NYSE: KRP

(3) Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP and MB Minerals L.P. and other holders or their respective affiliates.

(4) Kimbell Operating has entered into a management services agreement with us and separate management services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties for the provision of certain management, administrative and operational services.

Our Oil and Gas Assets

We categorize our oil and gas assets into two groups: mineral interests and overriding royalty interests.

Mineral Interests

Mineral interests are real property interests that are typically perpetual and grant ownership to all the oil and natural gas lying below the surface of the property, as well as the right to explore, drill and produce oil and natural gas on that property or to lease such rights to a third party. Mineral owners typically grant oil and gas leases to operators for an initial three-year term with an upfront cash payment to the mineral owners known as a lease bonus. Under the lease, the mineral owner retains a royalty interest entitling it to a cost-free percentage (usually ranging from 20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost-free percentage of production revenues for minerals extracted from the acreage, without the associated executive right to lease and the right to receive lease bonuses.

We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest. For example, we receive similar royalties from operators with respect to our mineral interests or nonparticipating royalty interests as long as such interests are subject to an oil and gas lease. When evaluating our business, our management team does not distinguish between mineral and nonparticipating royalty interests on leased acreage due to the similarity of the royalties received by the interests.

Overriding Royalty Interests

In addition to mineral interests, we also own overriding royalty interests, which are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. Overriding royalty interests typically remain in effect until the associated lease expires and, because substantially all the underlying leases are perpetual so long as production in paying quantities perpetuates the leasehold, substantially all of our overriding royalty interests are likewise perpetual.

Overview of Our Oil and Gas Assets and Operations

As of December 31, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2025, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including approximately 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 133,000 gross wells, including over 53,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we benefit from the continued development of the properties in which we own an interest without the need for investment of additional capital by us.

As of December 31, 2025, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 72,944 MBoe (51.2% liquids, consisting of 30.1% oil and 21.1% NGLs) based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). All of our reserves were classified as proved developed reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated yearly decline rate of 13.5% during the initial five-years.

Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. As of December 31, 2025, there were approximately 1,300 operators actively producing on our acreage, with our top ten operators (Conoco Phillips, Vital Energy, EOG Resources, Inc., Occidental Petroleum, Diamondback E&P LLC, CPX Energy Operating LLC, Pioneer Natural Resources Company, Devon Energy Production Company, Ovintiv Exploration

Inc. and Verdun Oil Company) together accounting for approximately 47.1% of our revenues.

During the years ended December 31, 2025, 2024 and 2023, payments we received from our top purchaser accounted for approximately 7.7%, 9.1% and 6.7%, respectively, of our revenues. We do not believe that the loss of any individual purchaser would have a material adverse effect on us due to the high number of purchasers actively producing on our acreage. As of December 31, 2025, there were 85 rigs (representing 16.1% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 87 rigs operating on our acreage as of December 31, 2024. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Environment” for further discussion.

Our revenues and the amount of cash available for distribution on common units may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. For the year ended December 31, 2025, our oil, natural gas and NGL revenues were generated 62% from oil sales, 25% from natural gas sales and 13% from NGL sales.

Business Strategies

Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We intend to accomplish this objective by executing the following strategies:

● Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors and the Contributing Parties to grow our business. We intend to make opportunistic acquisitions of mineral and royalty interests that have substantial resource and organic growth potential and meet our acquisition criteria, which include (i) mineral and royalty interests in high-quality producing acreage that enhance our asset base, (ii) significant amounts of recoverable oil and natural gas in place with geologic support for future production and reserve growth and (iii) a geographic footprint complementary to our diverse portfolio.

We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. We have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

● Acquire additional mineral and royalty interests from our Sponsors and the Contributing Parties. The Contributing Parties, including affiliates of our Sponsors, continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. The Contributing Parties have no obligation to sell any additional mineral and royalty interests to us or to accept any offer that we may make for any additional assets, and we may decide not to acquire such additional assets even if such Contributing Parties offer them to us. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

● Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests. Our assets consist of diversified mineral and royalty interests. As of December 31, 2025, 56% and 54% of our well count and gross aggregate acreage, respectively, are located in the Permian Basin and Mid-Continent, which are among the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a mineral or royalty interest in without the need for investment of additional capital by us.

● Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our General Partner contains provisions that prohibit certain actions without a supermajority vote of at least 662/3% of the members of the General Partner’s Board of Directors (the “Board of Directors”). Among the actions requiring a supermajority vote are the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio (as defined in our General Partner’s limited liability company agreement) for the preceding four quarters and the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. In addition, pursuant to the terms of our partnership agreement, we are prohibited from the issuance of any partnership interests that rank equal or senior in right of distributions or liquidation to our Series A Cumulative Convertible Preferred Units (“Series A preferred units”) without the consent of the holders of 662/3% of the outstanding Series A preferred units.

We have a $625.0 million secured revolving credit facility. During the year ended December 31, 2025, the Board of Directors approved the repayment of $56.5 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units. Of the $56.5 million, $13.4 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2026. With respect to future quarters, the Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility. We believe that this liquidity, along with internally generated cash from operations and access to capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

● Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent, and as of December 31, 2025, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including approximately 100% of our overriding royalty interests), and substantially all of those leases were held by production. The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 72,944 MBoe (51.2% liquids, consisting of 30.1% oil and 21.1% NGLs) based on the reserve report prepared by Ryder Scott. All of our reserves were classified as proved developed reserves. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays without further required investment on our behalf. We believe that we will continue to benefit from these cost-free additions to production and reserves for the

foreseeable future as a result of technological advances and continuing interest by third party producers in development activities on our acreage.

● Exposure to many of the leading resource plays in the United States. We expect the operators of our properties to continue to drill new wells and to complete drilled but uncompleted wells on our acreage, which we believe should substantially offset the natural production declines from our existing wells. We believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interests in multiple resource plays. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 133,000 gross wells, including over 53,000 wells in the Permian Basin.

● Financial flexibility to fund expansion. We believe that our conservative capital structure will permit us to maintain financial flexibility that will allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our General Partner and the terms of our partnership agreement, which in certain circumstances requires the affirmative vote of 662/3% of our outstanding Series A preferred units, in each case as discussed above. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness” for further information. We believe that we will be able to expand our asset base through acquisitions utilizing our secured revolving credit facility, internally generated cash from operations and access to capital markets.

● Experienced and proven management team with a track record of making acquisitions. The members of our management team and Board of Directors have an average of over 33 years of oil and gas experience. Our management team and Board of Directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 161 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.

Our Properties

Material Basins and Producing Regions

The following is an overview of the United States basins and producing regions we consider most material to our current and future business.

● Permian Basin. The Permian Basin extends from southeastern New Mexico into West Texas and is currently one of the most active drilling regions in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west and the Central Basin in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years. The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin and the Bone Spring formation in the Delaware Basin, which are among the most active plays in the country.

● Mid-Continent. The Mid-Continent is a broad area containing hundreds of fields in Arkansas, Kansas, Louisiana, New Mexico, Oklahoma, Nebraska and Texas and including the Granite Wash, Cleveland and the Mississippi Lime formations. The Anadarko Basin is a structural basin centered in the western part of Oklahoma and the Texas Panhandle, extending into southwestern Kansas and southeastern Colorado. A key feature of the Anadarko Basin is the stacked geologic horizons including the Cana-Woodford and Springer shale in the SCOOP and STACK.

● Terryville/Cotton Valley/Haynesville. We own a substantial position in the core of the Terryville Field that the Contributing Parties acquired in 2007. Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America. Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields and long reserve life with multiple stacked producing zones.

● Appalachian Basin. The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, central Tennessee, western Virginia, northwestern Georgia and northern Alabama. The basin’s most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of Pennsylvania, northern West Virginia and eastern Ohio. In addition to the Marcellus Shale and Utica plays, there are a number of other conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron and Rhinestreet.

● Eagle Ford. The Eagle Ford shale formation stretches across south Texas and includes some of the most economic and productive areas in the United States. The Eagle Ford contains significant amounts of hydrocarbons and is considered the source rock, or the original source, for much of the oil and natural gas contained in the Austin Chalk Basin. The Eagle Ford shale formation has benefitted from improvements in horizontal drilling and hydraulic fracturing.

● Bakken/Williston Basin. The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States in the past 40 years. Development of the Bakken became commercial on a large scale over the past ten years with the advent of horizontal drilling and hydraulic fracturing.

● DJ Basin/Rockies/Niobrara. The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western Nebraska and western Kansas. The area includes the Wattenberg Gas Field, one of the largest natural gas deposits in the United States, and the Niobrara formation. The Niobrara includes three separate zones and stretches from the DJ Basin up into the Powder River Basin in Wyoming. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations.

The following tables present information about our mineral and royalty interest acreage, well count and production by basin and producing region. We may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.

Mineral Interests

The following table sets forth information about our mineral and nonparticipating royalty interests. We combine our mineral and nonparticipating royalty assets into one category because they share many of the same characteristics due to the nature of the underlying interest.

December 31, 2025

Gross

Net

Percent

Basin or Producing Region

Acres

Acres

Leased

Permian Basin (1)

3,072,785

23,336

99.1

%

Mid‑Continent

3,663,657

30,830

99.0

%

Terryville/Cotton Valley/Haynesville

1,301,662

6,725

99.6

%

Appalachian Basin (2)

434,116

16,968

99.8

%

Eagle Ford

476,193

5,059

96.8

%

Barnett Shale/Fort Worth Basin

316,408

3,548

99.1

%

Bakken/Williston Basin (3)

1,214,446

3,132

99.9

%

San Juan Basin

85,604

99.2

%

Onshore California

67,139

95.7

%

DJ Basin/Rockies/Niobrara

46,398

96.1

%

Illinois Basin

11,163

100.0

%

Other Western (onshore) Gulf Basin

614,310

4,247

98.0

%

Other TX/LA/MS Salt Basin

308,850

3,841

95.3

%

Other

677,085

3,306

99.1

%

Total (4)

12,289,816

102,214

99.0

%

(1) Includes mineral interests in approximately 1,540,949 gross (11,145 net) acres in the Wolfcamp/Bone Spring.

(2) Includes mineral interests in approximately 209,340 gross (5,637 net) acres in the Marcellus/Utica.

(3) Includes mineral interests in approximately 1,103,904 gross (3,013 net) acres in the Bakken/Three Forks.

(4) Percentage leased represents the weighted average of our leased acres relative to our total acreage in the basins in which we own mineral interests.

ORRIs

The following table sets forth information about our ORRIs:

December 31, 2025

Gross

Net

Percent

Basin or Producing Region

Acres

Acres

Producing

Permian Basin (1)

333,243

4,465

100.0

%

Mid‑Continent

2,202,709

18,002

99.2

%

Terryville/Cotton Valley/Haynesville

127,245

1,194

99.6

%

Appalachian Basin (2)

307,238

6,235

100.0

%

Eagle Ford

147,955

1,671

100.0

%

Barnett Shale/Fort Worth Basin

76,755

100.0

%

Bakken/Williston Basin (3)

425,631

3,006

100.0

%

San Juan Basin

98,633

1,313

99.0

%

Onshore California

10,668

100.0

%

DJ Basin/Rockies/Niobrara

27,754

100.0

%

Illinois Basin

16,848

1,080

100.0

%

Other Western (onshore) Gulf Basin

89,209

1,215

100.0

%

Other TX/LA/MS Salt Basin

45,502

1,443

99.9

%

Other

814,386

15,544

100.0

%

Total (4)

4,723,776

56,139

99.6

%

(1) Includes overriding royalty interests in approximately 207,494 gross (2,025 net) acres in the Wolfcamp/Bone Spring.

(2) Includes overriding royalty interests in approximately 254,348 gross (4,852 net) acres in the Marcellus/Utica.

(3) Includes overriding royalty interests in approximately 411,439 gross (2,909 net) acres in the Bakken/Three Forks.

(4) Percentage producing represents the weighted average of our acres that are producing relative to our total acreage in the basins in which we own ORRIs. Virtually all acreage is producing.

Wells

The following table sets forth the well count in which we had mineral or royalty interest:

Basin or Producing Region

December 31, 2025

Permian Basin

53,181

Mid‑Continent

21,181

Terryville/Cotton Valley/Haynesville

16,444

Appalachian Basin

3,994

Eagle Ford

4,645

Barnett Shale/Fort Worth Basin

5,949

Bakken/Williston Basin

5,708

San Juan Basin

1,907

Onshore California

975

DJ Basin/Rockies/Niobrara

12,641

Other

6,681

Total

133,306

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

Our historical reserve estimates as of December 31, 2025, 2024 and 2023 were prepared by Ryder Scott, an independent third party petroleum engineering firm. Ryder Scott does not own an interest in any of our properties and is not employed by us on a contingent basis.

Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder

Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming. He earned a Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1983 and a Master of Business Administration in Finance from the University of Colorado in 1985. As technical principal, Mr. Wilson meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering evaluations as well as in applying United States Securities and Exchange Commission (“SEC”) and other industry reserves definitions and guidelines. A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2025 is attached as an exhibit to this Annual Report.

Our Chief Executive Officer, Robert D. Ravnaas, has agreed to provide us with reserve engineering services. Mr. R. Ravnaas is a petroleum engineer with over 36 years of reservoir and operations experience. Mr. R. Ravnaas and certain engineers and geoscience professionals under his supervision worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our mineral and royalty interests. Mr. R. Ravnaas met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Operating and development costs are not realized to our interest but are used to calculate the economic limit life of the wells. These costs are estimated and checked by our independent reserve engineers.

Mr. R. Ravnaas is primarily responsible for the preparation of our reserves. In addition, the preparation of our proved reserve estimates is completed in accordance with internal control procedures, including the following:

● review and verification of historical production data, which data is based on actual production as reported by the operators of our properties;

● preparation of reserve estimates by Mr. R. Ravnaas or under his direct supervision;

● review by Mr. R. Ravnaas of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes; and

● verification of property ownership by our land department.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, 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. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025, 2024 and 2023 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas, and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing

requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.

Summary of Estimated Proved Reserves

Estimates of reserves as of December 31, 2025, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2025, 2024 and 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $65.34, $75.48 and $78.22 per Bbl for oil and $3.39, $2.13 and $2.64 per MMBtu for natural gas at December 31, 2025, 2024 and 2023, respectively. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

The following table presents our estimated proved developed oil and natural gas reserves:

December 31,

Estimated proved developed reserves:

Oil (MBbls)

21,970

20,001

19,800

Natural gas (MMcf)

213,589

204,253

204,542

Natural gas liquids (MBbls)

15,376

13,498

11,519

Total (MBoe)(6:1) (1)

72,944

67,541

65,409

(1) Estimated proved developed reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the years ended December 31, 2025, 2024 and 2023 was used, the conversion factor would be approximately 19.3 Mcf per Bbl of oil, 35.4 Mcf per Bbl of oil and 29.6 Mcf per Bbl of oil, respectively.

The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “