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What changed in Kimbell Royalty Partners, LP's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Kimbell Royalty Partners, LP's 2022 and 2023 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 2023 report.

+398 added−409 removedSource: 10-K (2024-02-21) vs 10-K (2023-02-23)

Top changes in Kimbell Royalty Partners, LP's 2023 10-K

398 paragraphs added · 409 removed · 308 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

94 edited+22 added−26 removed157 unchanged
Biggest changeOil, 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, ​ ​ 2022 ​ 2021 ​ 2020 Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (Bbls) ​ ​ 1,425,842 ​ ​ 1,343,771 ​ ​ 1,409,163 Natural gas (Mcf) ​ ​ 20,310,991 ​ ​ 19,085,400 ​ ​ 17,891,384 Natural gas liquids (Bbls) ​ ​ 746,865 ​ ​ 714,494 ​ ​ 681,575 Total (Boe)(6:1) (1) ​ ​ 5,557,872 ​ ​ 5,239,165 ​ ​ 5,072,635 Average daily production (Boe/d)(6:1) ​ ​ 15,025 ​ ​ 14,354 ​ ​ 13,860 Average Realized Prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and condensate (per Bbl) ​ $ 91.74 ​ $ 64.86 ​ $ 36.98 Natural gas (per Mcf) ​ $ 6.04 ​ $ 3.51 ​ $ 1.79 Natural gas liquids (per Bbl) ​ $ 38.19 ​ $ 29.33 ​ $ 12.39 Average Unit Cost per Boe (6:1) ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ $ 2.92 ​ $ 2.00 ​ $ 1.26 (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.
Biggest changeRisk 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.
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.
The compensation for all our employees is indirectly paid by us pursuant to the management services agreement with Kimbell Operating. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements” for more information regarding such management services agreements. Our success depends on our ability to continue to attract, retain and motivate qualified employees.
The compensation for all of our employees is indirectly paid by us pursuant to the management services agreement with Kimbell Operating. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements” for more information regarding such management services agreements. Our success depends on our ability to continue to attract, retain and motivate qualified employees.
We intend to accomplish this objective by executing the following strategies: ● Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors, the Contributing Parties and TGR to grow our business.
We intend to accomplish this objective by executing the following strategies: ● Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors and the Contributing Parties to grow our business.
Summary of Estimated Proved Reserves Estimates of reserves as of December 31, 2022, 2021 and 2020 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, 2022, 2021 and 2020, 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, 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.
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, 2022, 2021 and 2020 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, 2023, 2022 and 2021 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, 2022, 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, 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.
Numerous federal, state and local governmental agencies, such as the Environmental Protection Agency (“EPA”) and Department of the Interior (“DOI”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance.
Numerous federal, state and local governmental agencies, such as the Environmental Protection Agency (“EPA”) and Department of the Interior (“DOI”), issue regulations that often require specific and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance.
The members of our management team and Board of Directors have an average of over 30 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 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 state, and some counties and municipalities, in which we operate also regulate one or more of the following: ● the location of wells; ● the method of drilling and casing wells; 31 Table of Contents ● the timing of construction or drilling activities, including seasonal wildlife closures; ● the rates of production or “allowables”; ● the surface use and restoration of properties upon which wells are drilled; ● the plugging and abandoning of wells; and ● notice to, and consultation with, surface owners and other third parties.
The state, and some counties and municipalities, in which we operate also regulate one or more of the following: ● the location of wells; ● the method of drilling and casing wells; ● the timing of construction or drilling activities, including seasonal wildlife closures; ● the rates of production or “allowables”; ● the surface use and restoration of properties upon which wells are drilled; ● the plugging and abandoning of wells; and ● notice to, and consultation with, surface owners and other third parties.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
To 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.
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 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 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.
We believe that we will continue to benefit from these cost-free additions to production and reserves for the foreseeable future as a result of technological advances and continuing interest by third-party producers in development activities on our acreage. ● Exposure to many of the leading resource plays in the United States.
We 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.
The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs.
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.
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 27 Table of Contents 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 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 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016.
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.
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 17, 2023: (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 16, 2024: (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. 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. 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.
Under our secured revolving credit facility, we have granted the lenders a lien on substantially all of the mineral and royalty interests of our wholly owned subsidiaries. 33 Table of Contents Human Capital Resources The officers of our General Partner manage our operations and activities. However, neither we, our General Partner nor our subsidiaries have employees.
Under our secured revolving credit facility, we have granted the lenders a lien on substantially all of the mineral and royalty interests of our wholly owned subsidiaries. Human Capital Resources The officers of our General Partner manage our operations and activities. However, neither we, our General Partner nor our subsidiaries have employees.
It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin in between. The Permian Basin 18 Table of Contents consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years.
It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west and the Central Basin in between. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs and has been actively drilled over the past 90 years.
A copy of Ryder Scott’s estimated proved reserve report as of December 31, 2022 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 33 years of reservoir and operations experience. Mr. R.
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.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 124,000 gross wells, including over 48,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays.
Additionally, many of our 25 Table of Contents competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties.
Additionally, many of our competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties.
These developments could result in additional regulation and restrictions on the 30 Table of Contents use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.
These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the operators of our properties and on their waste disposal activities.
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.
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.
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.
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.
Following a standard comment period, the EPA and Army Corp of Engineers announced a final rule establishing a revised and “durable” WOTUS definition on December 30, 2022, which restored many of the elements of the 2015 rule. Multiple legal challenges to the 2022 final rule are currently pending.
Following a standard comment period, the EPA and Army Corp of Engineers announced a final rule establishing a revised and “durable” WOTUS definition on December 30, 2022, which restored many of the elements of the 2015 rule. Multiple legal challenges to the 2022 final rule followed.
During the year ended December 31, 2022, the Board of Directors approved the repayment of $46.6 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units.
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.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 124,000 gross wells, including over 48,000 wells in the Permian Basin. ● Financial flexibility to fund expansion.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin. ● Financial flexibility to fund expansion.
As of December 31, 2022, 54% and 52% 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, 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.
Of the $46.6 million, $13.1 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2023. 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 $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.
Item 1. Business 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. Effective as of September 24, 2018, the Partnership elected to be taxed as a corporation for United States federal income tax purposes.
Item 1. Business 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. We have elected to be taxed as a corporation for United States federal income tax purposes.
Business Strategies Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We will also seek to utilize TGR to further our primary business objective.
Business Strategies Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes.
From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including wastes generated during the exploration and production of crude oil and natural gas.
As of December 31, 2022, we owned mineral and royalty interests in approximately 11.5 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% of our aggregate acres located in the Permian Basin and Mid-Continent, and as of December 31, 2022, 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, 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.
If the final rule announced in December 2022 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 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.
More stringent laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
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.
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, 2022, Kimbell Operating had approximately 27 employees performing services for our operations and activities. Women represent approximately 33% of our workforce, and men represent approximately 67%.
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%.
(3) Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP and certain affiliates of Hatch Royalty LLC .
(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.
The unweighted arithmetic average first day of the month prices were $93.67, $66.56 and $39.57 per Bbl for oil and $6.36, $3.60 and $1.99 per MMBtu for natural gas at December 31, 2022, 2021 and 2020, 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 $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.
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, 2022 ​ ​ Gross ​ Net Percent Basin or Producing Region ​ Acres ​ Acres ​ Leased Permian Basin (1) ​ 2,820,453 ​ 20,488 ​ 99.1 % Mid‑Continent 3,174,297 ​ 26,495 99.7 % 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) 11,548,123 95,030 99.1 % (1) Includes mineral interests in approximately 1,375,238 gross (8,872 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, 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.
(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, 2022 ​ ​ Gross ​ Net ​ Percent Basin or Producing Region ​ Acres ​ Acres ​ Producing Permian Basin (1) ​ 309,938 ​ 3,960 ​ 100.0 % Mid‑Continent 2,195,061 ​ 17,815 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) 4,692,824 55,447 99.6 % (1) Includes overriding royalty interests in approximately 199,721 gross (2,004 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. 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.
Overview of Our Oil and Gas Assets and Operations As of December 31, 2022, we owned mineral and royalty interests in approximately 11.5 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% 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, 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.
The following table presents our estimated proved developed oil and natural gas reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2022 ​ ​ 2021 ​ ​ 2020 ​ Estimated proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (MBbls) ​ 12,355 ​ 12,511 ​ 12,294 ​ Natural gas (MMcf) ​ 160,298 ​ 157,764 ​ 144,233 ​ Natural gas liquids (MBbls) ​ 7,388 ​ 6,669 ​ 6,085 ​ Total (MBoe)(6:1) (1) ​ 46,459 ​ 45,474 ​ 42,418 ​ (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, ​ ​ ​ 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.
Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Item 1A.
Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Item 1A.
Fortson, R. Ravnaas, Taylor and Wynne. (2) Includes 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.
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.
Environmental Matters Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety.
The regulatory burden on the oil and natural gas industry increases the cost of doing business. Environmental Matters Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety.
Ravnaas of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes; and ● verification of property ownership by our land department. 22 Table of Contents Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce. 32 Table of Contents Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness” for further information. We believe that we will be able to expand our asset base through acquisitions utilizing our secured revolving credit facility, internally generated cash from operations and access to capital markets. ● Experienced and proven management team with a track record of making acquisitions.
We believe that we will be able to expand our asset base through acquisitions utilizing our secured revolving credit facility, internally generated cash from operations and access to capital markets. ● Experienced and proven management team with a track record of making acquisitions.
For example, on December 15, 2022, we completed the Hatch Acquisition, further enhancing our asset base. We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties.
For example, in 2023, we completed the MB Minerals Acquisition and the LongPoint Acquisition, further enhancing our asset base. We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties.
The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 46,459 MBoe (42.5% liquids, consisting of 26.6% oil and 15.9% NGLs) based on the reserve report prepared by Ryder Scott. All of our reserves were classified as PDP reserves.
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.
As of December 31, 2022, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 46,459 MBoe (42.5% liquids, consisting of 62.6% oil and 37.4% NGLs) based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). All of our reserves were classified as PDP reserves.
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, 2022, there were 92 rigs (representing 12.1% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 61 rigs operating on our acreage as of December 31, 2021.
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.
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.
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.
Producing since 1954, the Terryville Field is one of the most prolific natural gas fields in North America. Redevelopment of the field with horizontal drilling and modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields and long reserve life with multiple stacked producing zones. ● Appalachian Basin.
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.
For the year ended December 31, 2022, our oil, natural gas and NGL revenues were generated 46% from oil sales, 44% from natural gas sales and 10% from NGL sales.
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.
If a price equivalent conversion based on the twelve-month average prices for the y ears ended December 31, 2022, 2021 and 2020 was used, the conversion factor would be approximately 14.7 Mcf per Bbl of oil, 18.5 Mcf per Bbl of oil and 19.9 Mcf per Bbl of oil, respectively. 23 Table of Contents The foregoing reserves are all located within the continental United States.
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.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.
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.
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.
As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. 28 Table of Contents 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.
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.
We believe that our conservative capital structure will permit us to maintain financial flexibility that will allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our General Partner as discussed above. Please read “Item 7.
We believe that our conservative capital structure will permit us to maintain financial flexibility that will allow us to opportunistically purchase strategic mineral and royalty interests, subject to the supermajority vote provisions of the limited liability company agreement of our General Partner and the terms of our partnership agreement, which in certain circumstances requires the affirmative vote of 66 2 / 3 % of our outstanding Series A preferred units, in each case as discussed above.
Our PDP reserves have an average estimated yearly decline rate of 12.4% during the initial five-years. 15 Table of Contents Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing.
Our 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.
Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming.
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.
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.
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 this liquidity, along with internally generated cash from operations and access to capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets. 17 Table of Contents Competitive Strengths We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective: ● Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities.
We believe that this liquidity, along with internally generated cash from operations and access to capital markets, will provide us with the financial flexibility to grow our production, reserves and cash generated from operations through strategic acquisitions of mineral and royalty interests and the continued development of our existing assets.
This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.
Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply.
As of December 31, 2022, we owned mineral or royalty interests in over 124,000 gross productive wells, which consisted of over 90,000 oil wells and over 34,000 natural gas wells. 24 Table of Contents 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, 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State Acreage ​ Acreage ​ Acreage Texas 5,053,702 ​ 60,733 ​ 5,114,435 Oklahoma 2,002,221 7,374 2,009,595 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 11,448,105 (1) 100,018 (2) 11,548,123 (1) Reflects mineral interests in approximately 11,448,105 total gross (85,571 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, 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.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects. 26 Table of Contents Non-Hazardous and Hazardous Waste The federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.
Non-Hazardous and Hazardous Waste The federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.
The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units representing limited partner interests in the Partnership (“common units”) and (iii) the issuance of 2,497,134 common units of the Operating Company (“OpCo common units”) and an equal number of newly issued Class B common units representing limited partner interests in the Partnership (“Class B units”).
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.
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. ​
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.
(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 April 17, 2020, we completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”) from the owners of such entities (collectively, the “Springbok Sellers”).
(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”).
ORRIs The following table sets forth information relating to our acreage for our ORRIs at December 31, 2022: ​ ​ ​ ​ ​ ​ ​ ​ ​ Developed ​ Undeveloped ​ Total State ​ Acreage ​ Acreage ​ Acreage Texas 1,395,641 680 1,396,321 Oklahoma 1,336,042 19,000 1,355,042 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 110,796 960 111,756 Other 271,100 — 271,100 Total 4,671,734 (1) 21,090 (2) 4,692,824 (1) Reflects ORRIs in approximately 4,671,709 total gross (55,335 net) developed acres.
(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.
Kimbell Tiger Acquisition Corporation In April 2021, we formed TGR as a special purpose acquisition company, or SPAC, for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses.
Kimbell Tiger Acquisition Corporation On February 8, 2022, we announced the initial public offering (the “TGR IPO”) of our recently dissolved special purpose acquisition company, Kimbell Tiger Acquisition Corporation (“TGR”) for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses.
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.
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.
That rule was rescinded in December 2017. This rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision has been appealed. If these requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive.
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.
During the years ended December 31, 2022, 2021 and 2020, payments we received from our top purchaser accounted for approximately 11.3%, 6.0% and 7.1%, 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 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.
Legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations.
If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary.
The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner.
On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations.
If these requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive. 29 Table of Contents On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeRisks 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.
Biggest changeThe 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.
Distributions we pay in excess of our earnings and profits are not be treated as “dividends” for United States federal income tax purposes; instead, they are treated first as a tax-free return of capital to the extent of your tax basis in your units and then as capital gain realized on the sale or exchange of such units.
Distributions we pay in excess of our earnings and profits are not to be treated as “dividends” for United States federal income tax purposes; instead, they are treated first as a tax-free return of capital to the extent of your tax basis in your units and then as capital gain realized on the sale or exchange of such units.
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.
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; 36 Table of Contents ● 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; ● 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 37 Table of Contents ● our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
These conflicts include, among others, the following situations: ● neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests; ● our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities; ● many of the officers and directors of our General Partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and owe fiduciary duties to our Sponsors, or any other investment partnership that they control, and the Contributing Parties and their respective owners; 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.
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; 39 Table of Contents ● determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or ● determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
For example, our partnership agreement provides that: ● whenever our General Partner (acting in its capacity as our General Partner), the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our General Partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity; ● our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; ● our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and ● our General Partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: ● approved by the conflicts committee of the Board of Directors, although our General Partner is not obligated to seek such approval; ● approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates; ● determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or ● determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. 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.
These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the Clean Water Act and OPA (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the RCRA (and comparable state laws that impose requirements for the handling and disposal of waste), the CERCLA, also known as the “Superfund” law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our operators or at locations our operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials 61 Table of Contents our operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).
These laws include, but are not limited to, the federal Clean Air Act (and comparable state laws and regulations that impose obligations related to air emissions), the Clean Water Act and OPA (and comparable state laws and regulations that impose requirements related to discharges of pollutants into regulated bodies of water), the RCRA (and comparable state laws that impose requirements for the handling and disposal of waste), the CERCLA, also known as the “Superfund” law, and the community right to know regulations under Title III of the act (and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by our operators or at locations our operators sent waste for disposal and comparable state laws that require organization and/or disclosure of information about hazardous materials our operators use or produce), the federal Occupational Safety and Health Act (which establishes workplace standards for the protection of health and safety of employees and requires a hazardous communications program) and the Endangered Species Act and the Migratory Bird Treaty Act (and comparable state laws that seek to ensure activities do not jeopardize endangered or threatened animals, fish, plant species by limiting or prohibiting construction activities in areas that are inhabited by such species and penalizing the taking, killing or possession of migratory birds).
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; 53 Table of Contents ● 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; ● 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.
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; 45 Table of Contents ● 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; ● the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; ● the price and availability of alternative fuels; and ● overall domestic and global economic conditions.
Historically, oil, natural gas and NGL prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: ● the domestic and foreign supply of and demand for oil, natural gas and NGLs; ● the level of prices and expectations about future prices of oil, natural gas and NGLs; ● the level of global oil and natural gas exploration and production; ● the cost of exploring for, developing, producing and delivering oil and natural gas; ● the price and quantity of foreign imports; ● the level of United States domestic production; ● political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia; ● the ability of members of the OPEC to agree to and maintain oil price and production controls; ● the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions; ● speculative trading in crude oil, natural gas and NGL derivative contracts; ● the level of consumer product demand; ● weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change; ● risks associated with operating drilling rigs; ● technological advances affecting energy consumption; ● domestic and foreign governmental regulations and taxes; ● the continued threat of terrorism and the impact of military and other action, including military actions involving Russia and Ukraine and the conflict in the Middle East; ● the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; ● the price and availability of alternative fuels; and ● overall domestic and global economic conditions.
Our existing and any future indebtedness could have important consequences to us, including: ● our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us; ● covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; 50 Table of Contents ● our access to the capital markets may be limited; ● our borrowing costs may increase; ● we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and ● our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our existing and any future indebtedness could have important consequences to us, including: ● our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us; ● covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; ● our access to the capital markets may be limited; ● our borrowing costs may increase; ● we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and ● our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including: ● the capital costs required for drilling activities by the operators of our properties, which could be significantly more than anticipated; ● the ability of the operators of our properties to access capital; ● prevailing commodity prices; ● the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; 51 Table of Contents ● the operators’ expertise, operating efficiency and financial resources; ● approval of other participants in drilling wells; ● the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; ● the selection of technology; ● the selection of counterparties for the marketing and sale of production; and ● the rate of production of the reserves.
The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including: ● the capital costs required for drilling activities by the operators of our properties, which could be significantly more than anticipated; ● the ability of the operators of our properties to access capital; ● prevailing commodity prices; ● the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; ● the operators’ expertise, operating efficiency and financial resources; ● approval of other participants in drilling wells; ● the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; ● the selection of technology; ● the selection of counterparties for the marketing and sale of production; and ● the rate of production of the reserves.
Our historical estimates of proved reserves and related valuations as of December 31, 2022, 2021 and 2020 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, 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 secured revolving credit facility contains various covenants and restrictive provisions that limit our ability to, among other things: ● incur or guarantee additional debt; ● make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists; ● make certain investments and acquisitions; ● incur certain liens or permit them to exist; 49 Table of Contents ● enter into certain types of transactions with affiliates; ● merge or consolidate with another company; and ● transfer, sell or otherwise dispose of assets.
Our secured revolving credit facility contains various covenants and restrictive provisions that limit our ability to, among other things: ● incur or guarantee additional debt; ● make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists; ● make certain investments and acquisitions; ● incur certain liens or permit them to exist; ● enter into certain types of transactions with affiliates; ● merge or consolidate with another company; and ● transfer, sell or otherwise dispose of assets.
Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state 63 Table of Contents and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.
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 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.
In addition, the actual amount of our available cash we will have to distribute each quarter will be reduced by replacement capital expenditures we make, payments in respect of our debt instruments and 34 Table of Contents other contractual obligations, tax obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine are appropriate.
In addition, the actual amount of our available cash we will have to distribute each quarter will be reduced by replacement capital expenditures we make, payments in respect of our debt instruments and other contractual obligations, tax obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine are appropriate.
As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available for distribution on common units. 56 Table of Contents Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.
As such, the actual drilling activities of the operators of our properties may materially differ from those presently identified, which could materially adversely affect our business, results of operation and cash available for distribution on common units. Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production.
Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including: ● unusual or unexpected geological formations; ● loss of drilling fluid circulation; ● title problems; ● facility or equipment malfunctions; 48 Table of Contents ● unexpected operational events; ● shortages or delivery delays of equipment and services; ● compliance with environmental and other governmental requirements; and ● adverse weather conditions.
Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including: ● unusual or unexpected geological formations; ● loss of drilling fluid circulation; ● title problems; ● facility or equipment malfunctions; ● unexpected operational events; ● shortages or delivery delays of equipment and services; ● compliance with environmental and other governmental requirements; and ● adverse weather conditions.
Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. 65 Table of Contents Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
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 $1.33 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 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.
If an operator of our properties is not satisfied with the 57 Table of Contents documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest.
If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest.
In addition, we entered into a transition services agreement in connection with the Springbok 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 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 some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or 62 Table of Contents suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations or taken other regulatory actions to curtail injection of produced water to account for induced seismicity.
In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations or taken other regulatory actions to curtail injection of produced water to account for induced seismicity.
However, the information that we provide to you may be inconsistent with the 59 Table of Contents amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return. The portion of our distributions taxable as dividends may be greater than expected.
However, the information that we provide to you may be inconsistent with the amounts reported to you by your broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to your tax return. The portion of our distributions taxable as dividends may be greater than expected.
Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders. 38 Table of Contents Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business.
Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders. Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage and operate, or arrange for the management and operation of, our business.
If this occurs or if production estimates change or exploration or development results deteriorate, full-cost efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas 46 Table of Contents properties.
If this occurs or if production estimates change or exploration or development results deteriorate, full-cost efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.
Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than 54 Table of Contents estimates based on a lengthy production history.
Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history.
The loss of their services, or the services of one or more members of our executive team or those providing services to us 55 Table of Contents pursuant to a contract, could materially adversely affect our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel.
The loss of their services, or the services of one or more members of our executive team or those providing services to us pursuant to a contract, could materially adversely affect our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel.
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).
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).
This effectively permits a “change of control” without the vote or consent of the unitholders. Our sole cash-generating asset is our membership interest in the Operating Company, and we are accordingly dependent upon distributions from the Operating Company to pay taxes and cover our expenses and to make distributions to our unitholders.
This effectively permits a “change of control” without the vote or consent of the unitholders. 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.
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; 44 Table of Contents ● future sales of our common units; and ● the other factors described in these “Risk Factors.” 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.” 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.
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.
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.
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.
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.
During 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 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.
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.
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.
Certain Relationships and Related Party Transactions, and Director Independence.” Unlike publicly traded corporations, we do not conduct annual meetings of our 40 Table of Contents unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations.
Certain Relationships and Related Party Transactions, and Director Independence.” Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations.
In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets. Legal, Environmental and Regulatory Risks ​ Oil and natural gas operations are subject to various governmental laws and regulations.
In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets. 60 Table of Contents Legal, Environmental and Regulatory Risks ​ Oil and natural gas operations are subject to various governmental laws and regulations.
Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax sooner than expected, our tax liability being greater than expected or a greater portion of our distributions being treated as taxable dividends.
Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax 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.
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.
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.
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.
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.
Our General Partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our General Partner to transfer its 41 Table of Contents membership interests in our General Partner to a third party.
Our General Partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our General Partner to transfer its membership interests in our General Partner to a third party.
Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for distribution on common units. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions, which, in turn, could negatively impact our growth and cash available for distribution on common units.
Our failure to minimize any unforeseen difficulties could materially adversely affect our financial condition and cash available for 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.
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.
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 actions of 60 Table of Contents President Biden, and the Biden Administration, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.
Further actions of President Biden, and the Biden Administration, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.
The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of 47 Table of Contents established production.
The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.
As of December 31, 2022, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 12.4%. 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.
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.
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.
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.
Because 58 Table of Contents an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may substantially reduced by our tax liabilities.
Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may be substantially reduced by our tax liabilities.
In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. ​ Item 1B. Unresolved Staff Comments None.
We will be required to take write-downs of the carrying values of our properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value. Accounting rules require that we periodically review the carrying value of our properties for possible impairment.
We will be required to take write-downs of the carrying values of our proved properties if commodity prices decrease to a level such that the future cash flows discounted at 10% from our proved properties are less than their carrying value. Accounting standards require that we periodically review the carrying value of our properties for possible impairment.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates and their transferees, the Contributing Parties and their respective affiliates, persons who acquired such units with the prior approval of the Board of Directors, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units at our option, may not vote on any matter.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates and their transferees, the Contributing Parties and their respective affiliates, persons who acquired such units with the prior approval of the Board of Directors, holders of Series A preferred units in connection with any vote, consent or approval of holders of the Series A preferred units, voting as a separate class or on an as-converted basis with the holders of common units, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units or any conversion of the Series A preferred units at our option, may not vote on any matter.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities. As of December 31, 2022, we had approximately $233.0 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, 2023, we had approximately $294.2 million in borrowings outstanding under our senior secured credit facility.
We depend in part on acquisitions to grow our reserves, production and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations.
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.
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.
For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive.
The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution prior to distributions on our common units.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. Holders of our Series A preferred units and Class B units are entitled to receive quarterly cash distributions prior to distributions on our common units.
If the operators of our properties are unable to obtain water to use in their operations from local sources or are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
If the operators of our properties are unable to obtain water to use in their 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.
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, softened. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We recorded material impairments in prior years as a result of the decline in oil and natural gas prices.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.
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.
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.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.
Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially adversely affect our financial condition, results of operations and cash available for distribution on common units. 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.
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.
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.
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.
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.
Derivative contracts also expose us to the risk of financial loss in some circumstances, including when: ● production is less than expected; ● the counterparty to the derivative contract defaults on its contract obligation; or ● the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.
Derivative contracts also expose us to the risk of financial loss in some circumstances, including when: ● production is less than expected; ● the counterparty to the derivative contract defaults on its contract obligation; or ● the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected. 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.
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. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data.
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. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data.
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.
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.
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 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 acquired mineral interests.
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.
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.
To increase reserves and production, we would need the operators of our properties to undertake replacement activities or use third parties to accomplish these activities. Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available for distribution on common units.
Our failure to successfully identify, complete and integrate acquisitions of properties or businesses would slow our growth and could materially adversely affect our results of operations and cash available for distribution on common units. We depend in part on acquisitions to grow our reserves, production and cash generated from operations.
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.
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.
The successful acquisition of properties requires an assessment of several factors, including: ● recoverable reserves; 52 Table of Contents ● future oil, natural gas and NGL prices and their applicable differentials; ● development plans; ● operating costs; and ● potential environmental and other liabilities.
The successful acquisition of properties requires an assessment of several factors, including: ● recoverable reserves; ● future oil, natural gas and NGL prices and their applicable differentials; ● development plans; ● operating costs; and ● potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities.
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.
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.
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. In addition, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and gas reserves or otherwise maintain an asset base.
In addition, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and gas reserves or otherwise maintain an asset base. To increase reserves and production, we would need the operators of our properties to undertake replacement activities or use third parties to accomplish these activities.
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, 2022, we received revenue from approximately 1,500 operators and we received approximately 40.3% of revenues from the top ten purchasers of our properties.
Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties.
Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units. Changes in certain market conditions may cause the price of our common units to decrease.
Changes in certain market conditions may cause the price of our common units to decrease.
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. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
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.
As of February 17, 2023, the owners of our Sponsors own or control an aggregate of approximately 9.9% of our outstanding common units and Class B units, and our Sponsors indirectly own and control our General Partner.
As of February 16, 2024, the owners of our Sponsors own or control 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.
Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units or Class B units to be repurchased by it upon exercise of the limited call right. 42 Table of Contents There is no restriction in our partnership agreement that prevents our General Partner from causing us to issue additional common units or Class B units and then exercising its call right.
Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units or Class B units to be repurchased by it upon exercise of the limited call right.
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 We are no longer an “emerging growth company,” and, as a result, we now must comply with increased reporting and disclosure requirements, which may increase our costs.
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.
In addition, consequences associated with the ongoing invasion of Ukraine by Russia, and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices.
In addition, consequences associated with the ongoing invasion of Ukraine by Russia, the conflict in the Middle East, and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries.

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Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

11 edited+11 added−4 removed18 unchanged
Biggest changeGeneral Partner Interest Our General Partner owns a non-economic general partner interest in us and therefore is not entitled to receive cash distributions. However, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.
Biggest changeHowever, it may acquire common units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests. Securities Authorized for Issuance under Equity Compensation Plans See “Item 12.
The limited liability company agreement of the Operating Company generally defines “available cash” as: ● the sum of: ● all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and ● as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter; ● 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 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.
For the quarter ended December 31, the limited liability company agreement of the Operating Company requires that the Operating Company distribute its available cash to holders of record of its OpCo common units on the applicable record date by the earlier of (i) 20 business days following the publication by the managing member of 69 Table of Contents the Operating Company of its results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.
For the quarter ended December 31, the limited liability company agreement of the Operating Company requires that the Operating Company distribute its available cash to holders of record of its OpCo common units on the applicable record date by the earlier of (i) 20 business days following the publication by the managing member of the Operating Company of its results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.
The Board of Directors approved the allocation of approximately 25% of our cash available for distribution on common units for the fourth quarter of 2022 for the repayment of $13.1 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2022.
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.
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 We expect to pay our distributions for the quarters ending March 31, June 30 and September 30 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. 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.
Securities Authorized for Issuance under Equity Compensation Plans See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2022.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2023.
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 17, 2023, there were 64,231,833 common units outstanding held by 158 holders of record and 15,484,400 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 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.
Method of Distributions Subject to the distribution preferences of the Class B units, we intend to distribute available cash to our common unitholders pro rata. Our partnership agreement permits, but does not require, us to borrow to pay distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.
Method of Distributions Subject to the distribution preferences of the Series A preferred units and the Class B units, we intend to distribute available cash to our common unitholders pro rata. Our partnership agreement permits, but does not require, us to borrow to pay distributions.
Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution prior to distributions on our common units. 70 Table of Contents Common Units As of February 17, 2023, we had 64,231,833 common 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.
Unregistered Sales of Equity Securities On March 30, 2022, we issued 9,357,919 common units to PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (the “PEP Entities”) in exchange for 9,357,919 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 the PEP Entities, 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.
On 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.
Subject to the distribution preferences of the Class B units, each common unit is entitled to receive cash distributions to the extent we distribute available cash. Common units do not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.
Subject to the distribution preferences of the Series A preferred units and Class B units, each common unit is entitled to receive cash distributions to the extent we distribute available cash. Common units do not accrue arrearages.
Removed
We expect to pay our distributions for the quarter ending December 31 by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.
Added
Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter. The Series A preferred units and Class B units will receive the distribution preference described below.
Removed
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.
Added
Series A preferred units Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions.
Removed
The Class B units will receive the distribution preference described below. Class B units As of February 17, 2023, we had 15,484,400 Class B units outstanding.
Added
We have the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum.
Removed
On April 22, 2022, we issued 42,081 common units to PEP II Holdings, LLC in exchange for 42,081 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.
Added
If we make such an election in consecutive quarters or otherwise materially breach our obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid or the breach is cured, as applicable.
Added
Each holder of Series A preferred units has the right to share in any special distributions by us of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments.
Added
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.
Added
Subject to the voting rights of the Series A preferred units, our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank. General Partner Interest Our General Partner owns a non-economic general partner interest in us and therefore is not entitled to receive cash distributions.
Added
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
Medary, Wayne A. Psencik in a private placement.
Added
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”).
Added
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)

1 edited+0 added−0 removed0 unchanged
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 86 Item 8. Financial Statements and Supplementary Data 90 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 90 Item 9A. Controls and Procedures 91
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.

Item 7. Management's Discussion & Analysis

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

91 edited+35 added−27 removed73 unchanged
Biggest changeA significant portion of our mineral and royalty interests are located in Texas basins and producing regions. 77 Table of Contents Results of Operations The table below summarizes our revenue and expenses and production data for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 ​ 2021 ​ 2020 Operating Results: ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL revenues ​ $ 281,964,126 ​ $ 175,088,021 ​ $ 92,586,685 Lease bonus and other income ​ ​ 3,073,609 ​ ​ 3,319,104 ​ ​ 345,771 Loss on commodity derivative instruments, net ​ ​ (36,978,550) ​ ​ (42,791,909) ​ ​ (2,450,541) Total revenues ​ ​ 248,059,185 ​ ​ 135,615,216 ​ ​ 90,481,915 Costs and expenses ​ ​ ​ ​ ​ ​ ​ ​ ​ Production and ad valorem taxes ​ 16,238,814 ​ 10,480,481 ​ 6,389,231 Depreciation and depletion expense ​ 50,086,414 ​ 36,797,881 ​ 47,988,796 Impairment of oil and natural gas properties ​ — ​ — ​ 251,558,557 Marketing and other deductions ​ 13,383,074 ​ 12,048,643 ​ 9,376,375 General and administrative expenses ​ 29,128,659 ​ 26,977,519 ​ 25,902,496 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ General and administrative expense ​ ​ 2,304,445 ​ — ​ ​ — Total costs and expenses ​ 111,141,406 ​ 86,304,524 ​ 341,215,455 Operating income (loss) ​ 136,917,779 ​ 49,310,692 ​ (250,733,540) Other income (expense) ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity income in affiliate ​ ​ 2,668,844 ​ ​ 1,119,819 ​ ​ 763,988 Interest expense ​ (13,818,310) ​ (9,182,103) ​ (6,430,061) Loss on extinguishment of debt ​ ​ — ​ — ​ (476,350) Other income (expense) ​ 4,043,530 ​ 1,263,566 ​ ​ (100,000) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ 3,721,145 ​ — ​ ​ — Net income (loss) before income taxes ​ ​ 133,532,988 ​ ​ 42,511,974 ​ ​ (256,975,963) Income tax expense (benefit) ​ ​ 2,738,702 ​ ​ 74,100 ​ ​ (885,193) Net income (loss) ​ ​ 130,794,286 ​ ​ 42,437,874 ​ ​ (256,090,770) Distribution and accretion on Series A preferred units ​ ​ — ​ ​ (11,249,969) ​ ​ (7,810,588) Net (income) loss and distributions and accretion on Series A preferred units attributable to non-controlling interests in OpCo ​ ​ (18,822,552) ​ ​ (8,496,104) ​ ​ 96,642,334 Distribution on Class B units ​ ​ (42,243) ​ ​ (76,780) ​ ​ (91,869) Net income (loss) attributable to common units of Kimbell Royalty Partners, LP ​ $ 111,929,491 ​ $ 22,615,021 ​ $ (167,350,893) Production Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil (Bbls) ​ 1,425,842 ​ 1,343,771 ​ 1,409,163 Natural gas (Mcf) ​ 20,310,991 ​ 19,085,400 ​ 17,891,384 Natural gas liquids (Bbls) ​ 746,865 ​ 714,494 ​ 681,575 Combined volumes (Boe) (6:1) ​ 5,557,872 ​ 5,239,165 ​ 5,072,635 ​ Comparison of the Year Ended December 31, 2022 to the Year Ended December 31, 2021 and the Year Ended December 31, 2021 to the Year Ended December 31, 2020 Oil, Natural Gas and NGL Revenues For the year ended December 31, 2022, our oil, natural gas and NGL revenues were $282.0 million, an increase of $106.9 million from $175.1 million for the year ended December 31, 2021.
Biggest changeA 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.
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 and 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, 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.
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, 2022 and 2021, we recorded a full valuation allowance on our deferred tax assets.
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.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion.
For the year ended December 31, 2021, we used approximately $54.6 million to fund the Cornerstone acquisition, we used $0.8 million primarily to fund the renovation of office space, $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP (“Oil Nut Bay”), partially offset by a $0.5 million cash distribution received in connection with the Joint Venture during the period.
For the year ended December 31, 2021, we used approximately $54.6 million to fund the Cornerstone acquisition, we used $0.8 million primarily to fund the renovation of office space, $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP, partially offset by a $0.5 million cash distribution received in connection with the Joint Venture during the period.
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 2022.
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.
Market for Registrant’s Common Equity, Related Unitholder 81 Table of Contents Matters and Issuer Purchases of Equity Securities—Definition of Available Cash.” We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Definition of Available Cash.” We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
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, 2022, 2021 and 2020, in each case based on the reserve report prepared by Ryder Scott.
For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.” Reserves and Pricing The tables below identify our proved reserves at December 31, 2023, 2022 and 2021, in each case based on the reserve report prepared by Ryder Scott.
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 are 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 unitholder, partially offset by $183.3 million used to repay borrowings under out secured revolving credit facility, $126.8 million of distributions paid to holders 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 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.
As of December 31, 2022, 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, 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.
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.
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.
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 ​ 2022 ​ 2021 ​ 2020 Permian Basin ​ 47 ​ 25 ​ 17 Mid‑Continent ​ 12 ​ 8 ​ 7 Terryville/Cotton Valley/Haynesville ​ 15 ​ 12 ​ 9 Appalachian Basin ​ 1 ​ 1 ​ 1 Bakken/Williston Basin ​ 6 ​ 6 ​ 3 Eagle Ford ​ 7 ​ 6 ​ 1 DJ Basin/Rockies/Niobrara ​ — ​ 1 ​ 1 Other ​ 4 ​ 2 ​ — Total ​ 92 ​ 61 ​ 39 ​ 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 ​ 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.
Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company 84 Table of Contents allocated to us.
Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us.
In calculating future net revenues, prices are calculated as the average oil, natural gas and NGL prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the reporting period.
In calculating future net revenues, prices are calculated as the average oil, natural gas and NGL prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the reporting period. 88 Table of Contents
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.
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.
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 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.
To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of the invasion of Ukraine; however, we will continue to monitor for events that could materially impact us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile and may continue to be volatile in the future.
To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile and may continue to be volatile in the future.
Lease Bonus and Other Income Lease bonus and other income remained relatively flat at $3.1 million for the year ended December 31, 2022, compared to $3.3 million for the year ended December 31, 2021.
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.
The inclusion of our unevaluated costs into the amortization base is expected to be completed within five years. 76 Table of Contents Marketing and Other Deductions Marketing and other deductions include product marketing expense, which is a post-production expense.
The inclusion of our unevaluated costs into the amortization base is expected to be completed within five years. Marketing and Other Deductions Marketing and other deductions include product marketing expense, which is a post-production expense.
The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.
We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter. 75 Table of Contents Impairment of Oil and Natural Gas Properties Accounting rules require that we periodically review the carrying value of our properties for possible impairment.
We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter. 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.
The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2022 for the repayment of $13.1 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2022.
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 process of estimating oil, natural gas and NGL reserves is complex, requiring 85 Table of Contents 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.
As noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine, have created increased volatility in oil and natural gas prices.
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.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 124,000 gross wells, including over 48,000 wells in the Permian Basin.
Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin.
As a result, we incur interest expense, which is included in our accompanying consolidated statements of operations. Please read “Liquidity and Capital Resources—Indebtedness” for further discussion of our secured revolving credit facility. Income Tax Expense Effective as of September 24, 2018, the Partnership elected to be taxed as a corporation for United States federal income tax purposes.
As a result, we incur interest expense, which is included in our accompanying consolidated statements of operations. Please read “Liquidity and Capital Resources—Indebtedness” for further discussion of our secured revolving credit facility. Income Tax Expense We have elected to be taxed as a corporation for United States federal income tax purposes.
The following table presents the breakdown of our oil, natural gas, and NGL revenues for the following periods: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 2021 2020 Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil sales ​ 46 % ​ 50 % ​ 56 % Natural gas sales ​ 44 % ​ 38 % ​ 35 % NGL sales ​ 10 % ​ 12 % ​ 9 % ​ ​ 100 % ​ 100 % ​ 100 % We have entered into oil and natural gas commodity derivative agreements, which extend through December 2024, 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, ​ ​ 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, as reported by the EIA, sets forth the average prices for oil and natural gas. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 ​ 2021 2020 Oil ($/Bbl) ​ $ 94.90 ​ $ 68.14 ​ $ 39.16 Natural gas ($/MMBtu) ​ $ 6.45 ​ $ 3.89 ​ $ 2.03 Rig Count Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
The following table, as reported by the EIA, sets forth the average prices for oil and natural gas. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2023 ​ 2022 2021 Oil ($/Bbl) ​ ​ $ 77.58 ​ $ 94.90 ​ $ 68.14 Natural gas ($/MMBtu) ​ ​ $ 2.53 ​ $ 6.45 ​ $ 3.89 Rig Count Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
Cash flows provided by operating activities for the year ended December 31, 2022 were $166.6 million, an increase of $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, 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.
The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.
The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under our secured revolving credit facility.
The prices used to estimate proved reserves for the respective periods were held 74 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 2022 ​ 2021 ​ 2020 Oil (MBbls) 12,355 ​ 12,511 ​ 12,294 Natural gas (MMcf) 160,298 ​ 157,764 ​ 144,233 Natural gas liquids (MBbls) 7,388 ​ 6,669 ​ 6,085 Total (MBoe)(6:1) 46,459 ​ 45,474 ​ 42,418 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, Unweighted Arithmetic Average First ‑ Day ‑ of ‑ the ‑ Month Prices 2022 ​ 2021 ​ 2020 Oil (Bbls) ​ $ 93.67 ​ $ 66.56 ​ $ 39.57 Natural gas (Mcf) ​ $ 6.36 ​ $ 3.60 ​ $ 1.99 ​ 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 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 significant increase in oil, natural gas and NGL revenues was primarily related to the 78 Table of Contents 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, 2021 as discussed below.
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.
We intend to pay the distributions on March 16, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on March 9, 2023. As to us, $0.000265 of the OpCo common unit distribution corresponds to a tax payment made by us in the fourth quarter of 2022.
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.
Investing Activities Cash flows used in investing activities for the year ended December 31, 2022 were $374.7 million compared to $55.6 million for the year ended December 31, 2021.
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.
As of December 31, 2022, we owned mineral and royalty interests in approximately 11.5 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% of our aggregate acres located in the Permian Basin and Mid-Continent.
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.
Loss on commodity derivative instruments for the year ended December 31, 2020 included $7.1 million of mark-to-market losses and $4.6 million of gains on the settlement of commodity derivative instruments. 79 Table of Contents Production and Ad Valorem Taxes Production and ad valorem taxes for the year ended December 31, 2022 were $16.2 million, an increase of $5.7 million from $10.5 million for the year ended December 31, 2021.
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.
We recognized an income tax benefit of $0.9 million for the year ended December 31, 2020, resulting in an effective tax rate of 0.34%. The overall change in our effective tax rate for the year ended December 31, 2022 is primarily due estimated current federal income tax that cannot be sheltered by a net operating loss carryforward.
We recognized an income tax expense of $0.1 million for the year ended December 31, 2021, resulting in an effective tax rate of 0.17%. The overall change in our effective tax rate for the year ended December 31, 2023 is primarily due estimated current federal and state income tax that cannot be sheltered by a net operating loss carryforward.
The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ Year Ended December 31, 2021 ​ Year Ended December 31, 2020 ​ ​ High Low ​ High Low ​ High Low Oil ($/Bbl) ​ $ 123.64 ​ $ 71.05 ​ $ 85.64 ​ $ 47.47 ​ $ 63.27 ​ $ (36.98) Natural gas ($/MMBtu) ​ $ 9.85 ​ $ 3.46 ​ $ 23.86 ​ $ 2.43 ​ $ 3.14 ​ $ 1.33 ​ On February 6, 2023, the WTI posted price for crude oil was $74.11 per Bbl and the Henry Hub spot market price of natural gas was $2.17 per MMBtu.
The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ Year Ended December 31, 2022 ​ Year Ended December 31, 2021 ​ ​ High Low ​ High Low ​ High Low Oil ($/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.
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 increased 34% to 762 active land rigs at December 31, 2022 compared to 570 active land rigs at December 31, 2021.
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.
The increase in marketing and other deductions was primarily attributable the increase in prices for oil, natural gas and NGL production. 80 Table of Contents General and Administrative Expense General and administrative expenses for the year ended December 31, 2022 were $29.1 million, an increase of $2.1 million from $27.0 million for the year ended December 31, 2021.
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.
See “Indebtedness” below for further discussion of our secured revolving credit facility. Cash Distribution Policy The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter.
Cash Distribution Policy The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter.
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.
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 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.
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.
Financing Activities Cash flows provided by financing activities were $226.1 million for the year ended December 31, 2022 compared to $38.6 million of cash flows used in financing activities for the year ended December 31, 2021.
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.
Capital Expenditures During the year ended December 31, 2022, we paid approximately $141.3 million primarily to fund the Hatch Acquisition. During the year ended December 31, 2021, we paid approximately $55.3 million, which was primarily 83 Table of Contents attributable to the completion of the Cornerstone acquisition.
During the year ended December 31, 2021, we paid approximately $55.3 million, which was primarily attributable to the completion of the Cornerstone acquisition.
Income Tax Expense (Benefit) For the year ended December 31, 2022, we recognized an income tax expense of $2.7 million, resulting in an effective tax rate of 2.05%, compared to income tax expense of $0.1 million for the year ended December 31, 2021, resulting in an effective tax rate of 0.17%.
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%.
Our average depletion rate per barrel was $8.84 for the year ended December 31, 2022, an increase of $2.06 per barrel from the $6.78 average depletion rate per barrel for the year ended December 31, 2021.
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.
Cash Flows The following table presents our cash flows for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 2021 ​ 2020 Cash Flow Data: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net cash provided by operating activities ​ $ 166,636,493 ​ $ 91,442,481 ​ $ 62,245,341 Net cash used in investing activities ​ (374,723,901) ​ (55,572,551) ​ (90,827,734) Net cash provided by (used in) financing activities ​ 226,061,562 ​ (38,622,493) ​ 24,183,120 Net increase (decrease) in cash and cash equivalents ​ $ 17,974,154 ​ $ (2,752,563) ​ $ (4,399,273) 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 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.
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 for the volumes sold during the year ended December 31, 2022 and $64.86 per Bbl of oil, $3.51 per Mcf of natural gas and $29.33 per Bbl of NGL for the volumes sold during the year ended December 31, 2021.
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.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.
An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.
As an owner of mineral and royalty interests, we are entitled to 71 Table of Contents a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes.
We have elected to be taxed as a corporation for United States federal income tax purposes. 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.
For the year ended December 31, 2021, production and ad valorem taxes increased by $4.1 million from $6.4 million for the year ended December 31, 2020.
For the year ended December 31, 2022, production and ad valorem taxes increased by $5.7 million from $10.5 million for the year ended December 31, 2021.
Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.
Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023.
Depreciation and Depletion Expense Depreciation and depletion expense for the year ended December 31, 2022 was $50.1 million, an increase of $13.3 million from $36.8 million for the year ended December 31, 2021.
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.
Cash flows used in investing activities for the year ended December 31, 2021 increased by $35.2 million compared to cash flows used in used in investing activities of $90.8 million for the year ended December 31, 2020.
Cash flows used in investing activities for the year ended December 31, 2022 increased by $319.1 million compared to cash flows used in used in investing activities of $55.6 million for the year ended December 31, 2021.
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. For the year ended December 31, 2021, depreciation and depletion expense decreased by $11.2 million from $48.0 million for the year ended December 31, 2020.
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 production for the year ended December 31, 2021 was primarily attributable to production associated with the Springbok Acquisition, which included a full year of production for the year ended December 31, 2021, compared to approximately eight months of production for the year ended December 31, 2020.
The increase in production for the year ended December 31, 2023 was primarily attributable to production associated with the Hatch Acquisition, which included a full year of production for the year ended December 31, 2023, compared to approximately three months of production for the year ended December 31, 2022, the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.
This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 74.0% or $28.98 per Bbl of oil and 91.6% or $1.86 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 18.3% or $17.32 per Bbl of oil and 60.8% or $3.92 per Mcf of natural gas for the comparable periods.
The year ended December 31, 2022 increased 41.4% or $26.88 per Bbl of oil and 72.1% or $2.53 per Mcf of natural gas compared to the year ended December 31, 2021.
Average prices received by our operators during the year ended December 31, 2022 increased 41.4% or $26.88 per Bbl of oil and 72.1% or $2.53 per Mcf of natural gas compared to the year ended December 31, 2021, which our operators received an average of $64.86 per Bbl of oil, $3.51 per Mcf of natural gas and $29.33 per Bbl of NGL.
Also contributing to the increase in interest expense was an increase in the weighted average interest rate from 3.86% at December 31, 2021 to 5.28% at December 31, 2022. Interest expense for the year ended December 31, 2021 increased by $2.8 million as compared to interest expense of $6.4 million for the year ended December 31, 2020.
Also contributing to the increase in interest expense was an increase in the weighted average interest rate from 3.86% at December 31, 2021 to 5.28% at December 31, 2022.
The increase in production and ad valorem taxes was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2021, and to a lesser extent, production and ad valorem taxes associated with the Springbok Acquisition.
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.
These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the years ended December 31, 2022, 2021 and 2020 include the Hatch Acquisition, the Cornerstone Acquisition and the Springbok Acquisition.
These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations.
Our revenues for the year ended December 31, 2021 increased by $82.5 million, from $92.6 million for the year ended December 31, 2020.
Our revenues for the year ended December 31, 2022 increased by $106.9 million, from $175.1 million for the year ended December 31, 2021.
Acquisitions On December 15, 2022, we completed the Hatch Acquisition for an aggregate purchase price of (i) approximately $150.4 million in cash and (ii) the issuance of 7,272,821 OpCo common units and an equal number of Class B units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility.
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 OpCo common units and an equal number of Class B Units and (b) 557,302 common units. We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility.
We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units.
The reduced tax basis will increase unitholders’ capital gain (or 86 Table of Contents decrease unitholders’ capital loss) when unitholders sell their common units.
Marketing and other deductions for the year ended December 31, 2021 increased by $2.6 million from $9.4 million for the year ended December 31, 2020.
Interest expense for the year ended December 31, 2022 increased by $4.6 million compared to interest expense of $9.2 million for the year ended December 31, 2021.
The 570 active rig count at December 31, 2021 increased significantly compared to 332 active land rigs at December 31, 2020. The overall increase in rig count is primarily 73 Table of Contents attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.
The increase in rig count for the 2022 period was primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.
General and administrative expenses for the year ended December 31, 2021 remained relatively flat compared to $25.9 million for the year ended December 31, 2020. Interest Expense Interest expense for the year ended December 31, 2022 was $13.8 million as compared to interest expense of $9.2 million for the year ended December 31, 2021.
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.
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.
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.
Our production volumes for the year ended December 31, 2021 increased by 166,530 Boe or 494 Boe/d, from 5,072,635 Boe or 13,860 Boe/d, for the year ended December 31, 2020.
Our production volumes for the year ended December 31, 2022 increased by 318,707 Boe or 671 Boe/d, from 5,239,165 Boe or 14,354 Boe/d, for the year ended December 31, 2021.
Recent Developments 2022 Equity Offering In November 2022, we completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to purchase OpCo common units.
Equity Offering On August 7, 2023, we completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). We used the net proceeds from the 2023 Equity Offering to purchase OpCo common units.
Cash flows provided by financing activities for the year ended December 31, 2020 were partially offset by $91.2 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $54.9 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $4.5 million paid in connection with amending our secured revolving credit facility and $0.4 million paid in connection with the redemption of Class B units.
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.
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.
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.
The decrease in depletion rate was due to the significant impairment that was recorded during the year ended December 31, 2020 which significantly reduced our net capitalized oil and natural gas properties.
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.
Marketing and other deductions for the year ended December 31, 2022 were $13.4 million, an increase of $1.4 million from $12.0 million for the year ended December 31, 2021, which was primarily attributable to the increase in prices for oil, natural gas and NGL production.
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.
As of December 31, 2020, the 12-month average prices of oil and natural gas were $39.57 per Bbl of oil and $1.99 per Mcf of natural gas.
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.
Our lease bonus and other income for the year ended December 31, 2021 increased by $3.0 million, from $0.3 million for the year ended December 31, 2020.
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.
These prices represent a 28.9% and 22.9% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2019, which were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas.
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.
Russia / Ukraine Conflict In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country.
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.
Impairment of Oil, Natural Gas and NGL Expense We did not record an impairment expense 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 years ended December 31, 2022 and 2021.

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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. 88 Table of Contents The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income (loss) and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 ​ 2021 ​ 2020 Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units: ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) ​ $ 130,794,286 ​ $ 42,437,874 ​ $ (256,090,770) Depreciation and depletion expense ​ ​ 50,086,414 ​ ​ 36,797,881 ​ ​ 47,988,796 Interest expense ​ ​ 13,818,310 ​ ​ 9,182,103 ​ ​ 6,430,061 Cash distribution from affiliate ​ ​ 385,326 ​ ​ 1,015,559 ​ ​ 812,810 Income tax expense (benefit) ​ ​ 2,738,702 ​ ​ 74,100 ​ ​ (885,193) EBITDA ​ ​ 197,823,038 ​ ​ 89,507,517 ​ ​ (201,744,296) Impairment of oil and natural gas properties ​ ​ — ​ ​ — ​ ​ 251,558,557 Unit-based compensation ​ ​ 11,107,639 ​ ​ 10,632,725 ​ ​ 9,261,756 Loss on extinguishment debt ​ ​ — ​ ​ — ​ ​ 476,350 (Gain) loss on derivative instruments, net of settlements ​ ​ (14,300,570) ​ ​ 20,343,783 ​ ​ 7,085,364 Cash distribution from affiliate ​ ​ 645,451 ​ ​ 500,389 ​ ​ — Equity income in affiliate ​ ​ (2,668,844) ​ ​ (1,119,819) ​ ​ (763,988) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ (3,721,145) ​ ​ — ​ ​ — General and administrative expenses ​ ​ 2,304,445 ​ ​ — ​ ​ — Consolidated Adjusted EBITDA ​ ​ 191,190,014 ​ ​ 119,864,595 ​ ​ 65,873,743 Adjusted EBITDA attributable to non-controlling interest ​ ​ (27,154,867) ​ ​ (35,608,960) ​ ​ (23,914,812) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 164,035,147 ​ ​ 84,255,635 ​ ​ 41,958,931 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 9,583,004 ​ ​ 5,297,810 ​ ​ 3,399,655 Cash distributions on Series A preferred units ​ ​ — ​ ​ 1,943,385 ​ ​ 3,047,466 Restricted units repurchased for tax withholding ​ ​ — ​ ​ 1,433,265 ​ ​ — Cash income tax expense ​ ​ 3,082,245 ​ ​ — ​ ​ — Distributions on Class B units ​ ​ 42,243 ​ ​ 76,780 ​ ​ 91,869 Cash available for distribution on common units ​ $ 151,327,655 ​ $ 75,504,395 ​ $ 35,419,941 ​ 89 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 ​ 2021 ​ 2020 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 ​ $ 166,636,493 ​ $ 91,442,481 ​ $ 62,245,341 Interest expense ​ 13,818,310 ​ 9,182,103 ​ 6,430,061 Income tax expense (benefit) ​ ​ 2,738,702 ​ ​ 74,100 ​ ​ (885,193) Impairment of oil and natural gas properties ​ — ​ — ​ (251,558,557) Amortization of right-of-use assets ​ ​ (319,674) ​ (298,093) ​ ​ (276,180) Amortization of loan origination costs ​ (1,872,700) ​ (1,556,769) ​ (1,108,685) Loss on extinguishment of debt ​ ​ — ​ — ​ (476,350) Equity (loss) income in affiliate, net ​ (716,481) ​ 1,119,819 ​ 763,988 Forfeiture of restricted units ​ ​ 19,813 ​ ​ — ​ ​ 127,934 Unit-based compensation ​ (11,107,639) ​ (10,632,725) ​ (9,261,756) Gain (loss) on derivative instruments, net of settlements ​ 14,300,570 ​ (20,343,783) ​ (7,085,364) Changes in operating assets and liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil, natural gas and NGL receivables ​ 11,846,567 ​ 17,594,389 ​ (1,618,006) Accounts receivable and other current assets ​ 511,319 ​ 2,077,637 ​ 897,088 Accounts payable ​ (399,318) ​ 77,716 ​ 319,001 Other current liabilities ​ (1,590,016) ​ 463,828 ​ (533,582) Operating lease liabilities ​ ​ 324,913 ​ 306,814 ​ ​ 275,964 Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in trust account ​ ​ 3,721,145 ​ — ​ ​ — Other assets and liabilities ​ ​ (88,966) ​ — ​ ​ — EBITDA ​ ​ 197,823,038 ​ ​ 89,507,517 ​ ​ (201,744,296) Add: ​ ​ ​ ​ ​ ​ ​ ​ ​ Impairment of oil and natural gas properties ​ — ​ — ​ 251,558,557 Unit-based compensation ​ 11,107,639 ​ 10,632,725 ​ 9,261,756 Loss on extinguishment of debt ​ ​ — ​ ​ — ​ ​ 476,350 (Gain) loss on derivative instruments, net of settlements ​ (14,300,570) ​ 20,343,783 ​ 7,085,364 Cash distribution from affiliate ​ ​ 645,451 ​ ​ 500,389 ​ ​ — Equity income in affiliate ​ ​ (2,668,844) ​ ​ (1,119,819) ​ ​ (763,988) Consolidated variable interest entities related: ​ ​ ​ ​ ​ ​ ​ ​ ​ Interest earned on marketable securities in Trust Account ​ ​ (3,721,145) ​ ​ — ​ ​ — General and administrative expenses ​ ​ 2,304,445 ​ ​ — ​ ​ — Consolidated Adjusted EBITDA ​ ​ 191,190,014 ​ ​ 119,864,595 ​ ​ 65,873,743 Adjusted EBITDA attributable to non-controlling interest ​ ​ (27,154,867) ​ ​ (35,608,960) ​ ​ (23,914,812) Adjusted EBITDA attributable to Kimbell Royalty Partners, LP ​ ​ 164,035,147 ​ ​ 84,255,635 ​ ​ 41,958,931 Adjustments to reconcile Adjusted EBITDA to cash available for distribution ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash interest expense ​ ​ 9,583,004 ​ ​ 5,297,810 ​ ​ 3,399,655 Cash distributions on Series A preferred units ​ ​ — ​ ​ 1,943,385 ​ ​ 3,047,466 Restricted units repurchased for tax withholding ​ ​ — ​ ​ 1,433,265 ​ ​ — Cash income tax expense ​ ​ 3,082,245 ​ ​ — ​ ​ — Distributions on Class B units ​ ​ 42,243 ​ ​ 76,780 ​ ​ 91,869 Cash available for distribution on common units ​ $ 151,327,655 ​ $ 75,504,395 ​ $ 35,419,941 ​ ​
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 ​ ​
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 $2.3 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 $2.9 million annually, assuming that our indebtedness remained constant throughout the year.
During the years ended December 31, 2022, 2021 and 2020, our top purchaser accounted for approximately 11.3%, 6.0% and 7.1%, 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, 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.
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, 2022, we had three 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, 2023, we had five counterparties to our derivative contracts, which are also lenders under our credit facility.
Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of COVID-19 and its variants, ongoing international supply and demand imbalances and limited international storage capacity.
Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of ongoing international supply and demand imbalances and limited international storage capacity.
See Note 4—Derivatives to the consolidated financial statements in Item 8 of this Annual Report for additional information regarding our commodity derivatives. Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
See Note 4—Derivatives to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding our commodity derivatives. Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, non cash unit based compensation, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income.
We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income.
The counterparty to the contracts is an unrelated third party. Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Interest Rate Risk We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2022, we had total borrowings outstanding under our secured revolving credit facility of $233.0 million.
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.
The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative 86 Table of Contents contracts to reduce our exposure to price volatility of oil and natural gas.
The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.
However, rising inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure.
Inflation Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 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.
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. 87 Table of Contents Inflation Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2020 through December 31, 2022.
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.
Removed
We hedge our daily production based on the amount of debt and/or preferred equity as a percent of our enterprise value. As of December 31 2022, these economic hedges constituted approximately 21% of our daily oil and natural gas production.

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