Kimbell Royalty Partners, LP

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. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. 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.

The diagram below depicts a simplified version of our organizational structure as of February 20, 2026:

Our Oil and Gas Assets

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

Mineral Interests

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

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

Overriding Royalty Interests

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

Overview of Our Oil and Gas Assets and Operations

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

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

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

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

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

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

Business Strategies

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

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

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

Competitive Strengths

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

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

Our Properties

Material Basins and Producing Regions

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

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

Mineral Interests

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

ORRIs

The following table sets forth information about our ORRIs:

Wells

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

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

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

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

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

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

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

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025, 2024 and 2023 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas, and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. All proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. All proved developed non-producing reserves were estimated by the analogy method.

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

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

Summary of Estimated Proved Reserves

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

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

The foregoing reserves are all located within the continental United States. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Item 1A. Risk Factors.”

Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2025, which is included as an exhibit to this Annual Report.

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:

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells. As of December 31, 2025, we owned mineral or royalty interests in over 133,000 gross productive wells, which consisted of over 98,000 oil wells and over 35,000 natural gas wells.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2025:

ORRIs

The following table sets forth information relating to our acreage for our ORRIs at December 31, 2025:

Drilling Results

As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant period.

Competition

The oil and natural gas industry is intensely competitive; we primarily compete with companies for the acquisition of oil and natural gas properties some of whom have greater resources than we do. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. 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. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months, while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. 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.

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.

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. 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. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. 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. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of certain environmental laws and regulations could impose liability upon the operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. 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.

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. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements under RCRA or related waste regulations. 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. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Any changes in the laws and regulations in the future could have a material adverse effect on the operators of our properties’ capital expenditures and operating expenses, which in turn could effect production from the acreage underlying our mineral and royalty interests and have a material adverse effect on our business and prospects.

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. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The federal Water Pollution Control Act of 1972 (“Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The EPA issued a final rule outlining its position on the federal jurisdictional reach over waters of the United States, in September 2015, but this rule was promptly challenged in courts and was enjoined by judicial action in some states.

In October 2019, the EPA and the United States Army Corps of Engineers issued a final rule that repealed the 2015 regulations and reinstated the agencies’ narrower pre-2015 scope of federal Clean Water Act jurisdiction. In April 2020, the EPA and the United States Army Corps of Engineers issued a new final waters of the United States (“WOTUS”) definition that provided a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction. On August 30, 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 Rule, and in June 2021, the EPA and the Army Corp of Engineers announced their intention to initiate a new rulemaking process to restore the 2015 definition of “waters of the United States.” The proposed rule was published on December 7, 2021. Following a standard comment period, the final rule establishing a revised and “durable” WOTUS definition, which restored many of the elements of the 2015 rule, was published in the Federal Register on January 18, 2023. Multiple legal challenges to the January 2023 final rule followed. Additionally, in May 2023, the Supreme Court of the United States issued its decision in a case,Sackett v. EPA, that clarified and narrowed the reach of federal jurisdiction under the Clean Water Act by focusing on water bodies forming geographic features. Then in August 2023, the EPA and Army Corps of Engineers released the text of a rule further revising the WOTUS definition to incorporate certain limitations on jurisdictional reach explained in the Supreme Court’s decision inSackett. Additional legal challenges to the January 2023 final rule and August 2023 regulation are proceeding in federal courts. With federal litigation ongoing, in March 2025, the EPA and Army Corps of Engineers issued updated guidance concerning determinations of whether a wetland has a “continuous surface connection” to a requisite jurisdictional water under the Clean Water Act to align with the Supreme Court decision inSackett. If the January 2023 final rule or other expanded WOTUS definition is ultimately implemented, Clean Water Act jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.

In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

The OPA is the primary federal law for oil spill liability. The 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 subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the operators of the acreage underlying our mineral interests.

Air Emissions

The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in May 2016, the EPA finalized regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the regulations applicable to sources in the production and processing segments and removed the transmission and storage segments from the source category, which removes them from the scope of the regulations. The 2020 rules were later challenged in the U.S. Circuit Court for the D.C. Circuit. In addition, on January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directing the EPA to consider publishing a proposed rule suspending, revising or rescinding the 2020 rules. In January 2024, the EPA published a proposed rule to assess methane “waste emissions charges” from the oil and gas sector. The final rule became effective in May 2024, and in July 2024, the D.C. Circuit denied a request to delay EPA’s implementation of the 2024 rule. However, the final methane rule from May 2024 is no longer in effect and has no force of law following disapproval by a joint resolution of Congress in March 2025 pursuant to the Congressional Review Act. Implementation of more stringent laws and regulations, including the reinstatement of the final methane rule from May 2024 or enactment of future methane regulations, may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In 2009, the EPA found that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment. Relying on this finding, which is referred to as the 2009 Endangerment Finding, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. On February 12, 2026, the EPA issued a final rule that rescinded the 2009 Endangerment Finding and repealed all GHG emission standards for motor vehicles that directly relied on the 2009 Endangerment Finding. The impact from the February 2026 rescission on other GHG regulations issued under the Clean Air Act that relied on the 2009 Endangerment Finding for legal support, including GHG regulations affecting the oil and gas industry, is uncertain.

During his presidency, President Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden administration’s climate policies. In his current presidential term, President Trump has reversed many climate-focused executive actions taken by President Biden. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at this time, it may do so in the future, and many states continue to pursue regulations to

reduce GHG emissions. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Additionally, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. As an example, the United States participated in the United Nations Conference on Climate Change in 2015, which led to the creation of the Paris Climate Agreement (the “Paris Agreement”). 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. Following a June 2017 announcement from President Trump, the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reversed this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021. In April 2021, President Biden announced a new, more rigorous nationally determined emissions reduction level of 50 percent to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030, and in November 2021, the international community gathered again in Glasgow at the 26th Conference of the Parties (“COP26”). 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. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative joined by more than 100 countries, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. During more recent COP meetings, the United States and other participating countries have reaffirmed these emission reduction goals. In January 2025, President Trump ordered the U.S. Ambassador to the United Nations to submit a formal written notification of the United States’ withdrawal from the Paris Agreement, which withdrawal by the United States became effective on January 27, 2026. The impacts of international efforts, pledges, agreements and any legislation or regulation promulgated to fulfill prior commitments by the United States under the Paris Agreement or other international conventions cannot be predicted at this time. Additionally, the Inflation Reduction Act, signed into law in August 2022, contains hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels, electric vehicles, carbon capture and sequestration, and supporting energy transition infrastructure. The substantial incentives contained in the Inflation Reduction Act could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower-emitting alternatives.

Moreover, activists and members of the investment community concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult or costly for operators to engage in exploration and production activities.

Finally, one potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados, droughts and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. From time to time, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure

of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. In March 2015, the Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for wellbore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. 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.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, did not find evidence that hydraulic fracturing has led to widespread, systematic impacts on drinking water resources but did identify instances in which impacts to drinking water may occur, including situations involving large volume spills and inadequate mechanical integrity of wells. The report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. This study and other ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. In addition, local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called 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. 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.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause our operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on our financial condition and results of operations. 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. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently

increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business and potentially delays operations, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of the operators of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. 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. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties

operate. The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the United States Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the operators of our properties receive for sales of natural gas and release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.

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.

Oil Sales and Transportation

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. 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. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax (2.3% for enhanced recovery) on the market value of oil production and a 7.5% severance tax on the market value of natural gas

production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of oil and natural gas that may be produced from our wells and the number of wells or locations the operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

Title to Properties

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties. 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. 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 for us, including the operation of our properties, and we may refer to individuals providing these services as our employees for ease of reference. 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 recognize that we are in a competitive marketplace when it comes to finding top talent. As a result, talent acquisition and the retention of employees continue to be a priority initiative for us. We strive to continue to attract, retain and motivate qualified employees by offering competitive compensation and benefits in an inclusive and safe workplace, with opportunities for our employees to grow and develop in their careers. Our employees may participate in a robust benefits program, which includes a focus on health and wellness, and we offer a variety of other employee perks.

As of December 31, 2025, Kimbell Operating had approximately 29 employees performing services for our operations and activities. Women represent approximately 34% of our workforce, and men represent approximately 66%. We 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.

Facilities

Our principal executive offices are located at 777 Taylor Street, Suite 810, Fort Worth, Texas 76102. We believe that our leased facilities are adequate for our current operations.

Additional Information

We electronically file various reports with the SEC including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The SEC maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com. 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.