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What changed in Kimbell Royalty Partners, LP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Kimbell Royalty Partners, LP's 2023 and 2024 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 2024 report.

+330 added−358 removedSource: 10-K (2025-02-27) vs 10-K (2024-02-21)

Top changes in Kimbell Royalty Partners, LP's 2024 10-K

330 paragraphs added · 358 removed · 276 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

77 edited+6 added−25 removed171 unchanged
Biggest changeAs of December 31, 2023, there were approximately 1,100 operators actively producing on our acreage, with our top ten operators (EP Energy E&P Company, L.P., SWN Production Company LLC, XTO Energy, Inc., Chesapeake Operating, Inc., EOG Resources, Inc., Vital Energy, Mewbourne Oil Company, Pioneer Natural Resources Company, Chevron USA, Inc., and Diamondback E&P, LLC) together accounting for approximately 38.0% of our revenues. 15 Table of Contents During the years ended December 31, 2023, 2022 and 2021, payments we received from our top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of our revenues.
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.
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.
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, 2023 ​ ​ 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, 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.
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, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 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.
Wells The following table sets forth the well count in which we had mineral or royalty interest: ​ ​ ​ Basin or Producing Region ​ December 31, 2023 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, 2023, 2022 and 2021 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, 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.
On August 30, 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 Rule, and in June 2021, the EPA and the Army Corp of Engineers announced their intention to initiate a new rulemaking process to restore the pre-2015 definition of “waters of the United States.” The proposed rule was published on December 7, 2021.
On August 30, 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 Rule, and in June 2021, the EPA and the Army Corp of Engineers announced their intention to initiate a new rulemaking process to restore the 2015 definition of “waters of the United States.” The proposed rule was published on December 7, 2021.
More recently, President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50 percent to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030, and in November 2021, the international community gathered again in Glasgow at the 26th Conference of the Parties (“COP26”).
In April 2021, President Biden announced a new, more rigorous nationally determined emissions reduction level of 50 percent to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030, and in November 2021, the international community gathered again in Glasgow at the 26th Conference of the Parties (“COP26”).
Fortson, R. Ravnaas, Taylor and Wynne. (2) Includes common units representing limited partner interests in the Partnership (“common units”) beneficially owned by the Sponsors other than those reflected as held by Kimbell GP Holdings, LLC. Also includes common units beneficially owned by our directors and officers and other of our affiliates.
R. Ravnaas, Taylor and Wynne. (2) Includes common units representing limited partner interests in the Partnership (“common units”) beneficially owned by the Sponsors other than those reflected as held by Kimbell GP Holdings, LLC. Also includes common units beneficially owned by our directors and officers and other of our affiliates.
(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. 20 Table of Contents ORRIs The following table sets forth information about our ORRIs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2023 ​ ​ 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, 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.
These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations. 25 Table of Contents Regulation The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.
These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations. 24 Table of Contents Regulation The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.
As of December 31, 2023, 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, 2023, 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, 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.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing 22 Table of Contents requirements and forecasts of future production rates.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing 21 Table of Contents requirements and forecasts of future production rates.
Summary of Estimated Proved Reserves Estimates of reserves as of December 31, 2023, 2022 and 2021 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, 2023, 2022 and 2021, 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, 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.
Remediation The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and analogous state laws, generally impose strict, joint and several liability, without regard to fault or 26 Table of Contents legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.
Remediation The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and analogous state laws, generally impose strict, joint and several liability, without regard to fault or 25 Table of Contents legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.
(2) Reflects mineral interests in approximately 127,832 total gross (9,760 net) undeveloped acres. 24 Table of Contents ORRIs The following table sets forth information relating to our acreage for our ORRIs at December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 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.
We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by third party producers in development activities on our acreage. 17 Table of Contents ● Exposure to many of the leading resource plays in the United States.
We believe that we will continue to benefit from these cost-free additions to production and reserves for the 16 Table of Contents foreseeable future as a result of technological advances and continuing interest by third party producers in development activities on our acreage. ● Exposure to many of the leading resource plays in the United States.
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 27 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 26 Table of Contents contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs.
Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations. 19 Table of Contents The following tables present information about our mineral and royalty interest acreage, well count and production by basin and producing region. We may own more than one type of interest in the same tract of land.
Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations. 18 Table of Contents The following tables present information about our mineral and royalty interest acreage, well count and production by basin and producing region. We may own more than one type of interest in the same tract of land.
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 28 Table of Contents into force in November 2016.
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.
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, 2023, 2022 and 2021 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, 2024, 2023 and 2022 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, 2023, 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, 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.
Overview of Our Oil and Gas Assets and Operations As of December 31, 2023, 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, 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.
The members of our management team and Board of Directors have an average of over 31 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 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.
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 affect production from the acreage underlying our mineral and royalty interests and materially adversely affect 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 affect on our business and prospects.
Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder 21 Table of Contents Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming.
Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder 20 Table of Contents Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming.
As of December 31, 2023, 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, 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.
For example, most recently 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 additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations.
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 16, 2024: (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 21, 2025: (1) The Sponsors are affiliates of our founders, Messrs.
At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 30 Table of Contents Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.
At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.
As of December 31, 2023, 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, 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.
Certain Relationships and Related Party Transactions , and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.” ● Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests. Our assets consist of diversified mineral and royalty interests.
Certain Relationships and Related Party Transactions , and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.” 15 Table of Contents ● Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests. Our assets consist of diversified mineral and royalty interests.
Redevelopment of the field with horizontal drilling and 18 Table of Contents modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields and long reserve life with multiple stacked producing zones. ● Appalachian Basin.
Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields and long reserve life with multiple stacked producing zones. ● Appalachian Basin.
A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2023 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 34 years of reservoir and operations experience. Mr. R.
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.
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, 2023, Kimbell Operating had approximately 29 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, 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%.
Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service 32 Table of Contents on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.
Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs.
In April 2020, the EPA and the United States Army Corps of Engineers issued a new final waters of the United States (“WOTUS”) definition that continues to provide a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction.
In April 2020, the EPA and the United States Army Corps of Engineers issued a new final waters of the United States (“WOTUS”) definition that provided a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction.
Circuit Court for the D.C. Circuit. In addition, on January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider publishing a proposed rule suspending, revising or rescinding the 2020 rules.
Circuit. In addition, on January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider publishing a proposed rule suspending, revising or rescinding the 2020 rules.
These laws and regulations may limit the amount of oil and 31 Table of Contents natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill.
These laws and regulations may limit the amount of oil and natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill.
However, the rules currently remain in effect. In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources.
In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources.
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”).
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”).
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.
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.
More stringent laws and regulations, including finalizing of the draft rule announced in January 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 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.
The unweighted arithmetic average first day of the month prices were $78.22, $93.67 and $66.56 per Bbl for oil and $2.64, $6.36 and $3.60 per MMBtu for natural gas at December 31, 2023, 2022 and 2021, 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 $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.
If a price equivalent conversion based on the twelve-month average prices for the y ears ended December 31, 2023, 2022 and 2021 was used, the conversion factor would be approximately 29.66 Mcf per Bbl of oil, 14.7 Mcf per Bbl of oil and 18.5 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, 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.
The following table presents our estimated proved developed oil and natural gas reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2023 ​ ​ 2022 ​ ​ 2021 ​ Estimated proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (MBbls) ​ 19,800 ​ 12,355 ​ 12,511 ​ Natural gas (MMcf) ​ 204,542 ​ 160,298 ​ 157,764 ​ Natural gas liquids (MBbls) ​ 11,519 ​ 7,388 ​ 6,669 ​ Total (MBoe)(6:1) (1) ​ 65,409 ​ 46,459 ​ 45,474 ​ (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, ​ ​ ​ 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.
Additionally, in May 2023, the Supreme Court of the United States issued its decision in a case, Sackett v. EPA , that clarified and narrowed the reach of federal jurisdiction under the Clean Water Act.
Additionally, in May 2023, the Supreme Court of the United States issued its decision in a case, Sackett v. EPA , that clarified and narrowed the reach of federal jurisdiction under the Clean Water Act by focusing on water bodies forming geographic features.
Risk Factors.” Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2023, which is included as an exhibit to this Annual Report. 23 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, ​ ​ 2023 ​ 2022 ​ 2021 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (Bbls) ​ ​ 2,392,622 ​ ​ 1,425,842 ​ ​ 1,343,771 Natural gas (Mcf) ​ ​ 23,384,021 ​ ​ 20,310,991 ​ ​ 19,085,400 Natural gas liquids (Bbls) ​ ​ 1,082,663 ​ ​ 746,865 ​ ​ 714,494 Total (Boe)(6:1) (1) ​ ​ 7,372,622 ​ ​ 5,557,872 ​ ​ 5,239,165 Average daily production (Boe/d)(6:1) ​ ​ 20,265 ​ ​ 15,025 ​ ​ 14,354 Average Realized Prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (per Bbl) ​ $ 76.55 ​ $ 91.74 ​ $ 64.86 Natural gas (per Mcf) ​ $ 2.55 ​ $ 6.04 ​ $ 3.51 Natural gas liquids (per Bbl) ​ $ 23.01 ​ $ 38.19 ​ $ 29.33 Average Unit Cost per Boe (6:1) ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ $ 2.76 ​ $ 2.92 ​ $ 2.00 (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, 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.
As of December 31, 2023, there were 98 rigs (representing 16.3% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 92 rigs operating on our acreage as of December 31, 2022. Please read “Item 7.
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.
Of the $50.6 million, $13.8 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2024. 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, $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.
If the final rule announced in December 2022 or the new regulation from August 2023 is ultimately implemented, the expansion of 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 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.
In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the regulations applicable to sources in the production and processing segments and removed the transmission and storage segments from the source category, which removes them from the scope of the regulations. However, these 2020 rules are being challenged in the U.S.
In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the regulations applicable to sources in the production and processing segments and removed the transmission and storage segments from the source category, which removes them from the scope of the regulations. The 2020 rules were later challenged in the U.S. Circuit Court for the D.C.
As of December 31, 2023, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 65,409 MBoe (47.9% liquids, consisting of 30.3% oil and 17.6% 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, 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.
During the year ended December 31, 2023, the Board of Directors approved the repayment of $50.6 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units.
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.
The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 65,409 MBoe (47.9% liquids, consisting of 30.3% oil and 17.6% 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 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.
(3) Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP, certain affiliates of Hatch Royalty LLC and MB Minerals, L.P.
(3) Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP and MB Minerals L.P. and other holders or their respective affiliates.
President Biden has 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.
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.
When production or drilling ceases on the leased property, the lease is typically terminated, 14 Table of Contents subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party.
The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party.
For the year ended December 31, 2023, our oil, natural gas and NGL revenues were generated 69% from oil sales, 22% from natural gas sales and 9% from NGL sales.
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.
A key feature of the Anadarko Basin is the stacked geologic horizons including the Cana-Woodford and Springer shale in the SCOOP and STACK. ● Terryville/Cotton Valley/Haynesville. We own a substantial position in the core of the Terryville Field that the Contributing Parties acquired in 2007. Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp.
A key feature of the Anadarko Basin is the stacked geologic horizons including the Cana-Woodford and Springer shale in the SCOOP and STACK. 17 Table of Contents ● Terryville/Cotton Valley/Haynesville. We own a substantial position in the core of the Terryville Field that the Contributing Parties acquired in 2007.
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. 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.
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.
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 13.2% 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.
We believe that our employees are one of our greatest assets and that we are made up of talented and dedicated employees 33 Table of Contents working together to achieve common and rewarding goals. We value integrity, hard work, dedication and teamwork.
We believe that our employees are one of our greatest assets and that we are made up of talented and dedicated employees working together to achieve common and rewarding goals. We value integrity, hard work, dedication and teamwork. Our goal is to promote an environment where employees are encouraged to do their best work with high professional standards.
(4) Kimbell Operating has entered into a management services agreement with us and separate management services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties for the provision of certain management, administrative and operational services. 13 Table of Contents Significant Acquisitions On May 17, 2023, we completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”).
(4) Kimbell Operating has entered into a management services agreement with us and separate management services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties for the provision of certain management, administrative and operational services. 13 Table of Contents Our Oil and Gas Assets We categorize our oil and gas assets into two groups: mineral interests and overriding royalty interests.
We believe this arrangement will give us access to third party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13.
Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services. We believe this arrangement will give us access to third party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13.
Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com. These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.
These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this Annual Report. ​
More recently, the United States and other participating countries reaffirmed these emission reduction goals at the 27th Conference of the Parties (“COP27”) in November 2022. The impacts of these efforts, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international conventions cannot be predicted at this time.
The impacts of international efforts, pledges, agreements and any legislation or regulation promulgated to fulfill prior commitments by the United States under the Paris Agreement or other international conventions cannot be predicted at this time.
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. 16 Table of Contents 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.
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 do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future.
States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future.
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, 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.
We have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R. Ravnaas, Taylor and Wynne provide, directly or indirectly, any oil and gas diligence, reserve engineering or other business services.
We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. We have a right to participate, at our option and on substantially the same or better terms, in up to 50% of any acquisitions, other than de minimis acquisitions, for which Messrs. R.
Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America.
Our mineral interests are leased and operated by Range Resources Corporation/Memorial Resource Development Corp. Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America.
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.
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.
The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated yearly decline rate of 14.1% during the initial five-years.
The properties underlying our mineral and royalty interests typically have low estimated decline rates.
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.
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.
In January 2024, the EPA published a proposed rule to assess methane “waste emissions charges” from the oil and gas sector. The public comment period for the proposed rule is expected to close in March 2024.
In January 2024, the EPA published a proposed rule to assess methane “waste emissions charges” from the oil and gas sector. The final rule became effective in May 2024, and in July 2024, the D.C. Circuit denied a request to delay EPA’s implementation of the 2024 rule.
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.
Mineral Interests The following table sets forth information about our mineral and nonparticipating royalty interests.
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. 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.
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.
Removed
The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 common units of the Operating Company (“OpCo common units”) and an equal number of Class B common units representing limited partner interests in the Partnership (“Class B units”) and (b) 557,302 common units.
Added
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.
Removed
We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

92 edited+24 added−11 removed327 unchanged
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.
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.
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.
Any acquisition involves potential risks, including, among other things: ● the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and production costs; ● a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions; ● a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; ● the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate; ● mistaken assumptions about the overall cost of equity or debt; ● our inability to obtain satisfactory title to the assets we acquire; ● an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and ● the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
Any acquisition involves potential risks, including, among other things: ● the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and production costs; ● a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions; ● a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; ● the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate; ● mistaken assumptions about the overall cost of equity or debt; ● our inability to obtain satisfactory title to the assets we acquire; ● our inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and ● the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.
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; 36 Table of Contents ● 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; ● 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. 37 Table of Contents Our partnership agreement does not restrict our Sponsors and their respective affiliates or the Contributing Parties from competing with 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 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.
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.
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.
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.” 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; ● 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.
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. 39 Table of Contents In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the conflicts committee must be made in good faith.
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.
Our historical estimates of proved reserves and related valuations as of December 31, 2023, 2022 and 2021 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, 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.
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.
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.
The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable 57 Table of Contents flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases.
The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases.
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.
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 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
Our General Partner may not be removed unless such removal is both (i) for cause and 40 Table of Contents (ii) approved by the vote of the holders of not less than 66 2 / 3 % of all outstanding units (including common units and Class B units held by the General Partner and its affiliates).
Our General Partner may not be removed unless such removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 66 2 / 3 % of all outstanding units (including common units and Class B units held by the General Partner and its affiliates).
This effectively permits a “change of control” without the vote or consent of the unitholders. 41 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.
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.
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.
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.
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.
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.
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.
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.
These and other potential regulations could increase the operating costs of the 61 Table of Contents operators and delay production from our properties, which could reduce the amount of cash available for distribution to our common unitholders. The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations.
These and other potential regulations could increase the operating costs of the operators and delay production from our properties, which could reduce the amount of cash available for distribution to our common unitholders. The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations.
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 38 Table of Contents our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us.
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.
Recently, President Biden has 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, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.
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, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.
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.
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.
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.
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.
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.
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.
In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets. 60 Table of Contents 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. 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, 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, 49 Table of Contents 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 59 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.
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.
Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that 52 Table of Contents successful exploration or development activities are conducted on our properties, or we acquire properties containing proved reserves, or both.
Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties, or we acquire properties containing proved reserves, or both.
The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base 50 Table of Contents requires the consent of the lenders holding 100% of the commitments.
The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments.
Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for 53 Table of Contents 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. 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.
Further, 56 Table of Contents the potential drilling locations identified by the operators of our properties are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation.
Further, the potential drilling locations identified by the operators of our properties are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation.
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.
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.
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.
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.
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 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.
As a result, we may pay cash distributions during periods in which we 34 Table of Contents record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.
As a result, we may pay cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.
The holders of our Series A preferred units (to the extent of a distribution equal to 6.0% per annum plus accrued and unpaid distributions) and Class B units (to the extent of a distribution equal to 2.0% per quarter on such holder’s Class B Contribution (as defined below)) are entitled to receive quarterly cash distributions prior to distributions to holders of our common units.
The holders of our Series A preferred units (to the extent of a distribution equal to 6.0% per annum plus accrued and unpaid distributions) and Class B units representing limited partnership interests in the Partnership (“Class B Units”) (to the extent of a distribution equal to 2.0% per quarter on such holder’s Class B Contribution (as defined below)) are entitled to receive quarterly cash distributions prior to distributions to holders of our common units.
For example, during the past five years, the posted price for WTI, has ranged 46 Table of Contents 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 $1.33 per MMBtu in September 2020 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 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.
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.
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.
During 63 Table of Contents COP26, multiple efforts (not having the effect of law) were announced, including a call for countries to eliminate certain fossil fuel subsidies and pursue further action to reduce non-carbon dioxide GHG emissions.
During more recent COP meetings, including COP26, multiple efforts (not having the effect of law) were announced, including a call for countries to eliminate certain fossil fuel subsidies and pursue further action to reduce non-carbon dioxide GHG emissions.
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.
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, 2023, we had approximately $294.2 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, 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.
General Risk Factors ​ Increased costs of capital could materially adversely affect our business. Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates.
Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates.
As of February 16, 2024, the owners of our Sponsors own or control up to an aggregate of approximately 8.4% of our outstanding common units and Class B units (or approximately 6.8% 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 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.
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.
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.
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 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 addition, we entered into a transition services agreement in connection with the LongPoint Acquisition, and we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire.
In addition, we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire.
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 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.
Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. 43 Table of Contents The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.
Although a portion of the mineral and royalty interests acquired in connection with the dropdown were subject to the right of first offer provided by the Contributing Parties, that right of first refusal is now expired, and there can be no assurance that, should the Contributing Parties choose to sell any additional mineral and royalty interests, any offer will be made to us, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities.
There can be no assurance that, should the Contributing Parties choose to sell any additional mineral and royalty interests, any offer will be made to us, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities.
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. 62 Table of Contents Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing.
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.
In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply.
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.
By acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.
By acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. These provisions may have the effect of discouraging lawsuits against us and our General Partner’s officers and directors.
We recorded an impairment on our oil and natural gas properties of $18.2 million for the year ended December 31, 2023 as a result of the decline in oil and natural gas prices.
We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million for the years ended December 31, 2024 and 2023, respectively, as a result of the decline in oil and natural gas prices. The Partnership did not record an impairment on its oil and natural gas properties for the year ended December 31, 2022.
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. 48 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.
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.
A material decrease in the sale of oil and natural gas properties by any of our Sponsors and the Contributing Parties or by third parties would limit our opportunities for future acquisitions and could materially adversely affect our business, results of operations, financial condition and ability to pay quarterly cash distributions to our unitholders. 54 Table of Contents Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
A material decrease in the sale of oil and natural gas properties by any of our Sponsors and the Contributing Parties or by third parties would limit our opportunities for future acquisitions and could materially adversely affect our business, results of operations, financial condition and ability to pay quarterly cash distributions to our unitholders.
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.
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.
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. 45 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.
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.
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. 49 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.
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.
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.
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.
We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units. 55 Table of Contents We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.
We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.
Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.
Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us. Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.
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.
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.
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 64 Table of Contents damaged, they may experience a significant disruption in their operations.
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.
These provisions may have the effect of discouraging lawsuits against us and our General Partner’s officers and directors. 44 Table of Contents If a unitholder is an ineligible holder, the units of such unitholder may be subject to redemption. We have adopted certain requirements regarding those investors who may own our units.
If a unitholder is an ineligible holder, the units of such unitholder may be subject to redemption. We have adopted certain requirements regarding those investors who may own our units.
We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution on common units.
We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution on common units.
To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. 35 Table of Contents The limited liability company agreement of our General Partner contains restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.
To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.
A large percentage of our equity securities, including securities that are convertible or exchangeable into common units, are held by a relatively limited number of investors.
In addition, our Series A preferred units may be converted into common units at the then-applicable conversion rate. A large percentage of our equity securities, including securities that are convertible or exchangeable into common units, are held by a relatively limited number of investors.
The Board of Directors is made up of eight 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.
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.
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.
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.
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.
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.
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 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.
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.
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.
On December 29, 2023, the WTI posted price for crude oil was $71.89 per Bbl and the Henry Hub spot market price of natural gas was $2.58 per MMBtu. On February 5, 2024, the WTI posted price for crude oil was $73.21 per Bbl and the Henry Hub spot market price of natural gas was $2.12 per MMBtu.
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.
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.
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.
As of December 31, 2023, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 14.1%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected.
However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us. Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations and cash available for distribution on common units.
Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations 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 changeThese risk assessments include identification of reasonably foreseeable internal and external risks, software which helps identify potential weaknesses in our systems, the likelihood and potential damage that could result from such risks, and the sufficiency of existing policies, procedures, systems, and safeguards in place to manage such risks. 65 Table of Contents We continually monitor our network and firewall for security weaknesses using third party applications and we perform external penetration testing which is performed by a third party consultant on an annual basis.
Biggest changeThese risk assessments include identification of reasonably foreseeable internal and external risks, software which helps identify potential weaknesses in our systems, the likelihood and potential damage that could result from such risks, and the sufficiency of existing policies, procedures, systems, and safeguards in place to manage such risks.
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. 66 Table of Contents
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 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.
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.
While we have experienced cybersecurity incidents, to date, we are not aware that we have experienced a material cybersecurity incident during the 2023 fiscal year.
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.
In total, we engage third parties in connection with our risk assessment processes. These service providers work closely with our team and our managed service providers to assist us to design and implement our cybersecurity policies and procedures, as well as to monitor and test our safeguards.
These service providers work closely with our team and our managed service providers to assist us to design and implement our cybersecurity policies and procedures, as well as to monitor and test our safeguards.
Added
We continually monitor our network and firewall for security weaknesses using third party applications and we perform external penetration testing which is performed by a third party consultant on an annual basis. In total, we engage third parties in connection with our risk assessment processes.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

1 edited+0 added−0 removed1 unchanged
Biggest changeMine Safety Disclosures Not applicable. ​ 67 Table of Contents Part II
Biggest changeMine Safety Disclosures Not applicable. ​ 66 Table of Contents Part II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

8 edited+2 added−4 removed28 unchanged
Biggest changeOn September 28, 2023, we issued 6,323 common units to Ranch Road Holdings, LLC in exchange for 6,323 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 (the “Exchange Agreement”), 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.
Biggest changeUnregistered 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”).
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, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. 68 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.
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, 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.
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 69 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 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.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2023.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2024.
The Board of Directors approved the allocation of approximately 25% of our cash available for distribution on common units for the fourth quarter of 2023 for the repayment of $13.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2023.
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.
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 16, 2024, we had 20,847,295 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 21, 2025, we had 14,491,540 Class B units outstanding.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective 70 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 16, 2024, we had 75,851,458 common units outstanding.
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.
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 16, 2024, there were 73,851,458 common units outstanding held by 146 holders of record and 20,847,295 Class B units outstanding held by 21 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 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.
Removed
Unregistered Sales of Equity Securities On May 17, 2023, in connection with the closing of the MB Minerals Acquisition, we and the Operating Company issued (a) 5,369,218 Opco common units and an equal number of Class B units and (b) 557,302 common units, to MB Minerals, L.P., a Delaware limited partnership, Barry K. Clark, Michael F. Dignam Jr., Thomas A.
Added
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.
Removed
Medary, Wayne A. Psencik in a private placement.
Added
On February 14, 2025, we issued 29,418 common units to Gregory Scott Rasmussen in exchange for 29,418 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.
Removed
On September 13, 2023, in connection with the closing of the LongPoint Acquisition, we completed the private placement of 325,000 Series A preferred units to certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to us of $325.0 million (the “Preferred Unit Transaction”).
Removed
We used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company (“OpCo preferred units”). The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition.

Item 6. [Reserved]

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

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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 89 Item 8. Financial Statements and Supplementary Data 92 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 92 Item 9A. Controls and Procedures 93 Item 9B.
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

Item 7. Management's Discussion & Analysis

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

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Biggest changeThe 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, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region(1) ​ Gross DUCs ​ Gross Permits ​ Net DUCs ​ Net Permits Permian Basin ​ 495 ​ 396 ​ 2.55 ​ 2.22 Mid‑Continent 139 ​ 68 ​ 0.96 ​ 0.52 Terryville/Cotton Valley/Haynesville 66 ​ 30 ​ 0.51 ​ 0.37 Appalachian Basin ​ 3 ​ 9 ​ 0.01 ​ 0.02 Bakken/Williston Basin 55 ​ 148 ​ 0.13 ​ 0.11 Eagle Ford 45 ​ 61 ​ 0.33 ​ 0.47 DJ Basin/Rockies/Niobrara 4 ​ 15 ​ 0.06 ​ 0.12 Total 807 ​ 727 ​ 4.55 ​ 3.83 (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. 72 Table of Contents The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of December 31, 2023: ​ ​ ​ ​ ​ ​ ​ Basin or Producing Region ​ Gross Locations(1) ​ Net Locations(1) ​ Average Gross Horizontal Wells/DSU(2) Permian Basin ​ 5,216 ​ 32.14 ​ 12.0 Mid‑Continent 2,440 ​ 12.64 ​ 6.8 Haynesville 1,022 ​ 12.90 ​ 5.9 Appalachia ​ 257 ​ 2.13 ​ 7.6 Bakken 1,708 ​ 3.59 ​ 8.5 Eagle Ford 1,577 ​ 14.42 ​ 6.9 Rockies 197 ​ 1.27 ​ 10.5 Total 12,417 ​ 79.09 ​ 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.
Biggest changeThe 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.
Cash flows provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR IPO (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 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 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 85 Table of Contents 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 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.
As of December 31, 2023, 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, 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, 2023, 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.
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.
These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.
These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.
These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2022.
Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. 71 Table of Contents We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
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. 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. 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.
Liquidity and Capital Resources Overview Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral 83 Table of Contents and royalty interests in oil and natural gas properties.
Liquidity and Capital Resources Overview Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties.
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 TGR and $0.9 million in cash received from the dissolution of TGR.
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 assessment includes 87 Table of Contents consideration of the following factors, among others: the operators’ intent to drill; remaining lease term; geological and geophysical evaluations; the operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned.
The assessment includes consideration of the following factors, among others: the operators’ intent to drill; remaining lease term; geological and geophysical evaluations; the operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned.
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.
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 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 ​ 2023 ​ 2022 ​ 2021 Permian Basin ​ 50 ​ 47 ​ 25 Mid‑Continent ​ 17 ​ 12 ​ 8 Terryville/Cotton Valley/Haynesville ​ 13 ​ 15 ​ 12 Appalachian Basin ​ 3 ​ 1 ​ 1 Bakken/Williston Basin ​ 6 ​ 6 ​ 6 Eagle Ford ​ 8 ​ 7 ​ 6 DJ Basin/Rockies/Niobrara ​ 1 ​ — ​ 1 Other ​ — ​ 4 ​ 2 Total ​ 98 ​ 92 ​ 61 ​ 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 ​ 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.
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 2023.
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.
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, 2023, 2022 and 2021, in each case based on the reserve report prepared by Ryder Scott.
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.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2023 for the repayment of $13.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2023.
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 following table presents the breakdown of our oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 2022 2021 Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil revenue ​ 69 % ​ 46 % ​ 50 % Natural gas revenue ​ 22 % ​ 44 % ​ 38 % NGL revenue ​ 9 % ​ 10 % ​ 12 % ​ ​ 100 % ​ 100 % ​ 100 % We have entered into oil and natural gas commodity derivative agreements, which extend through December 2025, 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, ​ ​ 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 prices used to estimate proved reserves for the respective periods were held 76 Table of Contents 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 2023 ​ 2022 ​ 2021 Oil (MBbls) 19,800 ​ 12,355 ​ 12,511 Natural gas (MMcf) 204,542 ​ 160,298 ​ 157,764 Natural gas liquids (MBbls) 11,519 ​ 7,388 ​ 6,669 Total (MBoe)(6:1) 65,409 ​ 46,459 ​ 45,474 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Unweighted Arithmetic Average First ‑ Day ‑ of ‑ the ‑ Month Prices 2023 ​ 2022 ​ 2021 Oil (Bbls) ​ $ 78.22 ​ $ 93.67 ​ $ 66.56 Natural gas (Mcf) ​ $ 2.64 ​ $ 6.36 ​ $ 3.60 ​ 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 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 increase in depreciation and depletion expense was due to the Cornerstone Acquisition and the Hatch Acquisition, which significantly increased our net capitalized oil and natural gas properties.
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.
On June 13, 2023, we entered into the A&R Credit Agreement (as defined below).
On June 13, 2023, we entered into the A&R Credit Agreement (as 80 Table of Contents defined below).
Income Tax Expense For the year ended December 31, 2023, we recognized an income tax expense of $3.8 million, resulting in an effective tax rate of 4.34%, compared to income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%.
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%.
See “Recent Developments—Fourth Quarter Distributions” above for discussion of our fourth quarter 2023 distributions. 84 Table of Contents Cash Flows The following table presents our cash flows for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 2022 ​ 2021 Cash Flow Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 174,267,667 ​ $ 166,636,493 ​ $ 91,442,481 Net cash used in investing activities ​ (246,676,974) ​ (374,723,901) ​ (55,572,551) Net cash provided by (used in) financing activities ​ 78,375,409 ​ 226,061,562 ​ (38,622,493) Net increase (decrease) in cash and cash equivalents ​ $ 5,966,102 ​ $ 17,974,154 ​ $ (2,752,563) 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.
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.
The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time.
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.
Interest Expense Interest expense for the year ended December 31, 2023 was $26.0 million as compared to interest expense of $13.8 million for the year ended December 31, 2022.
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.
As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. 75 Table of Contents The Baker Hughes United States Rotary Rig count decreased 21% to 602 active land rigs at December 31, 2023 compared to 762 active land rigs at December 31, 2022.
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.
The significant increase in oil, natural gas and NGL revenues was primarily related to the increase in the average prices we received for oil, natural gas and NGL production, and to a lesser extent, an increase in production volumes for the year ended December 31, 2022 as discussed below. 80 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 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 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, 2022, depreciation and depletion expense increased by $13.3 million from $36.8 million for the year ended December 31, 2021.
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.
As noted above, the supply and demand imbalance resulting from various OPEC announcements, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices.
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.
The overall decrease in rig count 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 762 active rig count at December 31, 2022 increased significantly compared to 570 active land rigs at December 31, 2021.
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.
Gain (Loss) on Commodity Derivative Instruments 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 compared to $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2022.
(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.
The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. 82 Table of Contents Marketing and other deductions for the year ended December 31, 2022 increased by $1.4 million from $12.0 million for the year ended December 31, 2021.
The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.
Cash flows provided by operating activities for the year ended December 31, 2023 were $174.3 million, an increase of $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, 2022 increased by $75.2 million compared to $91.4 million for the year ended December 31, 2021.
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.
The impairment is primarily attributed to the decline in the 12-month average price of oil and natural. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas.
As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas.
The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas.
As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas.
A significant portion of our mineral and royalty interests are located in Texas basins and producing regions. 79 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, ​ ​ 2023 ​ 2022 ​ 2021 Operating Results: ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL revenues ​ $ 267,584,785 ​ $ 281,964,126 ​ $ 175,088,021 Lease bonus and other income ​ ​ 5,594,855 ​ ​ 3,073,609 ​ ​ 3,319,104 Gain (loss) on commodity derivative instruments, net ​ ​ 20,888,972 ​ ​ (36,978,550) ​ ​ (42,791,909) Total revenues ​ ​ 294,068,612 ​ ​ 248,059,185 ​ ​ 135,615,216 Costs and expenses ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ 20,326,477 ​ 16,238,814 ​ 10,480,481 Depreciation and depletion expense ​ 96,477,003 ​ 50,086,414 ​ 36,797,881 Impairment of oil and natural gas properties ​ 18,220,173 ​ — ​ — Marketing and other deductions ​ 12,564,619 ​ 13,383,074 ​ 12,048,643 General and administrative expense ​ 35,677,851 ​ 29,128,659 ​ 26,977,519 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative expense ​ ​ 927,699 ​ 2,304,445 ​ ​ — Total costs and expenses ​ 184,193,822 ​ 111,141,406 ​ 86,304,524 Operating income ​ 109,874,790 ​ 136,917,779 ​ 49,310,692 Other income (expense) ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity income in affiliate ​ ​ — ​ ​ 2,668,844 ​ ​ 1,119,819 Interest expense ​ (25,950,600) ​ (13,818,310) ​ (9,182,103) Loss on extinguishment of debt ​ (480,244) ​ — ​ ​ ​ Other (expense) income ​ (180,765) ​ 4,043,530 ​ ​ 1,263,566 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ 3,508,691 ​ 3,721,145 ​ ​ — Net income before income taxes ​ ​ 86,771,872 ​ ​ 133,532,988 ​ ​ 42,511,974 Income tax expense ​ ​ 3,766,302 ​ ​ 2,738,702 ​ ​ 74,100 Net income ​ ​ 83,005,570 ​ ​ 130,794,286 ​ ​ 42,437,874 Distribution and accretion on Series A preferred units ​ ​ (6,310,215) ​ ​ — ​ ​ (11,249,969) Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests ​ ​ (16,464,890) ​ ​ (18,822,552) ​ ​ (8,496,104) Distribution on Class B units ​ ​ (88,786) ​ ​ (42,243) ​ ​ (76,780) Net income attributable to common units of Kimbell Royalty Partners, LP ​ $ 60,141,679 ​ $ 111,929,491 ​ $ 22,615,021 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (Bbls) ​ 2,392,622 ​ 1,425,842 ​ 1,343,771 Natural gas (Mcf) ​ 23,384,021 ​ 20,310,991 ​ 19,085,400 Natural gas liquids (Bbls) ​ 1,082,663 ​ 746,865 ​ 714,494 Combined volumes (Boe) (6:1) ​ 7,372,622 ​ 5,557,872 ​ 5,239,165 ​ Comparison of the Year Ended December 31, 2023 to the Year Ended December 31, 2022 and the Year Ended December 31, 2022 to the Year Ended December 31, 2021 Oil, Natural Gas and NGL Revenues For the year ended December 31, 2023, our oil, natural gas and NGL revenues were $267.6 million, a decrease of $14.4 million from $282.0 million for the year ended December 31, 2022.
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.
Financing Activities Cash flows provided by financing activities were $78.4 million for the year ended December 31, 2023 compared to $226.1 million of cash flows provided by financing activities for the year ended December 31, 2022.
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.
The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings from 5.28% at December 31, 2022 to 8.62% at December 31, 2023.
Interest expense for the year ended December 31, 2023 increased by $12.2 million compared to interest expense of $13.8 million for the year ended December 31, 2022. The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings from 5.28% at December 31, 2022 to 8.62% at December 31, 2023.
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. This gain was offset by the losses on the settlement of commodity derivative instruments.
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.
Our average depletion rate per barrel was $13.03 for the year ended December 31, 2023, an increase of $4.19 per barrel from the $8.84 average depletion rate per barrel for the year ended December 31, 2022.
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.
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.
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.
General and administrative expenses for the year ended December 31, 2022 increased by $2.1 million from $27.0 million for the year ended December 31, 2021.
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 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 for the volumes sold during the year ended December 31, 2023 and $91.74 per Bbl of oil, $6.04 per Mcf of natural gas and $38.19 per Bbl of NGL for the volumes sold during the year ended December 31, 2022.
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.
Investing Activities Cash flows used in investing activities for the year ended December 31, 2023 were $246.7 million compared to $374.7 million for the year ended December 31, 2022.
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.
This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 39.3% or $26.76 per Bbl of oil and 65.8% or $2.56 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 1.2% or $0.95 per Bbl of oil and 13.4% or $0.34 per Mcf of natural gas for the comparable periods.
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, 2023 were $12.6 million, a decrease of $0.8 million from $13.4 million for the year ended December 31, 2022.
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.
Cash flows used in financing activities for the year ended December 31, 2021 consists of $71.7 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $67.1 million to fund the redemption of Series A preferred units, $91.0 million used to repay borrowings under our secured revolving credit facility, $2.1 million of restricted units repurchased for tax withholding, $0.7 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $57.5 million in proceeds from the 2021 equity offering and $136.6 million of additional borrowings under our secured revolving credit facility.
Cash flows used in financing activities for the year ended December 31, 2024 consists primarily of $187.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $60.0 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and $0.3 million paid in connection with the redemption of Class B units, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.
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 recorded an impairment on our oil and natural gas properties of $18.2 million during 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.
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.
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 production volumes were 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023, an increase of 1,814,750 Boe or 5,240 Boe/d, from 5,557,872 Boe or 15,025 Boe/d, for the year ended December 31, 2022.
Our production volumes for the year ended December 31, 2023 increased by 1,814,750 Boe or 5,240 Boe/d, from 5,557,872 Boe or 15,025, for the year ended December 31, 2022.
If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and NGL reserves.
If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
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. As of December 31, 2023, 2022 and 2021, we recorded a full valuation allowance on our deferred tax assets.
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.
The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data.
The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data.
Lease Bonus and Other Income For the year ended December 31, 2023 lease bonus and other income was $5.6 million, an increase of $2.5 million compared to $3.1 million for the year ended December 31, 2022. The increase in lease bonus and other income is primarily related to legal settlements received during the year ended December 31, 2023.
The increase in lease bonus and other income is primarily related to legal settlements received during the year ended December 31, 2023.
We assess all items classified as unevaluated property on a periodic basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant.
We assess properties on an individual basis or as a group if properties are individually insignificant.
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, 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.
The volumes produced and asset costs are known, while proved reserves are based on estimates that are subject to some variability. Unevaluated Properties Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves, which is primarily based upon when such properties become producing.
Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves, which is primarily based upon when such properties become producing. We assess all items classified as unevaluated property on a periodic basis for possible impairment.
The increase in production for the year ended December 31, 2022 was primarily attributable to production associated with the Cornerstone Acquisition, which included a full year of production for the year ended December 31, 2022, compared to approximately three months of production for the year ended December 31, 2021, and to a lesser extent, production associated with the Hatch Acquisition.
The increase in production for the year ended December 31, 2024 was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of production for the year ended December 31, 2024, compared to a partial year of production 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.
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 $282.0 million for the year ended December 31, 2022.
Material acquisitions that would impact the comparability of our results for the years ended December 31, 2023, 2022 and 2021 include the MB Minerals Acquisition, the Longpoint Acquisition, the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”) and the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) .
Material acquisitions that would impact the comparability of our results for the years ended December 31, 2024, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”), the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) and the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”).
Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized.
Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate 74 Table of Contents results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.
The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ Year Ended December 31, 2022 ​ Year Ended December 31, 2021 ​ ​ High Low ​ High Low ​ High Low Oil ($/Bbl) ​ $ 93.67 ​ $ 66.61 ​ $ 123.64 ​ $ 71.05 ​ $ 85.64 ​ $ 47.47 Natural gas ($/MMBtu) ​ $ 3.78 ​ $ 1.74 ​ $ 9.85 ​ $ 3.46 ​ $ 23.86 ​ $ 2.43 ​ On February 5, 2024, the WTI posted price for crude oil was $73.21 per Bbl and the Henry Hub spot market price of natural gas was $2.12 per MMBtu.
The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2024 ​ Year Ended December 31, 2023 ​ Year Ended December 31, 2022 ​ ​ High Low ​ High Low ​ High Low Oil ($/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.
The reduced tax basis will increase unitholders’ capital gain (or 86 Table of Contents decrease unitholders’ capital loss) when unitholders sell their common units.
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.
Generally, the terms of the lease governing the development of our properties permit the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues. 78 Table of Contents 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 services.
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. 77 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.
Impairment of Oil and Natural Gas Properties Accounting standards require that we periodically review the carrying value of our properties for possible impairment.
Loss on commodity derivative instruments for the year ended December 31, 2021 included $22.1 million of mark-to-market losses and $20.7 million of losses on the settlement of commodity derivative instruments. 81 Table of Contents Production and Ad Valorem Taxes Production and ad valorem taxes for the year ended December 31, 2023 were $20.3 million, an increase of $4.1 million from $16.2 million for the year ended December 31, 2022.
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.
See the Note 2—Summary of Significant Accounting Policies to our financial statements for a summary of our significant accounting policies. Method of Accounting for Oil and Natural Gas Properties We account for oil, natural gas and NGL producing activities using the full cost method of accounting.
See Note 2—Summary of Significant Accounting Policies to our financial statements for a summary of our significant accounting policies.
The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.
For the year ended December 31, 2023, production and ad valorem taxes increased by $4.1 million from $16.2 million for the year ended December 31, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.
Depreciation and Depletion Expense Depreciation and depletion expense for the year ended December 31, 2023 was $96.5 million, an increase of $46.4 million from $50.1 million for the year ended December 31, 2022.
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.
The increase in marketing and other deductions was primarily attributable the increase in prices for oil, natural gas and NGL production. General and Administrative Expense General and administrative expenses for the year ended December 31, 2023 were $35.7 million, an increase of $6.6 million from $29.1 million for the year ended December 31, 2022.
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.
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. 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.
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.
The increase in our average depletion rate per barrel was due to the Cornerstone Acquisition and the Hatch Acquisition, which collectively increased our net capitalized oil and natural gas properties. Impairment of Oil and Natural Gas Properties ​ We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023.
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.
(2) Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of December 31, 2023. DSUs vary in size. Recent Developments Acquisitions On May 17, 2023, we completed the MB Minerals Acquisition.
(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”).
We intend to pay the distributions on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024. As to us, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by us in the fourth quarter of 2023.
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.
Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us. We will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2023.
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.
Our lease bonus and other income remained relatively flat at $3.3 million for the year ended December 31, 2021, compared to December 31, 2022.
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.
The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. On September 13, 2023, we completed the LongPoint Acquisition in a cash transaction valued at approximately $455.0 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the Preferred Unit Transaction.
We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas .
We intend to pay the distribution subsequent to March 13, 2024 and prior to the distribution on the common units and OpCo common units. Business Environment Global Conflicts In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country.
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.
Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units.
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.
For the year ended December 31, 2022, our average depletion rate per barrel increased by $2.06 per barrel from the $6.78 average depletion rate per barrel for the year ended December 31, 2021.
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.

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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. 90 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, ​ ​ 2023 ​ 2022 ​ 2021 Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income ​ $ 83,005,570 ​ $ 130,794,286 ​ $ 42,437,874 Depreciation and depletion expense ​ ​ 96,477,003 ​ ​ 50,086,414 ​ ​ 36,797,881 Interest expense ​ ​ 25,950,600 ​ ​ 13,818,310 ​ ​ 9,182,103 Cash distribution from affiliate ​ ​ — ​ ​ 385,326 ​ ​ 1,015,559 Income tax expense ​ ​ 3,766,302 ​ ​ 2,738,702 ​ ​ 74,100 EBITDA ​ ​ 209,199,475 ​ ​ 197,823,038 ​ ​ 89,507,517 Impairment of oil and natural gas properties ​ ​ 18,220,173 ​ ​ — ​ ​ — Unit-based compensation ​ ​ 13,111,522 ​ ​ 11,107,639 ​ ​ 10,632,725 Loss on extinguishment of debt ​ ​ 480,244 ​ ​ — ​ ​ — (Gain) loss on derivative instruments, net of settlements ​ ​ (26,371,058) ​ ​ (14,300,570) ​ ​ 20,343,783 Cash distribution from affiliate ​ ​ — ​ ​ 645,451 ​ ​ 500,389 Equity income in affiliate ​ ​ — ​ ​ (2,668,844) ​ ​ (1,119,819) 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 ​ ​ 212,059,364 ​ ​ 191,190,014 ​ ​ 119,864,595 Adjusted EBITDA attributable to non-controlling interest ​ ​ (46,475,531) ​ ​ (27,154,867) ​ ​ (35,608,960) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 165,583,833 ​ ​ 164,035,147 ​ ​ 84,255,635 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 18,520,334 ​ ​ 9,583,004 ​ ​ 5,297,810 Cash distributions on Series A preferred units ​ ​ 4,551,746 ​ ​ — ​ ​ 1,943,385 Restricted units repurchased for tax withholding ​ ​ — ​ ​ — ​ ​ 1,433,265 Cash income tax expense ​ ​ 1,641,675 ​ ​ 3,082,245 ​ ​ — Distributions on Class B units ​ ​ 88,786 ​ ​ 42,243 ​ ​ 76,780 Cash available for distribution on common units ​ $ 140,781,292 ​ $ 151,327,655 ​ $ 75,504,395 ​ 91 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2023 ​ 2022 ​ 2021 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 ​ $ 174,267,667 ​ $ 166,636,493 ​ $ 91,442,481 Interest expense ​ 25,950,600 ​ 13,818,310 ​ 9,182,103 Income tax expense ​ ​ 3,766,302 ​ ​ 2,738,702 ​ ​ 74,100 Impairment of oil and natural gas properties ​ (18,220,173) ​ — ​ — Amortization of right-of-use assets ​ ​ (336,080) ​ (319,674) ​ ​ (298,093) Amortization of loan origination costs ​ (1,943,025) ​ (1,872,700) ​ (1,556,769) Loss on extinguishment of debt ​ ​ (480,244) ​ ​ — ​ ​ — Equity income in affiliate, net ​ — ​ (716,481) ​ 1,119,819 Forfeiture of restricted units ​ ​ — ​ ​ 19,813 ​ ​ — Unit-based compensation ​ (13,111,522) ​ (11,107,639) ​ (10,632,725) Gain (loss) on derivative instruments, net of settlements ​ 26,371,058 ​ 14,300,570 ​ (20,343,783) Changes in operating assets and liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL receivables ​ 12,026,760 ​ 11,846,567 ​ 17,594,389 Accounts receivable and other current assets ​ (1,863,376) ​ 511,319 ​ 2,077,637 Accounts payable ​ (509,400) ​ (399,318) ​ 77,716 Other current liabilities ​ (1,263,804) ​ (1,590,016) ​ 463,828 Operating lease liabilities ​ ​ 348,668 ​ 324,913 ​ ​ 306,814 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 ​ ​ 209,199,475 ​ ​ 197,823,038 ​ ​ 89,507,517 Add: ​ ​ ​ ​ ​ ​ ​ ​ ​ Impairment of oil and natural gas properties ​ 18,220,173 ​ — ​ — Unit-based compensation ​ 13,111,522 ​ 11,107,639 ​ 10,632,725 Loss on extinguishment of debt ​ 480,244 ​ — ​ — (Gain) loss on derivative instruments, net of settlements ​ (26,371,058) ​ (14,300,570) ​ 20,343,783 Cash distribution from affiliate ​ ​ — ​ ​ 645,451 ​ ​ 500,389 Equity income in affiliate ​ ​ — ​ ​ (2,668,844) ​ ​ (1,119,819) 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 ​ ​ 212,059,364 ​ ​ 191,190,014 ​ ​ 119,864,595 Adjusted EBITDA attributable to non-controlling interest ​ ​ (46,475,531) ​ ​ (27,154,867) ​ ​ (35,608,960) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 165,583,833 ​ ​ 164,035,147 ​ ​ 84,255,635 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 18,520,334 ​ ​ 9,583,004 ​ ​ 5,297,810 Cash distributions on Series A preferred units ​ ​ 4,551,746 ​ ​ — ​ ​ 1,943,385 Restricted units repurchased for tax withholding ​ ​ — ​ ​ — ​ ​ 1,433,265 Cash income tax expense ​ ​ 1,641,675 ​ ​ 3,082,245 ​ ​ — Distributions on Class B units ​ ​ 88,786 ​ ​ 42,243 ​ ​ 76,780 Cash available for distribution on common units ​ $ 140,781,292 ​ $ 151,327,655 ​ $ 75,504,395 ​ ​
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 ​ ​
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 $2.9 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 $2.4 million annually, assuming that our indebtedness remained constant throughout the year.
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, 2023, we had five 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, 2024, we had six 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 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 85 Table of Contents nearby month futures contract of the contract period.
During the years ended December 31, 2023, 2022 and 2021, our top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, 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, 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.
Interest Rate Risk We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2023, we had total borrowings outstanding under our secured revolving credit facility of $294.2 million.
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.
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. On May 17, 2022 we entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap.
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.
On August 8, 2022, we entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. 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.
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.
Inflation Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 2021 through December 31, 2023. 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.
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.
We used an interest rate swap for the management of interest rate 89 Table of Contents risk exposure, as the interest rate swap effectively converted a portion of our secured revolving credit facility from a floating to a fixed rate.
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.

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