Mega Rule”). The first part of the Mega Rule was finalized in October 2019 and requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors—Risks Related to Laws and Regulations—We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.”

Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays.

U.S. Federal and State Taxation

The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur.

In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations and cash flows.

Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.”

Underground Injection and Hydraulic Fracturing

We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced water. The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. 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

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earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells.

In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, have imposed additional regulatory or permitting requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells and, in some instances, allow the agency to modify, suspend, or terminate existing operating permits for disposal wells. 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 use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. 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.”

The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. 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. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to 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. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our 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.”

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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. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. 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. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us.

The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action.

The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges.

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. 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. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA.

RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes.

The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties

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for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a waste emissions charge on greenhouse gas emissions from certain facilities that exceed specified emissions levels. However, the OBBBA delayed implementation of the waste emissions charges for the oil and gas industry until 2034. See “Risk Factors—Risks Related to Laws and Regulations—New regulations on all emissions from our operations could cause us to incur significant costs.”

Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which included a range of measures designed to address climate change, including the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy. However, the Trump administration changed course on the United States’ participation in international climate initiatives. In January 2025, the Trump administration issued an executive order directing the U.S. 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. Ambassador to the United Nations has submitted formal notifications to the United Nations of such withdrawals. The withdrawal of the United States from the Paris Agreement took effect on January 27, 2026. Certain states, including New Mexico, joined the U.S. Climate Alliance and have issued regulations aimed at supporting the goals of the Paris Agreement.

In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. The New Mexico Environment Department (“NMED”) and the NMOCD both issued regulations in response to the governor’s executive order, limiting some aspects of oil and gas operations in the state.

In January 2025, the NMED announced that, due to budget constraints, the NMED Cabinet Secretary will issue a temporary emergency rule to suspend deadlines to issue air permits. 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. Any interruption in our ability to timely obtain air permits could result in delays in or an inability to proceed with our development plans for our oil and natural gas operations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. 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. On December 3, 2025, the EPA issued a final rule extending certain compliance deadlines in the March 8, 2024 rule. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in April 2024, the EPA issued a final consent decree that established a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA has not yet proposed any such revisions.

On February 18, 2026, the EPA published a final rule rescinding the Endangerment Finding, which underpins the EPA’s regulation of greenhouse gas emissions. The rescission has been challenged in court, which could result in the rescission being stayed, overturned or limited in scope or effect. See “Regulation—Oil and Natural Gas Regulation” for additional information.

Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 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

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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. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM.

We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. For example, when the USFWS issues a final rule listing a species as endangered or threatened, the USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”

We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. 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. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable or unwilling to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors—Risks Related to Laws and Regulations—We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”

Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.

We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance other than with respect to our midstream business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.”

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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. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.

Employee Recruiting, Retention and Professional Development

Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders.

We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2025, for example, our employees completed approximately 26,800 hours of continuing education and study, equating to approximately 56 hours per employee. We also have a leadership program that fosters the development and growth of many of our staff with meetings and opportunities to enhance their leadership skills.

We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status.

Proactive Safety Culture

We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and our experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern.

We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts.

Available Information

Our Internet website address is www.matadorresources.com. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. 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. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. 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.