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What changed in Kimbell Royalty Partners, LP's 10-K — 2024 vs 2025

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

+307 added−324 removedSource: 10-K (2026-02-26) vs 10-K (2025-02-27)

Top changes in Kimbell Royalty Partners, LP's 2025 10-K

307 paragraphs added · 324 removed · 271 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

69 edited+5 added−2 removed183 unchanged
Biggest changeAs of December 31, 2024, there were approximately 1,400 operators actively producing on our acreage, with our top ten operators (Vital Energy, Occidental Petroleum, Pioneer Natural Resources Company, EP Energy E&P Company, L.P., Verdad Oil & Gas, Chesapeake Operating, Inc., EOG Resources, Inc., XTO Energy, Inc., SWN Production Company LLC and Comstock Oil & Gas, Inc.) together accounting for approximately 41.2% of our revenues.
Biggest changeAs 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.
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.
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.
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.
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.
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 and undeveloped reserves were estimated by the analogy method.
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.
Any changes in the laws and regulations in the future could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could effect production from the acreage underlying our mineral and royalty interests and have a material adverse affect on our business and prospects.
Any changes in the laws and regulations in the future could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could effect production from the acreage underlying our mineral and royalty interests and have a material adverse effect on our business and prospects.
For example, in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations.
For example, in May 2016, the EPA finalized regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations.
Summary of Estimated Proved Reserves Estimates of reserves as of December 31, 2024, 2023 and 2022 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, 2024, 2023 and 2022, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period.
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.
Our PDP reserves have an average estimated yearly decline rate of 13.2% during the initial five-years. 14 Table of Contents 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.
Our PDP reserves have an average estimated yearly decline rate of 13.5% during the initial five-years. 14 Table of Contents 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.
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, 2024, 2023 and 2022 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations.
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.
We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2024, 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.
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.
Certain members of our management team have managed a significant investment program, investing in over 160 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.
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.
The members of our management team and Board of Directors have an average of over 32 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.
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.
Implementation of more stringent laws and regulations, including the final methane rule from May 2024, may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
Implementation of more stringent laws and regulations, including the reinstatement of the final methane rule from May 2024 or enactment of future methane regulations, may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
That rule was rescinded in December 2017. This rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision has been appealed. If these 28 Table of Contents requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive.
That rule was rescinded in December 2017. This rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision has been appealed. If these requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive.
The state, and some counties and municipalities, in which we operate also regulate one or more of the following: ● the location of wells; ● the method of drilling and casing wells; ● the timing of construction or drilling activities, including seasonal wildlife closures; ● the rates of production or “allowables”; ● the surface use and restoration of properties upon which wells are drilled; ● the plugging and abandoning of wells; and ● notice to, and consultation with, surface owners and other third parties.
The state, and some counties and municipalities, in which we operate also regulate one or more of the following: ● the location of wells; ● the method of drilling and casing wells; ● the timing of construction or drilling activities, including seasonal wildlife closures; ● the rates of production or “allowables;” ● the surface use and restoration of properties upon which wells are drilled; ● the plugging and abandoning of wells; and ● notice to, and consultation with, surface owners and other third parties.
The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response 26 Table of Contents contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs.
The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs.
In April 2016, the United States was one of 175 countries to sign the Paris Agreement, 27 Table of Contents which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016.
In April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016.
Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. From time to time, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process.
Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. From time to time, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure 28 Table of Contents of the chemicals used in the fracturing process.
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. 12 Table of Contents The diagram below depicts a simplified version of our organizational structure as of February 21, 2025: (1) The Sponsors are affiliates of our founders, Messrs.
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. 12 Table of Contents The diagram below depicts a simplified version of our organizational structure as of February 20, 2026: ​ (1) The Sponsors are affiliates of our founders, Messrs.
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 Springs formation in the Delaware Basin, which are among the most active plays in the country. ● Mid-Continent.
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.
During the years ended December 31, 2024, 2023 and 2022, payments we received from our top purchaser accounted for approximately 9.1%, 6.7% and 11.3%, 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.
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, 2024, we owned mineral and royalty interests in approximately 12.2 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, 2024, 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.
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.
In line with a June 2017 announcement from President Trump, the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reversed this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021.
Following a June 2017 announcement from President Trump, the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reversed this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021.
States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. 31 Table of Contents States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both.
States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both.
(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. 19 Table of Contents ORRIs The following table sets forth information about our ORRIs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2024 ​ ​ Gross ​ Net ​ Percent Basin or Producing Region ​ Acres ​ Acres ​ Producing Permian Basin (1) ​ 333,243 ​ 4,465 ​ 100.0 % Mid‑Continent 2,205,269 ​ 18,002 99.1 % 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 ​ 593 100.0 % Bakken/Williston Basin (3) 425,631 ​ 3,006 100.0 % San Juan Basin 98,633 ​ 1,313 99.0 % Onshore California 10,668 ​ 22 100.0 % DJ Basin/Rockies/Niobrara 27,754 ​ 356 100.0 % 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 814,387 ​ 15,544 100.0 % Total (4) 4,726,337 56,139 99.6 % (1) Includes overriding royalty interests in approximately 207,494 gross (2,025 net) acres in the Wolfcamp/Bone Spring.
(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. 19 Table of Contents 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 ​ 593 100.0 % Bakken/Williston Basin (3) 425,631 ​ 3,006 100.0 % San Juan Basin 98,633 ​ 1,313 99.0 % Onshore California 10,668 ​ 22 100.0 % DJ Basin/Rockies/Niobrara 27,754 ​ 356 100.0 % 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.
A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2024 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 35 years of reservoir and operations experience. Mr. R.
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.
The Contributing Parties have no obligation to sell any additional assets 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.
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.
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 129,000 gross wells, including over 50,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays.
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.
Then in August 2023, the EPA and Army Corps of Engineers released the text of a rule further revising the WOTUS definition to incorporate certain limitations on jurisdictional reach explained in the Supreme Court’s May 2023 decision in Sackett v. EPA. Additional legal challenges to the August 2023 regulation are proceeding in federal courts.
Then in August 2023, the EPA and Army Corps of Engineers released the text of a rule further revising the WOTUS definition to incorporate certain limitations on jurisdictional reach explained in the Supreme Court’s decision in Sackett . Additional legal challenges to the January 2023 final rule and August 2023 regulation are proceeding in federal courts.
We have a $550.0 million secured revolving credit facility. During the year ended December 31, 2024, 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.
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.
Overview of Our Oil and Gas Assets and Operations As of December 31, 2024, we owned mineral and royalty interests in approximately 12.2 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.
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.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. The OPA is the primary federal law for oil spill liability.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. 26 Table of Contents The OPA is the primary federal law for oil spill liability.
Texas currently imposes a 4.6% severance tax (2.3% for enhanced recovery) on the market value of oil production and a 7.5% severance tax on the market value of natural gas production.
Texas currently imposes a 4.6% severance tax (2.3% for enhanced recovery) on the market value of oil production and a 7.5% severance tax on the market value of natural gas 31 Table of Contents production.
The SEC maintains an internet site that contains 32 Table of Contents reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com.
The SEC maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com.
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 129,000 gross wells, including over 50,000 wells in the Permian Basin. ● Financial flexibility to fund expansion.
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.
(2) Reflects ORRIs in approximately 21,115 total gross (111 net) undeveloped acres. Drilling Results As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells.
(2) Reflects ORRIs in approximately 18,554 total gross (92 net) undeveloped acres. Drilling Results As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells.
If the final rule announced in December 2022 or other expanded WOTUS definition is ultimately implemented, Clean Water Act jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.
If the January 2023 final rule or other expanded WOTUS definition is ultimately implemented, Clean Water Act jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.
As of December 31, 2024, 55% 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.
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.
Although Congress has not adopted such legislation at this time, it may do so in the future, and many states continue to pursue regulations to reduce GHG emissions.
Although Congress has not adopted such legislation at this time, it may do so in the future, and many states continue to pursue regulations to 27 Table of Contents reduce GHG emissions.
Of the $56.5 million, $14.3 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2025. 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.
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.
If a price equivalent conversion based on the twelve-month average prices for the y ears ended December 31, 2024, 2023 and 2022 was used, the conversion factor would be approximately 35.4 Mcf per Bbl of oil, 29.6 Mcf per Bbl of oil and 14.7 Mcf per Bbl of oil, respectively.
If a price equivalent conversion based on the twelve-month average prices for the y ears 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 interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”).
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”).
During more recent COP meetings, the United States and other participating countries have reaffirmed these emission reduction goals. In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement.
During more recent COP meetings, the United States and other participating countries have reaffirmed these emission reduction goals. In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement, which withdrawal by the United States became effective on January 27, 2026.
Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and potentially delays operations, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. 29 Table of Contents The availability, terms and cost of transportation significantly affect sales of oil and natural gas.
Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and potentially delays operations, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.
Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently 29 Table of Contents increasing the regulatory burden.
Our employees may participate in a robust benefits program, which includes a focus on health and wellness, and we offer a variety of other employee perks. As of December 31, 2024, Kimbell Operating had approximately 28 employees performing services for our operations and activities. Women represent approximately 36% of our workforce, and men represent approximately 64%.
Our employees may participate in a robust benefits program, which includes a focus on health and wellness, and we offer a variety of other employee perks. As of December 31, 2025, Kimbell Operating had approximately 29 employees performing services for our operations and activities. Women represent approximately 34% of our workforce, and men represent approximately 66%.
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, 2024 ​ ​ Gross ​ Net Percent Basin or Producing Region ​ Acres ​ Acres ​ Leased Permian Basin (1) ​ 3,003,486 ​ 22,463 ​ 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 ​ 159 99.2 % Onshore California 67,139 ​ 286 95.7 % DJ Basin/Rockies/Niobrara 46,398 ​ 680 96.1 % Illinois Basin 11,163 ​ 97 100.0 % Other Western (onshore) Gulf Basin 614,310 ​ 4,247 98.0 % Other TX/LA/MS Salt Basin 308,850 ​ 3,841 95.3 % Other 677,084 ​ 3,305 99.1 % Total (4) 12,220,516 101,340 99.0 % (1) Includes mineral interests in approximately 1,480,274 gross (10,375 net) acres in the Wolfcamp/Bone Spring.
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 ​ 159 99.2 % Onshore California 67,139 ​ 286 95.7 % DJ Basin/Rockies/Niobrara 46,398 ​ 680 96.1 % Illinois Basin 11,163 ​ 97 100.0 % 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.
Acreage Mineral and Royalty Interests The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State Acreage ​ Acreage ​ Acreage Texas 5,235,677 ​ 61,790 ​ 5,297,467 Oklahoma 2,464,825 34,131 2,498,956 North Dakota 1,097,983 1,000 1,098,983 Wyoming 301,330 771 302,101 Kansas 608,320 2,001 610,321 Louisiana 618,711 1,045 619,756 Arkansas 407,848 1,218 409,066 Montana 165,955 5,059 171,014 New Mexico 211,391 3,146 214,537 Utah ​ 144,053 ​ — ​ 144,053 Other 836,591 ​ 17,671 854,262 Total 12,092,684 (1) 127,832 (2) 12,220,516 (1) Reflects mineral interests in approximately 12,092,684 total gross (91,580 net) developed acres.
Acreage Mineral and Royalty Interests The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State Acreage ​ Acreage ​ Acreage Texas ​ 5,304,977 ​ 61,790 ​ 5,366,767 Oklahoma 2,464,825 34,131 2,498,956 North Dakota 1,097,983 1,000 1,098,983 Wyoming 301,330 771 302,101 Kansas 608,320 2,001 610,321 Louisiana 618,711 1,045 619,756 Arkansas 407,848 1,218 409,066 Montana 165,955 5,059 171,014 New Mexico 211,391 3,146 214,537 Utah ​ 144,053 ​ — ​ 144,053 Other 836,591 ​ 17,671 854,262 Total 12,161,984 (1) 127,832 (2) 12,289,816 (1) Reflects mineral interests in approximately 12,161,984 total gross (92,454 net) developed acres.
The unweighted arithmetic average first day of the month prices were $75.48, $78.22 and $93.67 per Bbl for oil and $2.13, $2.64 and $6.36 per MMBtu for natural gas at December 31, 2024, 2023 and 2022, respectively. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data.
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.
During his presidency, President Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden administration’s climate policies. More recently, President Trump reversed certain climate-focused executive actions taken by President Biden.
During his presidency, President Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden administration’s climate policies. In his current presidential term, President Trump has reversed many climate-focused executive actions taken by President Biden.
Risk Factors.” Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2024, which is included as an exhibit to this Annual Report. 22 Table of Contents Oil, Natural Gas and NGL Production and Pricing Production and Price History The following table sets forth information regarding our production of oil and natural gas and certain price and cost information for each of the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 ​ 2022 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (Bbls) ​ ​ 2,836,913 ​ ​ 2,392,622 ​ ​ 1,425,842 Natural gas (Mcf) ​ ​ 27,586,460 ​ ​ 23,384,021 ​ ​ 20,310,991 Natural gas liquids (Bbls) ​ ​ 1,667,089 ​ ​ 1,082,663 ​ ​ 746,865 Total (Boe)(6:1) (1) ​ ​ 9,101,745 ​ ​ 7,372,622 ​ ​ 5,557,872 Average daily production (Boe/d)(6:1) ​ ​ 24,868 ​ ​ 20,265 ​ ​ 15,025 Average Realized Prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (per Bbl) ​ $ 75.98 ​ $ 76.55 ​ $ 91.74 Natural gas (per Mcf) ​ $ 1.82 ​ $ 2.55 ​ $ 6.04 Natural gas liquids (per Bbl) ​ $ 23.34 ​ $ 23.01 ​ $ 38.19 Average Unit Cost per Boe (6:1) ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ $ 2.24 ​ $ 2.76 ​ $ 2.92 (1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. ​ Productive Wells Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells.
Risk Factors.” Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2025, which is included as an exhibit to this Annual Report. 22 Table of Contents Oil, Natural Gas and NGL Production and Pricing Production and Price History The following table sets forth information regarding our production of oil and natural gas and certain price and cost information for each of the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ 2023 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (Bbls) ​ ​ 3,061,920 ​ ​ 2,836,913 ​ ​ 2,392,622 Natural gas (Mcf) ​ ​ 26,733,988 ​ ​ 27,586,460 ​ ​ 23,384,021 Natural gas liquids (Bbls) ​ ​ 1,884,763 ​ ​ 1,667,089 ​ ​ 1,082,663 Total (Boe)(6:1) (1) ​ ​ 9,402,348 ​ ​ 9,101,745 ​ ​ 7,372,622 Average daily production (Boe/d)(6:1) ​ ​ 25,760 ​ ​ 24,868 ​ ​ 20,265 Average Realized Prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (per Bbl) ​ $ 63.84 ​ $ 75.98 ​ $ 76.55 Natural gas (per Mcf) ​ $ 2.93 ​ $ 1.82 ​ $ 2.55 Natural gas liquids (per Bbl) ​ $ 23.15 ​ $ 23.34 ​ $ 23.01 Average Unit Cost per Boe (6:1) ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ $ 2.17 ​ $ 2.24 ​ $ 2.76 (1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. ​ Productive Wells Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells.
As of December 31, 2024, there were 87 rigs (representing 15.2% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 98 rigs operating on our acreage as of December 31, 2023. Please read “Item 7.
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.
The following table presents our estimated proved developed oil and natural gas reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2024 ​ ​ 2023 ​ ​ 2022 ​ Estimated proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (MBbls) ​ 20,001 ​ 19,800 ​ 12,355 ​ Natural gas (MMcf) ​ 204,253 ​ 204,542 ​ 160,298 ​ Natural gas liquids (MBbls) ​ 13,498 ​ 11,519 ​ 7,388 ​ Total (MBoe)(6:1) (1) ​ 67,541 ​ 65,409 ​ 46,459 ​ (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.
The following table presents our estimated proved developed oil and natural gas reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2025 ​ ​ 2024 ​ ​ 2023 ​ 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.
(2) Reflects mineral interests in approximately 127,832 total gross (9,760 net) undeveloped acres. 23 Table of Contents ORRIs The following table sets forth information relating to our acreage for our ORRIs at December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State ​ Acreage ​ Acreage ​ Acreage Texas 1,415,796 680 1,416,476 Oklahoma 1,346,250 19,000 1,365,250 North Dakota 419,177 — 419,177 Wyoming 350,846 — 350,846 Utah ​ 235,432 ​ — ​ 235,432 Colorado 192,402 — 192,402 Pennsylvania 124,298 — 124,298 West Virginia 116,938 — 116,938 Louisiana 119,062 450 119,512 New Mexico 113,946 960 114,906 Other 271,075 25 271,100 Total 4,705,222 (1) 21,115 (2) 4,726,337 (1) Reflects ORRIs in approximately 4,705,222 total gross (56,028 net) developed acres.
(2) Reflects mineral interests in approximately 127,832 total gross (9,760 net) undeveloped acres. 23 Table of Contents ORRIs The following table sets forth information relating to our acreage for our ORRIs at December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State ​ Acreage ​ Acreage ​ Acreage Texas ​ ​ ​ 1,415,796 ​ ​ ​ 680 ​ ​ ​ 1,416,476 Oklahoma 1,346,251 16,440 1,362,691 North Dakota 419,177 — 419,177 Wyoming 350,846 — 350,846 Utah ​ 235,432 ​ — ​ 235,432 Colorado 192,402 — 192,402 Pennsylvania 124,298 — 124,298 West Virginia 116,938 — 116,938 Louisiana 119,062 450 119,512 New Mexico 113,946 960 114,906 Other 271,074 24 271,098 Total 4,705,222 (1) 18,554 (2) 4,723,776 (1) Reflects ORRIs in approximately 4,705,222 total gross (56,047 net) developed acres.
For the year ended December 31, 2024, our oil, natural gas and NGL revenues were generated 71% from oil sales, 16% from natural gas sales and 13% from NGL sales.
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.
Wells The following table sets forth the well count in which we had mineral or royalty interest: ​ ​ ​ Basin or Producing Region ​ December 31, 2024 Permian Basin ​ 50,604 Mid‑Continent 20,898 Terryville/Cotton Valley/Haynesville 16,297 Appalachian Basin 3,929 Eagle Ford 4,277 Barnett Shale/Fort Worth Basin 5,925 Bakken/Williston Basin 5,358 San Juan Basin 1,887 Onshore California 975 DJ Basin/Rockies/Niobrara 12,556 Other 6,657 Total 129,363 ​ Oil and Natural Gas Data Proved Reserves Evaluation and Review of Estimated Proved Reserves Our historical reserve estimates as of December 31, 2024, 2023 and 2022 were prepared by Ryder Scott, an independent third party petroleum engineering firm.
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.
As of December 31, 2024, we owned mineral or royalty interests in over 129,000 gross productive wells, which consisted of over 94,000 oil wells and over 34,000 natural gas wells.
As of December 31, 2025, we owned mineral or royalty interests in over 133,000 gross productive wells, which consisted of over 98,000 oil wells and over 35,000 natural gas wells.
As of December 31, 2024, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 67,541 MBoe (49.6% liquids, consisting of 29.6% oil and 20.0% 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.
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 estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 67,541 MBoe (49.6% liquids, consisting of 29.6% oil and 20.0% NGLs) based on the reserve report prepared by Ryder Scott. All of our reserves were classified as proved developed reserves.
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 substantial incentives contained in the Inflation Reduction Act could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower-emitting alternatives. The Inflation Reduction Act also imposes the first-ever federal fee on GHG emissions, which focuses on methane emissions.
The substantial incentives contained in the Inflation Reduction Act could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower-emitting alternatives.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties 30 Table of Contents operate.
Facilities Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102. We believe that our leased facilities are adequate for our current operations. Additional Information We electronically file various reports with the SEC including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports.
We believe that our leased facilities are adequate for our current operations. 32 Table of Contents Additional Information We electronically file various reports with the SEC including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports.
Following a standard comment period, the EPA and Army Corp of Engineers announced a final rule establishing a revised and “durable” WOTUS definition on December 30, 2022, which restored many of the elements of the 2015 rule. Multiple legal challenges to the 2022 final rule followed.
Following a standard comment period, the final rule establishing a revised and “durable” WOTUS definition, which restored many of the elements of the 2015 rule, was published in the Federal Register on January 18, 2023. Multiple legal challenges to the January 2023 final rule followed.
Climate Change In response to findings that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources.
Relying on this finding, which is referred to as the 2009 Endangerment Finding, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources.
Although the United States Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. 30 Table of Contents Natural Gas Sales and Transportation FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978.
Natural Gas Sales and Transportation FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. On February 12, 2026, the EPA issued a final rule that rescinded the 2009 Endangerment Finding and repealed all GHG emission standards for motor vehicles that directly relied on the 2009 Endangerment Finding.
Mineral Interests The following table sets forth information about our mineral and nonparticipating royalty interests.
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.
Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.
Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Climate Change In 2009, the EPA found that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment.
Removed
All information as of December 31, 2024 excludes the assets acquired in the Boren Acquisition, which is described in Management’s Discussion and Analysis of Financial Condition and Results of Operations–Recent Developments–Acquisitions.
Added
With federal litigation ongoing, in March 2025, the EPA and Army Corps of Engineers issued updated guidance concerning determinations of whether a wetland has a “continuous surface connection” to a requisite jurisdictional water under the Clean Water Act to align with the Supreme Court decision in Sackett.
Removed
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. All information as of December 31, 2024 excludes the assets acquired in the Boren Acquisition, which is described in Management’s Discussion and Analysis of Financial Condition and Results of Operations–Recent Developments–Acquisitions.
Added
However, the final methane rule from May 2024 is no longer in effect and has no force of law following disapproval by a joint resolution of Congress in March 2025 pursuant to the Congressional Review Act.
Added
The impact from the February 2026 rescission on other GHG regulations issued under the Clean Air Act that relied on the 2009 Endangerment Finding for legal support, including GHG regulations affecting the oil and gas industry, is uncertain.
Added
The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the United States Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Added
Facilities Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

91 edited+21 added−19 removed333 unchanged
Biggest changeThe operators of our properties must comply with federal and state laws and regulations governing conservation matters, including: ● provisions related to the unitization or pooling of the oil and natural gas properties; ● the establishment of maximum rates of production from wells; ● the spacing of wells; ● the plugging and abandonment of wells; and ● the removal of related production equipment. 59 Table of Contents Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of our operators and third party downstream natural gas transporters associated with production from our properties.
Biggest changeAdditionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of our operators and third party downstream natural gas transporters associated with production from our properties.
These conflicts include, among others, the following situations: ● neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests; ● our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities; ● many of the officers and directors of our General Partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and owe fiduciary duties to our Sponsors, or any other investment partnership that they control, and the Contributing Parties and their respective owners; ● our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us; ● our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from taking actions, that may be in our best interests; ● our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities, and restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty; ● except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval; ● contracts between us, on the one hand, and our General Partner and its affiliates, on the other hand, may not be the result of arm’s length negotiations; 35 Table of Contents ● disputes may arise under agreements we have with our General Partner or its affiliates; ● our General Partner determines the amount and timing of acquisitions and dispositions, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders; ● our General Partner determines which costs incurred by it or its affiliates are reimbursable by us; ● our partnership agreement does not restrict our General Partner from causing us to reimburse it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; ● we have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us, and such entities also provide these services to certain other entities, including certain of the Contributing Parties; ● our General Partner intends to limit its liability regarding our contractual and other obligations; ● our General Partner may exercise its right to call and purchase all of the common units and Class B units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units and Class B units (taken as a single class); ● our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including under the contribution agreement entered into in connection with our IPO and other agreements with our Sponsors and the Contributing Parties; and ● our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
These conflicts include, among others, the following situations: ● neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests; ● our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities; ● many of the officers and directors of our General Partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and owe fiduciary duties to our Sponsors, or any other investment partnership that they control, and the Contributing Parties and their respective owners; ● our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us; ● our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from taking actions, that may be in our best interests; ● our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities, and restricting the 35 Table of Contents remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty; ● except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval; ● contracts between us, on the one hand, and our General Partner and its affiliates, on the other hand, may not be the result of arm’s length negotiations; ● disputes may arise under agreements we have with our General Partner or its affiliates; ● our General Partner determines the amount and timing of acquisitions and dispositions, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders; ● our General Partner determines which costs incurred by it or its affiliates are reimbursable by us; ● our partnership agreement does not restrict our General Partner from causing us to reimburse it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; ● we have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us, and such entities also provide these services to certain other entities, including certain of the Contributing Parties; ● our General Partner intends to limit its liability regarding our contractual and other obligations; ● our General Partner may exercise its right to call and purchase all of the common units and Class B units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units and Class B units (taken as a single class); ● our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including under the contribution agreement entered into in connection with our IPO and other agreements with our Sponsors and the Contributing Parties; and ● our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including: ● changes in commodity prices; ● public reaction to our press releases, announcements and filings with the SEC; ● fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies; ● changes in market valuations of similar companies; ● departures of key personnel; ● commencement of or involvement in litigation; ● variations in our quarterly results of operations or those of other oil and natural gas companies; ● changes in general economic conditions, financial markets or the oil and natural gas industry; ● announcements by us or our competitors of significant acquisitions or other transactions; ● variations in the amount of our quarterly cash distributions to our unitholders; ● changes in accounting standards, policies, guidance, interpretations or principles; ● the failure of securities analysts to cover our common units or changes in their recommendations and estimates of our financial performance; ● future sales of our common units; and ● the other factors described in these “Risk Factors.” 42 Table of Contents The New York Stock Exchange (the “NYSE”) does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including: ● changes in commodity prices; 42 Table of Contents ● public reaction to our press releases, announcements and filings with the SEC; ● fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies; ● changes in market valuations of similar companies; ● departures of key personnel; ● commencement of or involvement in litigation; ● variations in our quarterly results of operations or those of other oil and natural gas companies; ● changes in general economic conditions, financial markets or the oil and natural gas industry; ● announcements by us or our competitors of significant acquisitions or other transactions; ● variations in the amount of our quarterly cash distributions to our unitholders; ● changes in accounting standards, policies, guidance, interpretations or principles; ● the failure of securities analysts to cover our common units or changes in their recommendations and estimates of our financial performance; ● future sales of our common units; and ● the other factors described in these “Risk Factors.” The New York Stock Exchange (the “NYSE”) does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities.
If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities.
In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions.
In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions.
For example, our partnership agreement provides that: ● whenever our General Partner (acting in its capacity as our General Partner), the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our General Partner, the Board of Directors and any committee 37 Table of Contents thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity; ● our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; ● our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and ● our General Partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: ● approved by the conflicts committee of the Board of Directors, although our General Partner is not obligated to seek such approval; ● approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; ● determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or ● determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
For example, our partnership agreement provides that: ● whenever our General Partner (acting in its capacity as our General Partner), the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our General Partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity; ● our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; ● our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and ● our General Partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: ● approved by the conflicts committee of the Board of Directors, although our General Partner is not obligated to seek such approval; ● approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; ● determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or ● determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: ● the domestic and foreign supply of and demand for oil, natural gas and NGLs; ● the level of prices and expectations about future prices of oil, natural gas and NGLs; ● the level of global oil and natural gas exploration and production; ● the cost of exploring for, developing, producing and delivering oil and natural gas; ● the price and quantity of foreign imports; ● the level of United States domestic production; ● political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia; ● the ability of members of the OPEC to agree to and maintain oil price and production controls; ● the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions; ● speculative trading in crude oil, natural gas and NGL derivative contracts; ● the level of consumer product demand; ● weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change; 44 Table of Contents ● risks associated with operating drilling rigs; ● technological advances affecting energy consumption; ● domestic and foreign governmental regulations and taxes; ● the continued threat of terrorism and the impact of military and other action, including military actions involving Russia and Ukraine and the conflict in the Middle East; ● the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; ● the price and availability of alternative fuels; and ● overall domestic and global economic conditions.
Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: ● the domestic and foreign supply of and demand for oil, natural gas and NGLs; ● the level of prices and expectations about future prices of oil, natural gas and NGLs; ● the level of global oil and natural gas exploration and production; ● the cost of exploring for, developing, producing and delivering oil and natural gas; ● the price and quantity of foreign imports; ● the level of United States domestic production; ● political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia; ● the ability of members of the OPEC to agree to and maintain oil price and production controls; ● the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions; ● speculative trading in crude oil, natural gas and NGL derivative contracts; ● the level of consumer product demand; ● weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change; ● risks associated with operating drilling rigs; ● technological advances affecting energy consumption; ● domestic and foreign governmental regulations and taxes; ● the continued threat of terrorism and the impact of military and other action, including military actions involving Russia and Ukraine and the conflict in the Middle East; ● the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; ● the price and availability of alternative fuels; and ● overall domestic and global economic conditions.
Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities. Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history.
Prospect areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities. Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history.
The limited liability company agreement of our General Partner, which is controlled by our Sponsors, contains provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the Board of Directors, including: ● the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters; ● the reservation of a portion of cash generated from operations to finance acquisitions; ● modifications to the definition of “available cash” in our partnership agreement; and ● the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. 34 Table of Contents The Board of Directors is made up of seven members.
The limited liability company agreement of our General Partner, which is controlled by our Sponsors, contains provisions that prohibit certain actions without a supermajority vote of at least 66 2 / 3 % of the members of the Board of Directors, including: ● the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters; 34 Table of Contents ● the reservation of a portion of cash generated from operations to finance acquisitions; ● modifications to the definition of “available cash” in our partnership agreement; and ● the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates and their transferees, the Contributing Parties and their respective affiliates, persons who acquired such units with the prior approval of the Board of Directors, holders of Series A preferred units in connection with any vote, consent or approval of holders of the Series A preferred units, voting as a separate class or on an as-converted basis with the holders of common units, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units or any conversion of the Series A preferred units at our option, may not vote on any matter.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates and their transferees, the Contributing Parties and their respective affiliates, persons who acquired such units with the prior approval of the 39 Table of Contents Board of Directors, holders of Series A preferred units in connection with any vote, consent or approval of holders of the Series A preferred units, voting as a separate class or on an as-converted basis with the holders of common units, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units or any conversion of the Series A preferred units at our option, may not vote on any matter.
Our historical estimates of proved reserves and related valuations as of December 31, 2024, 2023 and 2022 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us.
Our historical estimates of proved reserves and related valuations as of December 31, 2025, 2024 and 2023 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us.
Examples of decisions that our General Partner may make in its individual capacity include: ● how to allocate corporate opportunities among us and its other affiliates; 38 Table of Contents ● whether to exercise its limited call right; ● whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors or by the unitholders; ● how to exercise its voting rights with respect to the units it owns; ● whether to sell or otherwise dispose of any units or other partnership interests it owns; and ● whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
Examples of decisions that our General Partner may make in its individual capacity include: ● how to allocate corporate opportunities among us and its other affiliates; ● whether to exercise its limited call right; ● whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors or by the unitholders; ● how to exercise its voting rights with respect to the units it owns; ● whether to sell or otherwise dispose of any units or other partnership interests it owns; and ● whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
If the operators of our properties are unable to obtain water to use in their operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
If the operators of our properties are unable to obtain water to use in their 61 Table of Contents operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. 46 Table of Contents Neither we nor the operators of our properties control these third party transportation facilities and our operators’ access to them may be limited or denied.
The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor the operators of our properties control these third party transportation facilities and our operators’ access to them may be limited or denied.
If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution on common units may be materially adversely affected. Our estimated reserves are based on many assumptions that may prove to be inaccurate.
If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution on common units may be materially adversely affected. 53 Table of Contents Our estimated reserves are based on many assumptions that may prove to be inaccurate.
The volatility of these prices due to factors beyond our control greatly affects 33 Table of Contents our business, financial condition, results of operations and cash available for distribution on common units.” We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.
The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.” We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.
We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third party 55 Table of Contents service providers to provide many of the services and equipment necessary to drill new wells.
We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third party service providers to provide many of the services and equipment necessary to drill new wells.
If a unitholder is an ineligible holder, in certain circumstances as set forth in our partnership agreement, the units held by such unitholder may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.
If a unitholder is an ineligible holder, in certain circumstances as set forth in our partnership agreement, the units held by 43 Table of Contents such unitholder may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.
The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or 56 Table of Contents the present value of estimated future net revenues.
The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.
This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a 40 Table of Contents general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our General Partner if a limited partner were to lose limited liability through any fault of our General Partner.
This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our General Partner if a limited partner were to lose limited liability through any fault of our General Partner.
Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and NGL production has, in turn, 45 Table of Contents softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices.
Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. With current global economic growth slowing, demand for oil, natural gas and NGL production has, in turn, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices.
The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis.
The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry 46 Table of Contents on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis.
This effectively permits a “change of control” without the vote or consent of the unitholders. Our sole cash-generating asset is our membership interest in the Operating Company, and we are accordingly dependent upon distributions from the Operating Company to pay taxes and cover our expenses and to make distributions to our unitholders.
This effectively permits a “change of control” without the vote or consent of the unitholders. 40 Table of Contents Our sole cash-generating asset is our membership interest in the Operating Company, and we are accordingly dependent upon distributions from the Operating Company to pay taxes and cover our expenses and to make distributions to our unitholders.
Changes in current law in these jurisdictions could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution on common units. 57 Table of Contents Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units.
Changes in current law in these jurisdictions could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution on common units. Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units.
Our obligations to the holders of the Series A preferred units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. 43 Table of Contents The terms of our Series A preferred units contain covenants that may limit our business flexibility.
Our obligations to the holders of the Series A preferred units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. The terms of our Series A preferred units contain covenants that may limit our business flexibility.
Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well.
Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or 55 Table of Contents abandonment of the well.
Initiatives to implement pledges made at COP26, the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.
Initiatives to implement pledges made at COP meetings, the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.
We depend in part on acquisitions to grow our reserves, production and cash generated from operations. We have in the past elected not to, and may in the future not elect to, incur the expense of retaining lawyers to examine the title to 54 Table of Contents acquired mineral interests.
We depend in part on acquisitions to grow our reserves, production and cash generated from operations. We have in the past elected not to, and may in the future not elect to, incur the expense of retaining lawyers to examine the title to acquired mineral interests.
Applicable United States Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that 58 Table of Contents exchanges of the OpCo common units qualify for one or more such safe harbors.
Applicable United States Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges of the OpCo common units qualify for one or more such safe harbors.
Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on 51 Table of Contents commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow. There is intense competition for acquisition opportunities in our industry.
Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow. There is intense competition for acquisition opportunities in our industry.
In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets. Legal, Environmental and Regulatory Risks ​ Oil and natural gas operations are subject to various governmental laws and regulations.
In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets. 59 Table of Contents Legal, Environmental and Regulatory Risks ​ Oil and natural gas operations are subject to various governmental laws and regulations.
If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, 49 Table of Contents investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection.
If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection.
Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax sooner than expected, our tax liability being greater than expected or a greater portion of our distributions being treated as taxable dividends.
Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax 58 Table of Contents sooner than expected, our tax liability being greater than expected or a greater portion of our distributions being treated as taxable dividends.
In prior years, we 41 Table of Contents have issued preferred units that ranked senior in right of distributions and liquidation to our common units, and we may issue senior partnership interests again in the future.
In prior years, we have issued preferred units that ranked senior in right of distributions and liquidation to our common units, and we may issue senior partnership interests again in the future.
Prior to paying any distribution on our common units, we will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur 39 Table of Contents and payments they make on our behalf.
Prior to paying any distribution on our common units, we will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf.
Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties.
Because we depend on our third party operators for all of the exploration, development and 51 Table of Contents production on our properties, we have no control over the operations related to our properties.
Our Sponsors and their respective affiliates are under no obligation to 36 Table of Contents make any acquisition opportunities available to us, except as provided for under the contribution agreement entered into in connection with our IPO.
Our Sponsors and their respective affiliates are under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement entered into in connection with our IPO.
Our partnership agreement replaces our General Partner’s fiduciary duties to our unitholders with contractual standards governing its duties. Our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards.
If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. 38 Table of Contents Our partnership agreement replaces our General Partner’s fiduciary duties to our unitholders with contractual standards governing its duties.
During the year ended December 31, 2024, payments we received from our top purchaser accounted for approximately 9.1% of our revenues. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law).
During the year ended December 31, 2025, payments we received from our top purchaser accounted for 50 Table of Contents approximately 7.7% of our revenues. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law).
Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. As of December 31, 2024, we received revenue from approximately 1,400 operators and we received approximately 41.2% of revenues from the top ten purchasers of our properties.
Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. As of December 31, 2025, we received revenue from approximately 1,300 operators and we received approximately 47.1% of revenues from the top ten purchasers of our properties.
In addition, consequences associated with the ongoing invasion of Ukraine by Russia, the conflict in the Middle East, and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries.
In addition, consequences associated with the ongoing invasion of Ukraine by Russia, the conflict in the Middle East, recent U.S. military action in Venezuela and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries.
As of February 21, 2025, the owners of our Sponsors own or control up to an aggregate of approximately 2.7% of our outstanding common units and Class B units (or approximately 2.2% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner.
As of February 20, 2026, the owners of our Sponsors own or control up to an aggregate of approximately 2.5% of our outstanding common units and Class B units (or approximately 2.3% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner.
For example, during the past five years, the posted price for WTI, has ranged from a low of $(36.98) per Bbl in April 2020 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021.
For example, during the past five years, the posted price for WTI, has ranged 45 Table of Contents from a low of $47.47 per Bbl in January 2021 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021.
For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive.
The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities. As of December 31, 2024, we had approximately $239.2 million in borrowings outstanding under our senior secured credit facility. As of February 21, 2025, we had approximately $308.2 million in borrowings outstanding under our senior secured credit facility.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities. As of December 31, 2025, we had approximately $441.5 million in borrowings outstanding under our senior secured credit facility.
Our future business performance may be volatile, and our cash flows may be unstable. Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold.
Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold.
If the operators of our properties are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read “Item 1.
If the operators of our properties are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.
In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our common unitholders may be materially adversely affected. 47 Table of Contents Risks Related to Our Indebtedness and Derivatives ​ Our derivative activities could result in financial losses and reduce earnings.
In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our common unitholders may be materially adversely affected.
In connection with these acquisitions, and in subsequent acquisitions, record title to a significant amount of the acquired mineral and royalty interests was conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries became the record owner of these interests.
We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, and in subsequent acquisitions, record title to a significant amount of the acquired mineral and royalty interests was conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries became the record owner of these interests.
In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. 53 Table of Contents We do not intend to retain cash from our operations for replacement capital expenditures.
In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement.
In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement, which withdrawal by the United States became effective on January 27, 2026.
Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply.
In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply.
As of December 31, 2024, we had 80,969,651 common units outstanding and 14,524,120 Class B units outstanding. Our Class B units are exchangeable on a one-for-one basis, together with an equal number of common units of the Operating Company (“OpCo common units”), for common units.
As of December 31, 2025, we had 93,396,488 common units outstanding and 14,491,540 Class B units outstanding. Our Class B units are exchangeable on a one-for-one basis, together with an equal number of common units of the Operating Company (“OpCo common units”), for common units.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. 47 Table of Contents Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.
Similarly, our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us.
Similarly, our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us. 36 Table of Contents Affiliates of our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire and own mineral and royalty interests.
The affirmative vote of 66 2 / 3 % of the outstanding Series A preferred units voting separately as a class, will be necessary to, among other things, (i) issue, authorize or create any additional Series A preferred units or any class or series of partnership interests (or any obligation or security convertible into, exchangeable for or evidencing the right to purchase any class or series of partnership interests) that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A preferred units or (ii) under certain circumstances, incur certain indebtedness for borrowed money.
The affirmative vote of 66 2 / 3 % of the outstanding Series A preferred units voting separately as a class, will be necessary to, among other things, (i) issue, authorize or create any additional Series A preferred units or any class or series of partnership interests (or any obligation or security convertible into, exchangeable for or evidencing the right to purchase any class or series of partnership interests) that, with respect to distributions on such partnership interests or distributions in respect of such partnership interests upon our liquidation, dissolution and winding up, ranks equal to or senior to the Series A preferred units or (ii) under certain circumstances, incur certain indebtedness for borrowed money. 44 Table of Contents Risks Related to Economic Conditions and Our Industry All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold.
Derivative contracts also expose us to the risk of financial loss in some circumstances, including when: ● production is less than expected; ● the counterparty to the derivative contract defaults on its contract obligation; or ● the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.
Derivative contracts also expose us to the risk of financial loss in some circumstances, including when: ● production is less than expected; ● the counterparty to the derivative contract defaults on its contract obligation; or ● the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected. 48 Table of Contents In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.
The operators of our properties use hydraulic fracturing for the completion of their wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the wellbore.
Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the wellbore. Typically, the fluid used in this process is primarily water.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025.
More recently, President Trump reversed certain climate-focused executive actions taken by President Biden. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to 61 Table of Contents reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.
Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.
Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations.
The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and is directly dependent on the performance of our business. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.
We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter. Our future business performance may be volatile, and our cash flows may be unstable.
The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations.
To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity. 60 Table of Contents The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations.
Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks. Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit.
Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit.
Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our mineral and royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties.
The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties.
Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations. 62 Table of Contents General Risk Factors ​ Increased costs of capital could materially adversely affect our business.
While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities. 63 Table of Contents Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.
Our Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.
These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.
We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells.
We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells. 54 Table of Contents Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain or grow our asset base, we would expect to reduce our distributions.
Therefore, the vote of three directors would be sufficient to prevent us from undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us.
The Board of Directors is made up of seven members. Therefore, the vote of three directors would be sufficient to prevent us from undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties.
If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 41 Table of Contents We may issue additional common units and other equity interests ranking junior to the Series A preferred units without unitholder approval, which would dilute existing common unitholder ownership interests.
The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. 56 Table of Contents If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available for distribution on common units may be adversely affected.
For example, our secured revolving credit facility restricts us from paying distributions to our common unitholders and OpCo common unitholders if our Debt to EBITDAX Ratio exceeds 3.0 to 1.0 on a trailing twelve-month basis. 48 Table of Contents A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.
A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.
On December 31, 2024, the WTI posted price for crude oil was $72.44 per Bbl and the Henry Hub spot market price of natural gas was $3.40 per MMBtu. On February 10, 2025, the WTI posted price for crude oil was $72.73 per Bbl and the Henry Hub spot market price of natural gas was $3.48 per MMBtu.
On December 31, 2025, the WTI posted price for crude oil was $57.26 per Bbl and the Henry Hub spot market price of natural gas was $4.00 per MMBtu. On February 17, 2026, the WTI posted price for crude oil was $62.53 per Bbl and the Henry Hub spot market price of natural gas was $3.13 per MMBtu.
Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us. 60 Table of Contents Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. The operators of our properties use hydraulic fracturing for the completion of their wells.
Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected. Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.
Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our oil and natural gas reserves and the operators’ production thereof and our cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources.
Relying on this finding, referred to as the 2009 Endangerment Finding, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources.
The services to be provided under such transition services agreements may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations. 52 Table of Contents If we are unable to make acquisitions on economically acceptable terms from our Sponsors, the Contributing Parties or third parties, our future growth will be limited.
The services to be provided under such transition services agreements may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations.
If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances.
Decreases in the 49 Table of Contents available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances.
Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution on common units. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available for distribution on common units.
Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution on common units.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeOur Security Officer/Director of IT provide periodic briefings to the audit committee regarding the Partnership’s cybersecurity risks and activities, including any recent cybersecurity incidents and related responses, cybersecurity systems testing, activities of third parties, and the like. Our audit committee provides regular updates to the board of directors on such reports.
Biggest changeOur Security Officer/Director of IT provide periodic briefings to the audit committee regarding the Partnership’s cybersecurity risks and activities, including any recent cybersecurity incidents and related responses, cybersecurity systems 66 Table of Contents testing, activities of third parties, and the like. Our audit committee provides regular updates to the board of directors on such reports.
We conduct periodic risk assessments to identify cybersecurity threats, as well as assessments in the event of a material change in our business practices that may affect information systems that are vulnerable to such cybersecurity 64 Table of Contents threats.
We conduct periodic risk assessments to identify cybersecurity threats, as well as assessments in the event of a material change in our business practices that may affect information systems that are vulnerable to such cybersecurity threats.
While we have experienced cybersecurity incidents, to date, we are not aware that we have experienced a material cybersecurity incident during the 2024 fiscal year.
While we have experienced cybersecurity incidents, to date, we are not aware that we have experienced a material cybersecurity incident during the 2025 fiscal year.
We also hold employee trainings on 65 Table of Contents privacy and cybersecurity, records and information management, conduct phishing tests and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population.
We also hold employee trainings on privacy and cybersecurity, records and information management, conduct phishing tests and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population.
In order to help develop these policies and procedures, we monitor the privacy and cybersecurity laws, regulations and guidance applicable to us, as well as proposed privacy and cybersecurity laws, regulations, guidance and emerging risks.
In order to help develop these policies and procedures, we monitor the privacy and cybersecurity 65 Table of Contents laws, regulations and guidance applicable to us, as well as proposed privacy and cybersecurity laws, regulations, guidance and emerging risks.
Our Chief Operating Officer and Security Officer/Director of IT are primarily responsible to assess and manage our material risks from cybersecurity threats with assistance from third-party service providers. Our Chief Operating Officer and Security Officer/Director of IT oversee our cybersecurity policies and processes, including those described in “Risk Management and Strategy” above.
Our Chief Operating Officer and Security Officer/Director of IT are primarily responsible for assessing and managing our material risks from cybersecurity threats with assistance from third-party service providers. Our Chief Operating Officer and Security Officer/Director of IT oversee our cybersecurity policies and processes, including those described in “Risk Management and Strategy” above.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeMine Safety Disclosures Not applicable. ​ 66 Table of Contents Part II
Biggest changeMine Safety Disclosures Not applicable. ​ 67 Table of Contents Part II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

11 edited+1 added−2 removed25 unchanged
Biggest changeIt is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. 67 Table of Contents Definition of Available Cash Our partnership agreement requires that, for the quarters ending March 31, June 30 and September 30, we distribute all of our available cash to common unitholders of record on the applicable record date by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 60 days following the end of such quarter.
Biggest changeIt is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.
Series A preferred units Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions.
Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions.
The limited liability company agreement of the Operating Company generally defines “available cash” as: ● the sum of: ● all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and ● as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash 68 Table of Contents for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter; ● less the amount of cash reserves established by the managing member of the Operating Company to: ● provide for the proper conduct of the business of the Operating Company and its subsidiaries (including reserves for future capital expenditures and for future credit needs of the Operating Company and its subsidiaries); ● comply with applicable law or any debt instrument or other agreement or obligation to which the managing member of the Operating Company, the Operating Company or any of their subsidiaries is a party or to which its assets are subject; and ● provide funds for distributions to the Operating Company’s unitholders for any one or more of the next four quarters.
The limited liability company agreement of the Operating Company generally defines “available cash” as: ● the sum of: ● all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and ● as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter; 69 Table of Contents ● less the amount of cash reserves established by the managing member of the Operating Company to: ● provide for the proper conduct of the business of the Operating Company and its subsidiaries (including reserves for future capital expenditures and for future credit needs of the Operating Company and its subsidiaries); ● comply with applicable law or any debt instrument or other agreement or obligation to which the managing member of the Operating Company, the Operating Company or any of their subsidiaries is a party or to which its assets are subject; and ● provide funds for distributions to the Operating Company’s unitholders for any one or more of the next four quarters.
For the quarter ending December 31, our partnership agreement requires that we distribute all of our available cash to common unitholders of record on the applicable record date by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.
For the quarter ending December 31, our partnership agreement requires that we distribute all of 68 Table of Contents our available cash to common unitholders of record on the applicable record date by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2024.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2025.
We cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Class B units As of February 21, 2025, we had 14,491,540 Class B units outstanding.
We cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Class B units As of February 20, 2026, we had 14,491,540 Class B units outstanding.
The Board of Directors approved the allocation of approximately 25% of our cash available for distribution on common units for the fourth quarter of 2024 for the repayment of $14.3 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2024.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2025 for the repayment of $13.4 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2025.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Our common units are listed on the NYSE under the symbol “KRP.” As of February 21, 2025, there were 92,502,231 common units outstanding held by 132 holders of record and 14,491,540 Class B units outstanding held by 14 holders of record.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Our common units are listed on the NYSE under the symbol “KRP.” As of February 20, 2026, there were 93,396,488 common units outstanding held by 126 holders of record and 14,491,540 Class B units outstanding held by 14 holders of record.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective 69 Table of Contents Class B Contribution subsequent to distributions on the Series A preferred units but prior to distributions on our common units. Common Units As of February 21, 2025, we had 92,502,231 common units outstanding.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution subsequent to distributions on the Series A preferred units but prior to distributions on our common units. 70 Table of Contents Common Units As of February 20, 2026, we had 93,396,488 common units outstanding.
Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter. The Series A preferred units and Class B units will receive the distribution preference described below.
Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter. The Series A preferred units and Class B units will receive the distribution preference described below. Series A preferred units As of February 20, 2026, we had 162,500 Series A preferred units outstanding.
Unregistered Sales of Equity Securities On May 30, 2024, we issued 6,323,175 common units to REP HR II, LP, REP HR III, LP, Ridgemont Equity Partners Affiliates II-B, LP, Ridgemont Equity Partners Affiliates III, LP and Ridgemont Equity Partners Energy Opportunity Fund, LP in exchange for 6,323,175 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).
Unregistered Sales of Equity Securities On February 12, 2025, we issued 3,162 common units to Gregory James Rasmussen in exchange for 3,162 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).
Removed
We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.
Added
Definition of Available Cash Our partnership agreement requires that, for the quarters ending March 31, June 30 and September 30, we distribute all of our available cash to common unitholders of record on the applicable record date by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 60 days following the end of such quarter.
Removed
On February 12, 2025, we issued 3,162 common units to Gregory James Rasmussen in exchange for 3,162 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeItem 6. [Reserved] 70 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 70 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 85 Item 8. Financial Statements and Supplementary Data 89 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 89 Item 9A. Controls and Procedures 90
Biggest changeItem 6. [Reserved] 71 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 71 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 85 Item 8. Financial Statements and Supplementary Data 89 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 89 Item 9A. Controls and Procedures 90

Item 7. Management's Discussion & Analysis

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

81 edited+9 added−26 removed71 unchanged
Biggest changeThe table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2024 ​ Year Ended December 31, 2023 ​ Year Ended December 31, 2022 ​ ​ High Low ​ High Low ​ High Low Oil ($/Bbl) ​ $ 87.69 ​ $ 66.73 ​ $ 93.67 ​ $ 66.61 ​ $ 123.64 ​ $ 71.05 Natural gas ($/MMBtu) ​ $ 13.20 ​ $ 1.21 ​ $ 3.78 ​ $ 1.74 ​ $ 9.85 ​ $ 3.46 ​ On February 10, 2025, the WTI posted price for crude oil was $72.73 per Bbl and the Henry Hub spot market price of natural gas was $3.48 per MMBtu. 72 Table of Contents The following table, as reported by the EIA, sets forth the average prices for oil and natural gas. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2024 ​ 2023 2022 Oil ($/Bbl) ​ ​ $ 76.63 ​ $ 77.58 ​ $ 94.90 Natural gas ($/MMBtu) ​ ​ $ 2.19 ​ $ 2.53 ​ $ 6.45 Rig Count Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
Biggest changeThe table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2025 ​ Year Ended December 31, 2024 ​ Year Ended December 31, 2023 ​ ​ High ​ ​ ​ Low ​ High ​ ​ ​ Low ​ High ​ ​ ​ Low Oil ($/Bbl) ​ $ 80.73 ​ $ 55.44 ​ $ 87.69 ​ $ 66.73 ​ $ 93.67 ​ $ 66.61 Natural gas ($/MMBtu) ​ $ 9.86 ​ $ 2.65 ​ $ 13.20 ​ $ 1.21 ​ $ 3.78 ​ $ 1.74 ​ On February 17, 2026, the WTI posted price for crude oil was $62.53 per Bbl and the Henry Hub spot market price of natural gas was $3.13 per MMBtu.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas.
Cash flows provided by financing activities for the year ended December 31, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B 82 Table of Contents contributions, partially offset by $243.2 million of distributions to common unitholders of TGR, $153.0 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.
Cash flows provided by financing activities for the year ended December 31, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B contributions, partially offset by $243.2 million of distributions to common unitholders of TGR, $153.0 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Definition of Available Cash.” We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Definition of Available Cash.” We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the 81 Table of Contents Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
As of December 31, 2024, 2023 and 2022, we recorded a full valuation allowance on our deferred tax assets. As a result, we did not recognize a benefit from our net operating losses for the respective periods. See Note 13—Income Taxes for further discussion.
As of December 31, 2025, 2024 and 2023, we recorded a full valuation allowance on our deferred tax assets. As a result, we did not recognize a benefit from our net operating losses for the respective periods. See Note 13—Income Taxes for further discussion.
As of December 31, 2024, 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.
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.
For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to Kimbell Tiger Acquisition Corporation (“TGR”) and $0.9 million in cash received from the dissolution of TGR.
For the year ended December 31, 2024, cash flows used in investing activities included the purchase of equipment. 82 Table of Contents For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to Kimbell Tiger Acquisition Corporation (“TGR”) and $0.9 million in cash received from the dissolution of TGR.
The data for a given property may also change substantially over time as a result of numerous factors, including development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions.
The data for a given property may also change substantially over time as a result of numerous factors, including development activity, evolving production history and a continual reassessment of the viability of production 84 Table of Contents under changing economic conditions.
General and Administrative Expense General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services.
General and Administrative Expense General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional 76 Table of Contents services.
The inclusion of our unevaluated costs into the amortization base is expected to be completed within five years. 75 Table of Contents Marketing and Other Deductions Marketing and other deductions include product marketing expense, which is a post-production expense.
The inclusion of our unevaluated costs into the amortization base is expected to be completed within five years. Marketing and Other Deductions Marketing and other deductions include product marketing expense, which is a post-production expense.
We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax 83 Table of Contents filing status of a unitholder for 2024.
We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2025.
Tax Matters Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income.
Tax Matters Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate 83 Table of Contents rates on our net taxable income.
Revisions of previous quantity estimates accounted for the change in 84 Table of Contents the total standardized measure of our reserves from December 31, 2023 to December 31, 2024, and were primarily related to technical revisions due to changes in commodity prices, historical and projected performance and other factors. Additionally, we continue to not intend to book PUD reserves.
Revisions of previous quantity estimates accounted for the change in the total standardized measure of our reserves from December 31, 2024 to December 31, 2025, and were primarily related to technical revisions due to changes in commodity prices, historical and projected performance and other factors. Additionally, we continue to not intend to book PUD reserves.
The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Basin or Producing Region ​ 2024 ​ 2023 ​ 2022 Permian Basin ​ 46 ​ 50 ​ 47 Mid‑Continent ​ 18 ​ 17 ​ 12 Terryville/Cotton Valley/Haynesville ​ 9 ​ 13 ​ 15 Appalachian Basin ​ — ​ 3 ​ 1 Bakken/Williston Basin ​ 7 ​ 6 ​ 6 Eagle Ford ​ 5 ​ 8 ​ 7 DJ Basin/Rockies/Niobrara ​ 1 ​ 1 ​ — Other ​ 1 ​ — ​ 4 Total ​ 87 ​ 98 ​ 92 ​ Sources of Our Revenue Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing.
The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Basin or Producing Region ​ 2025 ​ 2024 ​ 2023 Permian Basin ​ 46 ​ 46 ​ 50 Mid‑Continent ​ 14 ​ 18 ​ 17 Terryville/Cotton Valley/Haynesville ​ 11 ​ 9 ​ 13 Appalachian Basin ​ — ​ — ​ 3 Bakken/Williston Basin ​ 5 ​ 7 ​ 6 Eagle Ford ​ 7 ​ 5 ​ 8 DJ Basin/Rockies/Niobrara ​ 2 ​ 1 ​ 1 Other ​ — ​ 1 ​ — Total ​ 85 ​ 87 ​ 98 ​ Sources of Our Revenue Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing.
Material acquisitions that would impact the comparability of our results for the years ended December 31, 2024, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”), the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) and the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”).
Material acquisitions that would impact the comparability of our results for the years ended December 31, 2025, 2024 and 2023 include the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”), the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”) and the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”).
As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The Baker Hughes United States Rotary Rig count decreased 4.8% to 573 active land rigs at December 31, 2024 compared to 602 active land rigs at December 31, 2023.
As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The Baker Hughes United States rotary rig count decreased 8.0% to 527 active land rigs at December 31, 2025 compared to 573 active land rigs at December 31, 2024.
For additional information on our Amended Credit Agreement, please read Note 8―Long-Term Debt to the consolidated financial statements included elsewhere in this Annual Report. Off-Balance Sheet Arrangements As of December 31, 2024, we did not have any off-balance sheet arrangements.
For additional information on our Second A&R Credit Agreement, please read Note 8―Long-Term Debt to the consolidated financial statements included elsewhere in this Annual Report. Off-Balance Sheet Arrangements As of December 31, 2025, we did not have any off-balance sheet arrangements.
For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.” 73 Table of Contents Reserves and Pricing The tables below identify our proved reserves at December 31, 2024, 2023 and 2022, in each case based on the reserve report prepared by Ryder Scott.
For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.” Reserves and Pricing The tables below identify our proved reserves at December 31, 2025, 2024 and 2023, in each case based on the reserve report prepared by Ryder Scott.
As of December 31, 2024, we owned mineral and royalty interests in approximately 12.2 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.
Overview 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.
(Loss) Gain on Commodity Derivative Instruments Loss on commodity derivative instruments for the year ended December 31, 2024 included $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments compared to $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2023.
Gain (Loss) on Commodity Derivative Instruments Gain on commodity derivative instruments for the year ended December 31, 2025 included $7.2 million of mark-to-market gains and $4.9 million of gains on the settlement of commodity derivative instruments compared to $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments for the year ended December 31, 2024.
The following table presents the breakdown of our oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 2023 2022 Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil revenue ​ 71 % ​ 69 % ​ 46 % Natural gas revenue ​ 16 % ​ 22 % ​ 44 % NGL revenue ​ 13 % ​ 9 % ​ 10 % ​ ​ 100 % ​ 100 % ​ 100 % We have entered into oil and natural gas commodity derivative agreements, which extend through December 2026, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests.
The following table presents the breakdown of our oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ ​ ​ 2024 ​ ​ ​ 2023 Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil revenue ​ 62 % ​ 71 % ​ 69 % Natural gas revenue ​ 25 % ​ 16 % ​ 22 % NGL revenue ​ 13 % ​ 13 % ​ 9 % ​ ​ 100 % ​ 100 % ​ 100 % We have entered into oil and natural gas commodity derivative agreements, which extend through December 2027, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests.
The overall decrease in rig count at December 31, 2023 compared December 31, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.
The overall decrease in rig count at December 31, 2024 compared December 31, 2023 was primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2024 for the repayment of $14.3 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2024.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2025 for the repayment of $13.4 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2025.
We recognized an income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%. Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance.
We recognized an income tax expense of $3.8 million for the year ended December 31, 2023, resulting in an effective tax rate of 4.34%. Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance.
These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
These conflicts, along with the recent U.S. military action in Venezuela, and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
Income Tax Expense For the year ended December 31, 2024, we recognized an income tax benefit of $0.8 million, resulting in an effective tax benefit of 7.49%, compared to income tax expense of $3.8 million for the year ended December 31, 2023, resulting in an effective tax rate of 4.34%.
Income Tax (Benefit) Expense For the year ended December 31, 2025 we recognized an income tax benefit of $1.3 million, resulting in an effective tax benefit of 1.33%, compared to an income tax benefit of $0.8 million for the year ended December 31, 2024, resulting in an effective tax rate of 7.49%.
Interest Expense Interest expense for the year ended December 31, 2024 was $26.7 million as compared to interest expense of $26.0 million for the year ended December 31, 2023.
Interest expense for the year ended December 31, 2024 increased by $0.7 million compared to interest expense of $26.0 million for the year ended December 31, 2023.
The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the year ended December 31, 2023 as discussed below. 77 Table of Contents Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes.
The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the year ended December 31, 2024 as discussed below. 78 Table of Contents Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes.
The prices used to estimate proved reserves for the respective periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Estimated Net Proved Reserves 2024 ​ 2023 ​ 2022 Oil (MBbls) 20,001 ​ 19,800 ​ 12,355 Natural gas (MMcf) 204,253 ​ 204,542 ​ 160,298 Natural gas liquids (MBbls) 13,498 ​ 11,519 ​ 7,388 Total (MBoe)(6:1) 67,541 ​ 65,409 ​ 46,459 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Unweighted Arithmetic Average First ‑ Day ‑ of ‑ the ‑ Month Prices 2024 ​ 2023 ​ 2022 Oil (Bbls) ​ $ 75.48 ​ $ 78.22 ​ $ 93.67 Natural gas (Mcf) ​ $ 2.13 ​ $ 2.64 ​ $ 6.36 ​ Factors Affecting the Comparability of Our Results Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.
The prices used to estimate proved reserves for the respective periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Estimated Net Proved Reserves ​ ​ ​ 2025 ​ 2024 ​ 2023 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) 72,944 ​ 67,541 ​ 65,409 ​ 74 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Unweighted Arithmetic Average First ‑ Day ‑ of ‑ the ‑ Month Prices ​ ​ ​ 2025 ​ 2024 ​ 2023 Oil (Bbls) ​ $ 65.34 ​ $ 75.48 ​ $ 78.22 Natural gas (Mcf) ​ $ 3.39 ​ $ 2.13 ​ $ 2.64 ​ Factors Affecting the Comparability of Our Results Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.
The increase in lease bonus and other income is primarily due to a large number lease bonuses received during the year ended December 31, 2024. Our lease bonus and other income for the year ended December 31, 2023 increased by $2.5 million compared to $3.1 million for the year ended December 31, 2022.
Our lease bonus and other income for the year ended December 31, 2024 increased by $0.4 million compared to $5.6 million for the year ended December 31, 2023. The increase in lease bonus and other income is primarily due to a large number of lease bonuses received during the year ended December 31, 2024.
General and Administrative Expense General and administrative expenses for the year ended December 31, 2024 were $38.5 million, an increase of $2.8 million from $35.7 million for the year ended December 31, 2023.
General and Administrative Expense General and administrative expenses for the year ended December 31, 2025 were $39.7 million, an increase of $1.2 million from $38.5 million for the year ended December 31, 2024.
Financing Activities Cash flows used in financing activities were $247.5 million for the year ended December 31, 2024 compared to $78.4 million of cash flows provided by financing activities for the year ended December 31, 2023.
Financing Activities Cash flows used in financing activities were $13.2 million for the year ended December 31, 2025 compared to $247.5 million of cash flows provided by financing activities for the year ended December 31, 2024.
Loss on commodity derivative instruments for the year ended December 31, 2022 included $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2022 as a result of the maturity of derivative contracts with lower strike pricing.
Gain on commodity derivative instruments for the year ended December 31, 2023 included $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing.
Our operators received an average of $75.98 per Bbl of oil, $1.82 per Mcf of natural gas and $23.34 per Bbl of NGL for the volumes sold during the year ended December 31, 2024 and $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL for the volumes sold during the year ended December 31, 2023.
Our operators received an average of $63.84 per Bbl of oil, $2.93 per Mcf of natural gas and $23.15 per Bbl of NGL for the volumes sold during the year ended December 31, 2025 and $75.98 per Bbl of oil, $1.82 per Mcf of natural gas and $23.34 per Bbl of NGL for the volumes sold during the year ended December 31, 2024.
The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.
The Second A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $1.5 billion with an initial borrowing base of $625.0 million and an initial aggregate elected commitments amount of up to $625.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the Second A&R Credit Agreement to December 16, 2030.
The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties. For the year ended December 31, 2023, depreciation and depletion expense increased by $46.4 million from $50.1 million for the year ended December 31, 2022.
For the year ended December 31, 2024, depreciation and depletion expense increased by $38.6 million from $96.5 million for the year ended December 31, 2023. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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 129,000 gross wells, including over 50,000 wells in the Permian Basin.
Our mineral and royalty interests are located in 28 71 Table of Contents 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.
As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices.
Commodity Prices and Demand Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices.
Impairment of Oil and Natural Gas Properties ​ We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas. Marketing and Other Deductions Our marketing and other deductions include product marketing expense, which is a post-production expense.
Capital Expenditures During the year ended December 31, 2023, we paid approximately $490.7 million primarily to fund the MB Minerals Acquisition and the LongPoint Acquisition. During the year ended December 31, 2022, we paid approximately $141.3 million primarily to fund the Hatch Acquisition.
Capital Expenditures During the year ended December 31, 2025, we paid approximately $222.8 million primarily to fund the Boren Acquisition. During the year ended December 31, 2023, we paid approximately $490.7 million primarily to fund the MB Minerals Acquisition and the LongPoint Acquisition.
This gain was offset by the losses on the settlement of commodity derivative instruments. 78 Table of Contents Production and Ad Valorem Taxes Production and ad valorem taxes for the year ended December 31, 2024 remained flat at $20.4 million, compared to $20.3 million for the year ended December 31, 2023.
This gain was partially offset by the realized losses on the settlement of commodity derivative instruments. 79 Table of Contents Production and Ad Valorem Taxes Production and ad valorem taxes for the years ended December 31, 2025 and 2024 remained flat at $20.4 million.
It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities.
The Board of Directors may further change its policy with respect to cash distributions in the future. It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities.
We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units.
The non-controlling interest, which is held by the OpCo common unitholders, is not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units.
The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023. 79 Table of Contents Marketing and other deductions for the year ended December 31, 2023 decreased by $0.8 million from $13.4 million for the year ended December 31, 2022.
The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023.
The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of December 31, 2024: ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region ​ Gross Locations(1) ​ Net Locations(1) ​ Average Gross Horizontal Wells/DSU(2) Permian Basin ​ 4,528 ​ 29.02 ​ 12.0 Mid‑Continent 2,241 ​ 11.39 ​ 6.8 Haynesville 988 ​ 12.32 ​ 5.9 Appalachia ​ 247 ​ 2.11 ​ 7.6 Bakken 1,475 ​ 2.80 ​ 8.5 Eagle Ford 1,369 ​ 13.17 ​ 6.9 Rockies 162 ​ 1.00 ​ 10.5 Total 11,010 ​ 71.81 ​ 8.3 (1) These locations only include our major properties and do not include locations from our minor properties, which generally include properties with less than a 0.1% net revenue interest and are time consuming to quantify, but in the estimation of our management, could add up to an additional 15% to our net inventory in the aggregate.
The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of December 31, 2025: ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region ​ Gross Locations(1) ​ Net Locations(1) ​ Average Gross Horizontal Wells/DSU(2) Permian Basin ​ 4,446 ​ 32.50 ​ 12.0 Mid‑Continent 2,056 ​ 10.73 ​ 6.8 Haynesville 911 ​ 11.61 ​ 5.9 Appalachia ​ 230 ​ 2.03 ​ 7.6 Bakken 1,308 ​ 2.50 ​ 8.5 Eagle Ford 1,242 ​ 12.76 ​ 6.9 Rockies 148 ​ 0.98 ​ 10.5 Total 10,341 ​ 73.11 ​ 8.3 (1) These locations only include our major properties and do not include locations from our minor properties, which generally include properties with less than a 0.1% net revenue interest and are time consuming to quantify, but in the estimation of our management, could add up to an additional 15% to our net inventory in the aggregate.
This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 18.3% or $17.32 per Bbl of oil and 60.8% or $3.92 per Mcf of natural gas for the comparable periods.
This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 14.7% or $11.24 per Bbl of oil and increase of 60.7% or $1.33 per Mcf of natural gas for the comparable periods.
Our average depletion rate per barrel was $14.80 for the year ended December 31, 2024, an increase of $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 2023.
For the year ended December 31, 2024, our average depletion rate per barrel increased by $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 2023.
Cash flows provided by operating activities for the year ended December 31, 2024 were $250.9 million, an increase of $76.6 million compared to $174.3 million for the year ended December 31, 2023. Cash flows provided by operating activities for the year ended December 31, 2023 increased by $7.7 million compared to $166.6 million for the year ended December 31, 2022.
Cash flows provided by operating activities for the year ended December 31, 2025 were $246.5 million, a decrease of $4.4 million compared to $250.9 million for the year ended December 31, 2024. Cash flows provided by operating activities for the year ended December 31, 2024 increased by $76.6 million compared to $174.3 million for the year ended December 31, 2023.
Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.
Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025.
To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile and may continue to be volatile in the future.
To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.
The production volumes were 9,101,745 Boe or 24,868 Boe/d, for the year ended December 31, 2024, an increase of 1,729,123 Boe or 4,603 Boe/d, from 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023.
Our production volumes for the year ended December 31, 2024 increased by 1,729,123 Boe or 4,603 Boe/d, from 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023.
We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments.
We recorded a mark-to-market gain for the year ended December 31, 2025 as a result of the maturity of derivative contracts with lower strike pricing.
The year ended December 31, 2024 decreased 0.7% or $0.57 per Bbl of oil and 28.6% or $0.73 per Mcf of natural gas compared to the year ended December 31, 2023.
Average prices received by our operators during the year ended December 31, 2024 decreased 0.7% or $0.57 per Bbl of oil and 28.6% or $0.73 per Mcf of natural gas compared to the year ended December 31, 2023, which our operators received an average of $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL.
The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties. Impairment of Oil and Natural Gas Properties ​ We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025.
The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of December 31, 2024: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region(1) ​ Gross DUCs ​ Gross Permits ​ Net DUCs ​ Net Permits Permian Basin ​ 465 ​ 384 ​ 2.13 ​ 1.53 Mid‑Continent 124 ​ 69 ​ 1.16 ​ 0.32 Terryville/Cotton Valley/Haynesville 48 ​ 11 ​ 0.56 ​ 0.13 Appalachian Basin ​ 3 ​ 3 ​ 0.02 ​ 0.01 Bakken/Williston Basin 97 ​ 56 ​ 0.31 ​ 0.20 Eagle Ford 73 ​ 37 ​ 0.52 ​ 0.21 DJ Basin/Rockies/Niobrara 12 ​ 1 ​ 0.10 ​ 0.01 Total 822 ​ 561 ​ 4.80 ​ 2.41 (1) The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future.
The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of December 31, 2025: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region(1) ​ Gross DUCs ​ Gross Permits ​ Net DUCs ​ Net Permits Permian Basin ​ 660 ​ 393 ​ 3.53 ​ 1.63 Mid‑Continent 96 ​ 57 ​ 0.40 ​ 0.34 Terryville/Cotton Valley/Haynesville 62 ​ 27 ​ 0.34 ​ 0.18 Appalachian Basin ​ 6 ​ 4 ​ 0.02 ​ 0.04 Bakken/Williston Basin 39 ​ 116 ​ 0.17 ​ 0.13 Eagle Ford 29 ​ 25 ​ 0.16 ​ 0.09 DJ Basin/Rockies/Niobrara 8 ​ 6 ​ 0.04 ​ 0.02 Total 900 ​ 628 ​ 4.66 ​ 2.43 (1) The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future.
For example, we issued 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and we completed the LongPoint Acquisition partially with net proceeds from the Preferred Unit Transaction.
For example, the purchase price paid in the Boren Acquisition was partially funded by the proceeds from the underwritten public offering of 11,500,000 common units which resulted in net proceeds of approximately $163.6 million (the “2025 Equity Offering”) , we issued 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and the purchase price paid in the LongPoint Acquisition was partially funded by the net proceeds from the Preferred Unit Transaction.
See “Recent Developments—Fourth Quarter Distributions” above for discussion of our fourth quarter 2024 distributions. 81 Table of Contents Cash Flows The following table presents our cash flows for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 2023 ​ 2022 Cash Flow Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 250,916,075 ​ $ 174,267,667 ​ $ 166,636,493 Net cash used in investing activities ​ (209,891) ​ (246,676,974) ​ (374,723,901) Net cash (used in) provided by financing activities ​ (247,530,430) ​ 78,375,409 ​ 226,061,562 Net increase in cash and cash equivalents ​ $ 3,175,754 ​ $ 5,966,102 ​ $ 17,974,154 Operating Activities Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes.
Cash Flows The following table presents our cash flows for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ ​ 2024 ​ 2023 ​ ​ (In thousands) Cash Flow Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 246,462 ​ $ 250,916 ​ $ 174,268 Net cash used in investing activities ​ (223,481) ​ (210) ​ (246,677) Net cash (used in) provided by financing activities ​ (13,172) ​ (247,531) ​ 78,375 Net increase in cash and cash equivalents ​ $ 9,809 ​ $ 3,175 ​ $ 5,966 Operating Activities Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes.
Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate 74 Table of Contents results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.
Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized.
Investing Activities Cash flows used in investing activities for the year ended December 31, 2024 were $0.2 million compared to $246.7 million for the year ended December 31, 2023. For the year ended December 31, 2024, cash flows used in investing activities included the purchase of equipment.
Investing Activities Cash flows used in investing activities for the year ended December 31, 2025 were $223.5 million compared to $0.2 million for the year ended December 31, 2024. For the year ended December 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition.
Lease Bonus and Other Income For the year ended December 31, 2024 lease bonus and other income was $6.0 million, an increase of $0.4 million compared to $5.6 million for the year ended December 31, 2023.
Lease Bonus and Other Income For the year ended December 31, 2025 lease bonus and other income was $4.3 million, a decrease of $1.7 million compared to $6.0 million for the year ended December 31, 2024. The decrease in lease bonus and other income was due to a large lease bonus received during the year ended December 31, 2024.
For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report. 70 Table of Contents Overview We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States.
For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.
Indebtedness On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022).
Indebtedness On December 16, 2025, we entered into a Second A&R Credit Agreement, which amended and restated our existing Amended and Restated Credit Agreement, dated as of June 13, 2023 (as amended on July 24, 2023, December 8, 2023, and May 1, 2025).
A significant portion of our mineral and royalty interests are located in Texas basins and producing regions. 76 Table of Contents Results of Operations The table below summarizes our revenue and expenses and production data for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 ​ 2022 Operating Results: ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL revenues ​ $ 304,606,242 ​ $ 267,584,785 ​ $ 281,964,126 Lease bonus and other income ​ ​ 6,046,426 ​ ​ 5,594,855 ​ ​ 3,073,609 (Loss) gain on commodity derivative instruments, net ​ ​ (1,345,132) ​ ​ 20,888,972 ​ ​ (36,978,550) Total revenues ​ ​ 309,307,536 ​ ​ 294,068,612 ​ ​ 248,059,185 Costs and expenses ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ 20,406,282 ​ 20,326,477 ​ 16,238,814 Depreciation and depletion expense ​ 135,123,177 ​ 96,477,003 ​ 50,086,414 Impairment of oil and natural gas properties ​ 62,118,433 ​ 18,220,173 ​ — Marketing and other deductions ​ 16,122,163 ​ 12,564,619 ​ 13,383,074 General and administrative expense ​ 38,543,056 ​ 35,677,851 ​ 29,128,659 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative expense ​ ​ — ​ 927,699 ​ ​ 2,304,445 Total costs and expenses ​ 272,313,111 ​ 184,193,822 ​ 111,141,406 Operating income ​ 36,994,425 ​ 109,874,790 ​ 136,917,779 Other (expense) income ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity income in affiliate ​ ​ — ​ ​ — ​ ​ 2,668,844 Interest expense ​ (26,696,018) ​ (25,950,600) ​ (13,818,310) Loss on extinguishment of debt ​ — ​ (480,244) ​ ​ — Other expense ​ — ​ (180,765) ​ ​ 4,043,530 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ 3,508,691 ​ ​ 3,721,145 Net income before income taxes ​ ​ 10,298,407 ​ ​ 86,771,872 ​ ​ 133,532,988 Income tax (benefit) expense ​ ​ (771,329) ​ ​ 3,766,302 ​ ​ 2,738,702 Net income ​ ​ 11,069,736 ​ ​ 83,005,570 ​ ​ 130,794,286 Distribution and accretion on Series A preferred units ​ ​ (21,091,855) ​ ​ (6,310,215) ​ ​ — Net loss (income) and distributions and accretion on Series A preferred units attributable to non-controlling interests ​ ​ 1,254,112 ​ ​ (16,464,890) ​ ​ (18,822,552) Distribution on Class B units ​ ​ (70,742) ​ ​ (88,786) ​ ​ (42,243) Net (loss) income attributable to common units of Kimbell Royalty Partners, LP ​ $ (8,838,749) ​ $ 60,141,679 ​ $ 111,929,491 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (Bbls) ​ 2,836,913 ​ 2,392,622 ​ 1,425,842 Natural gas (Mcf) ​ 27,586,460 ​ 23,384,021 ​ 20,310,991 Natural gas liquids (Bbls) ​ 1,667,089 ​ 1,082,663 ​ 746,865 Combined volumes (Boe) (6:1) ​ 9,101,745 ​ 7,372,622 ​ 5,557,872 ​ Comparison of the Year Ended December 31, 2024 to the Year Ended December 31, 2023 and the Year Ended December 31, 2023 to the Year Ended December 31, 2022 Oil, Natural Gas and NGL Revenues For the year ended December 31, 2024, our oil, natural gas and NGL revenues were $304.6 million, an increase of $37.0 million from $267.6 million for the year ended December 31, 2023.
A significant portion of our mineral and royalty interests are located in Texas basins and producing regions. 77 Table of Contents Results of Operations The table below summarizes our revenue and expenses and production data for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ 2023 ​ ​ (In thousands, except production data) Operating Results: ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL revenues ​ $ 317,473 ​ $ 304,605 ​ $ 267,586 Lease bonus and other income ​ ​ 4,266 ​ ​ 6,047 ​ ​ 5,594 Gain (loss) on commodity derivative instruments, net ​ ​ 12,091 ​ ​ (1,345) ​ ​ 20,888 Total revenues ​ ​ 333,830 ​ ​ 309,307 ​ ​ 294,068 Costs and expenses ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ 20,440 ​ 20,407 ​ 20,326 Depreciation and depletion expense ​ 124,554 ​ 135,123 ​ 96,477 Impairment of oil and natural gas properties ​ — ​ 62,118 ​ 18,220 Marketing and other deductions ​ 16,350 ​ 16,122 ​ 12,566 General and administrative expense ​ 39,657 ​ 38,543 ​ 35,678 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative expense ​ ​ — ​ — ​ ​ 927 Total costs and expenses ​ 201,001 ​ 272,313 ​ 184,194 Operating income ​ 132,829 ​ 36,994 ​ 109,874 Other (expense) income ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest expense ​ (34,470) ​ (26,695) ​ (25,950) Loss on extinguishment of debt ​ — ​ — ​ (480) Other expense ​ (12) ​ — ​ ​ (181) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ — ​ ​ 3,509 Net income before income taxes ​ ​ 98,347 ​ ​ 10,299 ​ ​ 86,772 Income tax (benefit) expense ​ ​ (1,304) ​ ​ (771) ​ ​ 3,766 Net income ​ ​ 99,651 ​ ​ 11,070 ​ ​ 83,006 Distribution and accretion on Series A preferred units ​ ​ (34,852) ​ ​ (21,091) ​ ​ (6,310) Net (income) loss and distributions and accretion on Series A preferred units attributable to non-controlling interests ​ ​ (8,704) ​ ​ 1,254 ​ ​ (16,465) Distribution to Class B unitholders ​ ​ (58) ​ ​ (72) ​ ​ (89) Net income (loss) attributable to common units of Kimbell Royalty Partners, LP ​ $ 56,037 ​ $ (8,839) ​ $ 60,142 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (Bbls) ​ 3,061,920 ​ 2,836,913 ​ 2,392,622 Natural gas (Mcf) ​ 26,733,988 ​ 27,586,460 ​ 23,384,021 Natural gas liquids (Bbls) ​ 1,884,763 ​ 1,667,089 ​ 1,082,663 Combined volumes (Boe) (6:1) ​ 9,402,348 ​ 9,101,745 ​ 7,372,622 ​ Comparison of the Year Ended December 31, 2025 to the Year Ended December 31, 2024 and the Year Ended December 31, 2024 to the Year Ended December 31, 2023 Oil, Natural Gas and NGL Revenues For the year ended December 31, 2025, our oil, natural gas and NGL revenues were $317.5 million, an increase of $12.9 million from $304.6 million for the year ended December 31, 2024.
Impairment of Oil and Natural Gas Properties Accounting standards require that we periodically review the carrying value of our properties for possible impairment.
We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter. 75 Table of Contents Impairment of Oil and Natural Gas Properties Accounting standards require that we periodically review the carrying value of our properties for possible impairment.
The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the year ended December 31, 2024 as discussed below. Our revenues for the year ended December 31, 2023 decreased by $14.4 million, from $282.0 million for the year ended December 31, 2022.
The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas coupled with an increase in combined production volumes for the year ended December 31, 2025, partially offset by a decrease in the average prices received for oil and NGLs, as discussed below.
The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.
The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.
The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.
Cash flows provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR initial public offering (these proceeds were held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 equity offering and $0.4 million in contributions from Class B unitholders, partially offset by $183.3 million used to repay borrowings under our secured revolving credit facility, $126.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $3.3 million of restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.
Cash flows used in financing activities for the year ended December 31, 2025 consists primarily of $179.9 million used to redeem a portion of the Series A preferred units, $187.3 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $493.3 million used to repay borrowings under our secured revolving credit facility and $5.1 million of restricted units repurchased for tax withholding, partially offset by $163.6 million in proceeds from the 2025 Equity Offering and $695.6 million of additional borrowings under our secured revolving credit facility.
Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses.
The increase in general and administrative expenses was attributable to a $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses. Interest Expense Interest expense for the year ended December 31, 2025 was $34.5 million as compared to interest expense of $26.7 million for the year ended December 31, 2024.
Quarterly Distributions On February 27, 2025, the Board of Directors declared a quarterly cash distribution of $0.40 per common unit and OpCo common unit for the quarter ended December 31, 2024. We intend to pay the distributions on March 25, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2025.
We intend to pay the distributions on March 25, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2026. The $0.012498 excluded from the OpCo common unit distribution corresponds to a tax refund received by us in the fourth quarter of 2025.
General and administrative expenses for the year ended December 31, 2023 increased by $6.6 million from $29.1 million for the year ended December 31, 2022.
Our revenues for the year ended December 31, 2024 increased by $37.0 million, from $267.6 million for the year ended December 31, 2023.
Also contributing to the increase in interest expense was an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint Acquisition.
The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the partial redemption of the Series A preferred units and the Boren Acquisition.
Marketing and Other Deductions Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2024 were $16.1 million, an increase of $3.5 million from $12.6 million for the year ended December 31, 2023.
Marketing and other deductions for the year ended December 31, 2025 remained relatively flat at $16.4 million compared to $16.1 million for the year ended December 31, 2024. Marketing and other deductions for the year ended December 31, 2024 increased by $3.5 million from $12.6 million for the year ended December 31, 2023.
On December 8, 2023, we entered into the Second Amendment (as defined below) to the A&R Credit Agreement that, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million. See “Indebtedness” below for further discussion of our secured revolving credit facility.
On December 16, 2025, we entered into a Second Amended and Restated Credit Agreement (the “Second A&R Credit Agreement”). See “Indebtedness” below for further discussion of our secured revolving credit facility.
The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production. Depreciation and Depletion Expense Depreciation and depletion expense for the year ended December 31, 2024 was $135.1 million, an increase of $38.6 million from $96.5 million for the year ended December 31, 2023.
For the year ended December 31, 2024, production and ad valorem taxes remained relatively flat compared to $20.3 million for the year ended December 31, 2023. Depreciation and Depletion Expense Depreciation and depletion expense for the year ended December 31, 2025 was $124.6 million, a decrease of $10.5 million from $135.1 million for the year ended December 31, 2024.
We will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2024. We intend to pay the distribution subsequent to February 27, 2025, and prior to the distribution on the common units and OpCo common units.
Under the limited liability company agreement of the Operating Company, we do not reimburse the Operating Company for federal income tax refunds received by us. We will pay a quarterly cash distribution on the Series A preferred units of approximately $2.5 million for the quarter ended December 31, 2025.
Business Environment Global Conflicts In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, there is no indication on the extent of the ceasefire.
We intend to pay the distribution subsequent to February 26, 2026, and prior to the distribution on the common units and OpCo common units. 72 Table of Contents Business Environment Global Conflicts In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country.
(2) Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of December 31, 2024. DSUs vary in size. 71 Table of Contents Recent Developments Equity Offering On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”).
(2) Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of December 31, 2025. DSUs vary in size. Recent Developments Quarterly Distributions On February 26, 2026, the Board of Directors declared a quarterly cash distribution of $0.37 per common unit and $0.357502 per OpCo common unit for the quarter ended December 31, 2025.
For the year ended December 31, 2023, our average depletion rate per barrel increased by $4.19 per barrel from the $8.84 average depletion rate per barrel for the year ended December 31, 2022.
Our average depletion rate per barrel was $13.22 for the year ended December 31, 2025, a decrease of $1.58 per barrel from the $14.80 average depletion rate per barrel for the year ended December 31, 2024.
Average prices received by our operators during the year ended December 31, 2023 decreased 16.6% or $15.19 per Bbl of oil and 57.8% or $3.49 per Mcf of natural gas compared to the year ended December 31, 2022, which our operators received an average of $91.74 per Bbl of oil, $6.04 per Mcf of natural gas and $38.19 per Bbl of NGL.
The year ended December 31, 2025 decreased 16.0% or $12.14 per Bbl of oil and increased 61.0% or $1.11 per Mcf of natural gas compared to the year ended December 31, 2024.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeOur computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies. 87 Table of Contents The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 ​ 2022 Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income ​ $ 11,069,736 ​ $ 83,005,570 ​ $ 130,794,286 Depreciation and depletion expense ​ ​ 135,123,177 ​ ​ 96,477,003 ​ ​ 50,086,414 Interest expense ​ ​ 26,696,018 ​ ​ 25,950,600 ​ ​ 13,818,310 Cash distribution from affiliate ​ ​ — ​ ​ — ​ ​ 385,326 Income tax (benefit) expense ​ ​ (771,329) ​ ​ 3,766,302 ​ ​ 2,738,702 EBITDA ​ ​ 172,117,602 ​ ​ 209,199,475 ​ ​ 197,823,038 Impairment of oil and natural gas properties ​ ​ 62,118,433 ​ ​ 18,220,173 ​ ​ — Unit-based compensation ​ ​ 16,384,668 ​ ​ 13,111,522 ​ ​ 11,107,639 Loss on extinguishment of debt ​ ​ — ​ ​ 480,244 ​ ​ — Loss (gain) on derivative instruments, net of settlements ​ ​ 12,211,660 ​ ​ (26,371,058) ​ ​ (14,300,570) Cash distribution from affiliate ​ ​ — ​ ​ — ​ ​ 645,451 Equity income in affiliate ​ ​ — ​ ​ — ​ ​ (2,668,844) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ ​ (3,508,691) ​ ​ (3,721,145) General and administrative expense ​ ​ — ​ ​ 927,699 ​ ​ 2,304,445 Consolidated Adjusted EBITDA ​ ​ 262,832,363 ​ ​ 212,059,364 ​ ​ 191,190,014 Adjusted EBITDA attributable to non-controlling interest ​ ​ (44,882,910) ​ ​ (46,475,531) ​ ​ (27,154,867) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 217,949,453 ​ ​ 165,583,833 ​ ​ 164,035,147 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 20,989,788 ​ ​ 18,520,334 ​ ​ 9,583,004 Cash distribution on Series A preferred units ​ ​ 16,223,494 ​ ​ 4,551,746 ​ ​ — Cash income tax refund ​ ​ — ​ ​ 1,641,675 ​ ​ 3,082,245 Distribution on Class B units ​ ​ 70,742 ​ ​ 88,786 ​ ​ 42,243 Cash available for distribution on common units ​ $ 180,665,429 ​ $ 140,781,292 ​ $ 151,327,655 ​ 88 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2024 ​ 2023 ​ 2022 Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 250,916,075 ​ $ 174,267,667 ​ $ 166,636,493 Interest expense ​ 26,696,018 ​ 25,950,600 ​ 13,818,310 Income tax (benefit) expense ​ ​ (771,329) ​ ​ 3,766,302 ​ ​ 2,738,702 Impairment of oil and natural gas properties ​ (62,118,433) ​ (18,220,173) ​ — Amortization of right-of-use assets ​ ​ (349,203) ​ (336,080) ​ ​ (319,674) Amortization of loan origination costs ​ (2,126,719) ​ (1,943,025) ​ (1,872,700) Loss on extinguishment of debt ​ ​ — ​ ​ (480,244) ​ ​ — Equity income in affiliate, net ​ — ​ — ​ (716,481) Forfeiture of restricted units ​ ​ — ​ ​ — ​ ​ 19,813 Unit-based compensation ​ (16,384,668) ​ (13,111,522) ​ (11,107,639) (Loss) gain on derivative instruments, net of settlements ​ (12,211,660) ​ 26,371,058 ​ 14,300,570 Changes in operating assets and liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL receivables ​ (13,096,963) ​ 12,026,760 ​ 11,846,567 Accounts receivable and other current assets ​ 1,072,015 ​ (1,863,376) ​ 511,319 Accounts payable ​ 89,105 ​ (509,400) ​ (399,318) Other current liabilities ​ 21,245 ​ (1,263,804) ​ (1,590,016) Operating lease liabilities ​ ​ 382,119 ​ 348,668 ​ ​ 324,913 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ 3,508,691 ​ ​ 3,721,145 Other assets and liabilities ​ ​ — ​ 687,353 ​ ​ (88,966) EBITDA ​ ​ 172,117,602 ​ ​ 209,199,475 ​ ​ 197,823,038 Add: ​ ​ ​ ​ ​ ​ ​ ​ ​ Impairment of oil and natural gas properties ​ 62,118,433 ​ 18,220,173 ​ — Unit-based compensation ​ 16,384,668 ​ 13,111,522 ​ 11,107,639 Loss on extinguishment of debt ​ — ​ 480,244 ​ — Loss (gain) on derivative instruments, net of settlements ​ 12,211,660 ​ (26,371,058) ​ (14,300,570) Cash distribution from affiliate ​ ​ — ​ ​ — ​ ​ 645,451 Equity income in affiliate ​ ​ — ​ ​ — ​ ​ (2,668,844) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in Trust Account ​ ​ — ​ ​ (3,508,691) ​ ​ (3,721,145) General and administrative expense ​ ​ — ​ ​ 927,699 ​ ​ 2,304,445 Consolidated Adjusted EBITDA ​ ​ 262,832,363 ​ ​ 212,059,364 ​ ​ 191,190,014 Adjusted EBITDA attributable to non-controlling interest ​ ​ (44,882,910) ​ ​ (46,475,531) ​ ​ (27,154,867) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 217,949,453 ​ ​ 165,583,833 ​ ​ 164,035,147 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 20,989,788 ​ ​ 18,520,334 ​ ​ 9,583,004 Cash distribution on Series A preferred units ​ ​ 16,223,494 ​ ​ 4,551,746 ​ ​ — Cash income tax refund ​ ​ — ​ ​ 1,641,675 ​ ​ 3,082,245 Distribution on Class B units ​ ​ 70,742 ​ ​ 88,786 ​ ​ 42,243 Cash available for distribution on common units ​ $ 180,665,429 ​ $ 140,781,292 ​ $ 151,327,655 ​ ​
Biggest changeOur computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies. 87 Table of Contents The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ 2023 ​ ​ (In thousands) Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income ​ $ 99,651 ​ $ 11,070 ​ $ 83,006 Depreciation and depletion expense ​ ​ 124,554 ​ ​ 135,123 ​ ​ 96,477 Interest expense ​ ​ 34,470 ​ ​ 26,695 ​ ​ 25,950 Income tax (benefit) expense ​ ​ (1,304) ​ ​ (771) ​ ​ 3,766 EBITDA ​ ​ 257,371 ​ ​ 172,117 ​ ​ 209,199 Impairment of oil and natural gas properties ​ ​ — ​ ​ 62,118 ​ ​ 18,220 Unit-based compensation ​ ​ 16,323 ​ ​ 16,386 ​ ​ 13,112 Loss on extinguishment of debt ​ ​ — ​ ​ — ​ ​ 480 (Gain) loss on derivative instruments, net of settlements ​ ​ (7,227) ​ ​ 12,211 ​ ​ (26,371) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ ​ — ​ ​ (3,509) General and administrative expense ​ ​ — ​ ​ — ​ ​ 927 Consolidated Adjusted EBITDA ​ ​ 266,467 ​ ​ 262,832 ​ ​ 212,058 Adjusted EBITDA attributable to non-controlling interest ​ ​ (35,793) ​ ​ (44,884) ​ ​ (46,476) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 230,674 ​ ​ 217,948 ​ ​ 165,582 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 27,624 ​ ​ 20,988 ​ ​ 18,519 Cash distribution to Series A preferred unitholders ​ ​ 10,523 ​ ​ 16,223 ​ ​ 4,552 Cash income tax (refund) expense ​ ​ (2,112) ​ ​ — ​ ​ 1,642 Distribution to Class B unitholders ​ ​ 58 ​ ​ 72 ​ ​ 89 Cash available for distribution on common units ​ $ 194,581 ​ $ 180,665 ​ $ 140,780 ​ 88 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2025 ​ 2024 ​ 2023 ​ ​ (In thousands) Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 246,462 ​ $ 250,916 ​ $ 174,268 Interest expense ​ 34,470 ​ 26,695 ​ 25,950 Income tax (benefit) expense ​ ​ (1,304) ​ ​ (771) ​ ​ 3,766 Impairment of oil and natural gas properties ​ — ​ (62,118) ​ (18,220) Amortization of right-of-use assets ​ ​ (348) ​ (349) ​ ​ (336) Amortization of loan origination costs ​ (2,356) ​ (2,126) ​ (1,943) Loss on extinguishment of debt ​ ​ — ​ ​ — ​ ​ (480) Unit-based compensation ​ (16,323) ​ (16,386) ​ (13,112) Forfeiture of restricted units ​ ​ 57 ​ — ​ ​ ​ Gain (loss) on derivative instruments, net of settlements ​ 7,227 ​ (12,211) ​ 26,371 Changes in operating assets and liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL receivables ​ (9,343) ​ (13,096) ​ 12,027 Accounts receivable and other current assets ​ (1,352) ​ 1,071 ​ (1,863) Accounts payable ​ 917 ​ 90 ​ (509) Other current liabilities ​ (1,039) ​ 20 ​ (1,264) Operating lease liabilities ​ ​ 303 ​ 382 ​ ​ 348 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ — ​ — ​ ​ 3,509 Other assets and liabilities ​ ​ — ​ — ​ ​ 687 EBITDA ​ ​ 257,371 ​ ​ 172,117 ​ ​ 209,199 Add: ​ ​ ​ ​ ​ ​ ​ ​ ​ Impairment of oil and natural gas properties ​ — ​ 62,118 ​ 18,220 Unit-based compensation ​ 16,323 ​ 16,386 ​ 13,112 Loss on extinguishment of debt ​ — ​ — ​ 480 (Gain) loss on derivative instruments, net of settlements ​ (7,227) ​ 12,211 ​ (26,371) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in Trust Account ​ ​ — ​ ​ — ​ ​ (3,509) General and administrative expense ​ ​ — ​ ​ — ​ ​ 927 Consolidated Adjusted EBITDA ​ ​ 266,467 ​ ​ 262,832 ​ ​ 212,058 Adjusted EBITDA attributable to non-controlling interest ​ ​ (35,793) ​ ​ (44,884) ​ ​ (46,476) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 230,674 ​ ​ 217,948 ​ ​ 165,582 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 27,624 ​ ​ 20,988 ​ ​ 18,519 Cash distribution to Series A preferred unitholders ​ ​ 10,523 ​ ​ 16,223 ​ ​ 4,552 Cash income tax (refund) expense ​ ​ (2,112) ​ ​ — ​ ​ 1,642 Distribution to Class B unitholders ​ ​ 58 ​ ​ 72 ​ ​ 89 Cash available for distribution on common units ​ $ 194,581 ​ $ 180,665 ​ $ 140,780 ​ ​
The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense of approximately $2.4 million annually, assuming that our indebtedness remained constant throughout the year.
The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense of approximately $4.4 million annually, assuming that our indebtedness remained constant throughout the year.
We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income.
We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of a variable interest entity, which include general and administrative expense and interest income.
During the years ended December 31, 2024, 2023 and 2022, our top purchaser accounted for approximately 9.1%, 6.7% and 11.3%, respectively, of our oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.
During the years ended December 31, 2025, 2024 and 2023, our top purchaser accounted for approximately 7.7%, 9.1% and 6.7%, respectively, of our oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.
While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2024, we had six counterparties to our derivative contracts, which are also lenders under our credit facility.
While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2025, we had seven counterparties to our derivative contracts, which are also lenders under our credit facility.
Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first 85 Table of Contents nearby month futures contract of the contract period.
Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period.
Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
The counterparties to the contracts are unrelated third parties. Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Interest Rate Risk We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2024, we had total borrowings outstanding under our secured revolving credit facility of $239.2 million.
Interest Rate Risk We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2025, we had total borrowings outstanding under our secured revolving credit facility of $441.5 million.
The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.
The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of 85 Table of Contents fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas.
However, rising inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure.
Inflation Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 2023 through December 31, 2025. However, rising inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure.
Non-GAAP Financial Measures Adjusted EBITDA and Cash Available for Distribution on Common Units Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects. 86 Table of Contents Non-GAAP Financial Measures Adjusted EBITDA and Cash Available for Distribution on Common Units Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
Removed
On January 27, 2021, we entered into an interest rate swap with Citibank , which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. In 2022 we entered into termination agreements with Citibank to unwind the interest rate swap.
Removed
The terminations resulted in a $6.4 million gain for the year ended December 31, 2022, which is included in other income (expense) in the accompanying consolidated statements of operations.
Removed
We used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of our secured revolving credit facility from a floating to a fixed rate. 86 Table of Contents Inflation Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 2022 through December 31, 2024.
Removed
In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

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