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55f

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2025

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)	1311 (Primary Standard Industrial Classification Code Number)	47-5505475 (I.R.S. Employer Identification No.)

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945-9700

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Exchange Act:


Title of class	Trading Symbol	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	KRP	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Exchange Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. Yes ☐ No ☒

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 30, 2025, was $1.2 billion, based on the closing price of such common units of $13.96 as reported on the New York Stock Exchange on June 30, 2025. As of February 20, 2026, the registrant had outstanding 93,396,488 common units representing limited partner interests and 14,491,540 Class B units representing limited partner units.

Documents Incorporated by Reference: None

Table of Contents

Kimbell Royalty Partners, LP

TABLE OF CONTENTS



PART I
Item 1. Business	12
Item 1A. Risk Factors	33
Item 1B. Unresolved Staff Comments	65
Item 1C. Cybersecurity	65
Item 2. Properties	67
Item 3. Legal Proceedings	67
Item 4. Mine Safety Disclosures	67
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	68
Item 6. [Reserved]	71
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	71
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	85
Item 8. Financial Statements and Supplementary Data	89
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A. Controls and Procedures	90
Item 9B. Other Information	93
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	93

PART III
Item 10. Directors, Executive Officers and Corporate Governance	93
Item 11. Executive Compensation and Other Information	97
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	107
Item 13. Certain Relationships and Related Party Transactions, and Director Independence	111
Item 14. Principal Accounting Fees and Services	116
PART IV
Item 15. Exhibits, Financial Statement Schedules	116
Item 16. Form 10-K Summary	119
Signatures	120

Table of Contents

GLOSSARY OF TERMS

The following are definitions of certain terms used in this Annual Report on Form 10-K (“Annual Report”).

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil at the pressure and temperature base standard of each respective state in which the gas is produced.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

DUCs. Drilled but uncompleted wells.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Electrical log. Provide information on porosity, hydraulic conductivity and fluid content of formations drilled in fluid-filled boreholes.

Exploration. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves).

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Table of Contents

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

MBbl/d. MBbl per day.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.

Mcf. One thousand cubic feet of natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. One million British Thermal Units.

MMcf. One million cubic feet of natural gas.

Net acres. The sum of the fractional working interest owned in gross acres.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

Natural gas liquids or NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Nonparticipating royalty interest. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

Oil. Crude oil and condensate.

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Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. Refers to the operator of record and any lessor or working interest holder for which the operator is acting.

Overriding royalty interest or ORRI. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

Pad drilling. The practice of drilling multiple wellbores from a single surface location.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third party acreage that is pooled with our acreage.

Production costs. The production or operational costs incurred while extracting and producing, storing and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes and insurance.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.

Proved reserves. The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

SCOOP. South Central Oklahoma Oil Province.

Secondary recovery. The second stage of hydrocarbon production during which an external fluid, such as water or gas, is injected into the reservoir through injection wells located in rock that has fluid communication with production wells.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

STACK. Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties, Oklahoma.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

Tertiary recovery. Traditionally, the third stage of hydrocarbon production, comprising recovery methods that follow water flooding or pressure maintenance. The principal tertiary recovery techniques used are thermal methods, gas injection and chemical flooding.

Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.

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Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, of API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.

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Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Annual Report may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

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our ability to replace our reserves;

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our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;

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our ability to execute our business strategies;

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the volatility of realized prices for oil, natural gas and NGLs, including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;

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the level of production on our properties;

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the level of drilling and completion activity by the operators of our properties;

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our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire;

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regional supply and demand factors, delays or interruptions of production;

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industry, economic, business or political conditions, including the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies;

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trade policies and tensions, including changes in, or the imposition of, tariffs and/or trade barriers and the economic impacts, volatility and uncertainty resulting therefrom, which may have varying effects on commodity prices;

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the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine, the conflict in the Middle East and recent U.S. military action in Venezuela;

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revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;

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impacts of impairment expense on our financial statements;

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competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;

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the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;

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title defects in the properties in which we acquire an interest;

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the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel to the operators of our properties;

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restrictions on or the availability of the use of water in the business of the operators of our properties;

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the availability of transportation facilities;

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the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

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federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including regulation, proposals and executive orders focused on addressing climate change;

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future operating results;

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exploration and development drilling prospects, inventories, projects and programs;

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operating hazards faced by the operators of our properties;

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the ability of the operators of our properties to keep pace with technological advancements;

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uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions;

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our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures; and

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certain factors discussed elsewhere in this Annual Report.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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Summary of Risk Factors

Risks Related to Our Organization and Structure

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We may not have sufficient available cash to pay any quarterly distribution on our common units (defined below).

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Our cash flow may prevent us from paying cash distributions.

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The amount of our quarterly cash distributions, if any, is directly dependent on the performance of our business. We do not have a minimum quarterly distribution and could pay no distribution with respect to any particular quarter.

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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

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The limited liability company agreement of our General Partner (defined below) contains provisions that may restrict our ability to pursue our business strategies.

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Our General Partner and its affiliates, including our Sponsors (defined below) and their affiliates, have conflicts of interest with us and limited duties to us and our unitholders.

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Our partnership agreement does not restrict our Sponsors and their affiliates or the Contributing Parties (defined below) from competing with us.

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Our General Partner intends to limit its liability under contractual arrangements between us and third parties such that these third parties would not have recourse against our General Partner or its assets.

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Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating (defined below) to manage and operate, or arrange for the management and operation of, our business.

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Our partnership agreement restricts the remedies available to our unitholders for actions by our General Partner that might otherwise constitute breaches of fiduciary duty.

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Our partnership agreement replaces our General Partner’s fiduciary duties with contractual standards.

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Holders of our common units have limited voting rights and cannot elect our General Partner or its directors.

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Even if our unitholders are dissatisfied, they cannot remove our General Partner without its consent.

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Our partnership agreement restricts the voting rights of unitholders owning 20% or more of the interests in any class of our securities.

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Cost reimbursements due to our General Partner for services provided to us or on our behalf will reduce cash available for distribution.

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Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

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Our sole cash-generating asset is our membership interest in the Operating Company.

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Unitholders may have liability to repay distributions and may be personally liable for the obligations of the partnership.

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Increases in interest rates may cause the market price of our common units to decline.

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Our General Partner has a call right that may require unitholders to sell their units.

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We may issue additional common units and other equity interests ranking junior to the Series A preferred units without unitholder approval, which would dilute existing common unitholder ownership interests.

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There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.

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The market price of our common units could be materially adversely affected by sales of substantial amounts of our common units in the public or private markets.

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The price of our common units may fluctuate, and unitholders could lose their investment.

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The New York Stock Exchange (the “NYSE”) does not require a publicly traded partnership to comply with certain corporate governance requirements.

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Our partnership agreement includes exclusive forum, venue and jurisdiction provisions applicable to our unitholders.

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If a unitholder is an ineligible holder, the units of such unitholder may be subject to redemption.

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Our Series A preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

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The terms of our Series A preferred units contain covenants that may limit our business flexibility.

Risks Related to Economic Conditions and Our Industry

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Our revenues are derived from royalty payments that are based on the variable prices at which oil, natural gas and NGLs are sold.

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A deterioration in general economic, business or industry conditions would materially adversely affect our business.

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Conservation measures and technological advances could reduce demand for oil and natural gas.

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Intense competition in the oil and natural gas industry may adversely affect our operators.

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The results of exploratory drilling in shale plays will be subject to risks and may not meet our expectations for reserves or production.

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The marketability of oil and natural gas production is dependent upon transportation and other facilities.

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Drilling for and producing oil and natural gas are high-risk activities.

Risks Related to Our Indebtedness and Derivatives

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Our derivative activities could result in financial losses and reduce earnings.

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Restrictions in our secured revolving credit facility and future debt agreements could limit our growth or ability to pay distributions.

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Any significant reduction in our borrowing base under our secured revolving credit facility may negatively impact our ability to fund our operations.

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Our debt levels may limit our flexibility to obtain additional financing.

Risks Related to Our Operations

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Our business is difficult to evaluate because we have made several significant acquisitions.

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We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests.

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We may not be able to terminate our leases if any of the operators of our properties declare bankruptcy.

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Our success depends on replacing reserves through acquisitions and the development of our properties.

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Our failure to identify, complete and integrate acquisitions would slow our growth.

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Any acquisitions of additional mineral and royalty interests will be subject to substantial risks.

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If we are unable to make acquisitions on economically acceptable terms, our future growth will be limited.

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Prospect areas on our properties may not yield oil or natural gas in commercially viable quantities.

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Our estimated reserves are based on many assumptions that may prove to be inaccurate.

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We do not intend to retain cash from our operations for replacement capital expenditures.

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We rely on a few key individuals whose absence or loss could materially adversely affect our business.

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Loss of our or our operators’ information and computer systems could materially adversely affect our business.

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Title to the properties in which we have an interest may be impaired by title defects.

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The potential drilling locations of operators of our properties are susceptible to uncertainties.

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Acreage must be drilled before lease expiration in order to hold the acreage by production.

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The unavailability, high cost, or shortages of materials, equipment or personnel may result in increased costs for our operators.

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Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, which could materially adversely affect our business.

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If the operators of our properties suspend our right to receive royalty payments for any reason, our business may be adversely affected.

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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.

Tax Risks to Common Unitholders

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We may incur substantial income tax liabilities.

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Taxable gain or loss on the sale of our common units could be more or less than expected.

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Our tax liability may be greater than expected if we do not generate sufficient depletion deductions.

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Future tax legislation could have an adverse impact on our cash tax liabilities.

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Certain decreases in the price of our common units could adversely affect our cash available for distribution.

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The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income and failure to report your dividend income accurately may cause the IRS to assert audit adjustments.

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The portion of our distributions taxable as dividends may be greater than expected.

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If the Operating Company became a publicly traded partnership taxable as a corporation for United States federal income tax purposes, we and the Operating Company might be subject to potentially significant tax inefficiencies.

Legal, Environmental and Regulatory Risks

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Oil and natural gas operations are subject to various governmental laws and regulations, and compliance with such laws and regulations can be burdensome and expensive.

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The operators of our properties are subject to complex and evolving environmental and occupational health and safety laws and regulations that may cause delays or expenses that could materially adversely affect our business.

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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The adoption of climate change legislation and regulations could result in increased operating costs of our operators and reduced demand for oil and natural gas.

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Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

General Risk Factors

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Increased costs of capital could materially adversely affect our business.

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A terrorist attack or armed conflict could harm our business.

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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations.

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Ineffective internal controls could impact our business and operating results.

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PART I

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “our Partnership,” “we,” “our,” “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to our subsidiary Kimbell Royalty Operating, LLC. References to “our General Partner” refer to Kimbell Royalty GP, LLC. References to “our Sponsors” refer to affiliates of our founders, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to “Kimbell Holdings” refer to Kimbell GP Holdings, LLC, a jointly owned subsidiary of our Sponsors and the parent of our General Partner. References to the “Contributing Parties” refer to all entities and individuals, including affiliates of our Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to us at the closing of our initial public offering (“IPO”). References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of our General Partner, which has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties as described herein.

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. 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.

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

(1)	The Sponsors are affiliates of our founders, Messrs. 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.

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

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

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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.

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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:

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

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

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

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

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

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

Competitive Strengths

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

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

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

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

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

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

Our Properties

Material Basins and Producing Regions

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

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

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

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

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

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

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

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

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

Mineral Interests

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


	December 31, 2025
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Leased
Permian Basin (1)	3,072,785	23,336	99.1	%
Mid‑Continent	3,663,657	30,830	99.0	%
Terryville/Cotton Valley/Haynesville	1,301,662	6,725	99.6	%
Appalachian Basin (2)	434,116	16,968	99.8	%
Eagle Ford	476,193	5,059	96.8	%
Barnett Shale/Fort Worth Basin	316,408	3,548	99.1	%
Bakken/Williston Basin (3)	1,214,446	3,132	99.9	%
San Juan Basin	85,604	159	99.2	%
Onshore California	67,139	286	95.7	%
DJ Basin/Rockies/Niobrara	46,398	680	96.1	%
Illinois Basin	11,163	97	100.0	%
Other Western (onshore) Gulf Basin	614,310	4,247	98.0	%
Other TX/LA/MS Salt Basin	308,850	3,841	95.3	%
Other	677,085	3,306	99.1	%
Total (4)	12,289,816	102,214	99.0	%

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

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

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

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

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ORRIs

The following table sets forth information about our ORRIs:


	December 31, 2025
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Producing
Permian Basin (1)	333,243	4,465	100.0	%
Mid‑Continent	2,202,709	18,002	99.2	%
Terryville/Cotton Valley/Haynesville	127,245	1,194	99.6	%
Appalachian Basin (2)	307,238	6,235	100.0	%
Eagle Ford	147,955	1,671	100.0	%
Barnett Shale/Fort Worth Basin	76,755	593	100.0	%
Bakken/Williston Basin (3)	425,631	3,006	100.0	%
San Juan Basin	98,633	1,313	99.0	%
Onshore California	10,668	22	100.0	%
DJ Basin/Rockies/Niobrara	27,754	356	100.0	%
Illinois Basin	16,848	1,080	100.0	%
Other Western (onshore) Gulf Basin	89,209	1,215	100.0	%
Other TX/LA/MS Salt Basin	45,502	1,443	99.9	%
Other	814,386	15,544	100.0	%
Total (4)	4,723,776	56,139	99.6	%

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

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

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

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

Wells

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


Basin or Producing Region		December 31, 2025
Permian Basin		53,181
Mid‑Continent		21,181
Terryville/Cotton Valley/Haynesville		16,444
Appalachian Basin		3,994
Eagle Ford		4,645
Barnett Shale/Fort Worth Basin		5,949
Bakken/Williston Basin		5,708
San Juan Basin		1,907
Onshore California		975
DJ Basin/Rockies/Niobrara		12,641
Other		6,681
Total		133,306

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

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

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

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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:

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

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

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

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verification of property ownership by our land department.

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

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

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

Summary of Estimated Proved Reserves

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

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


	December 31,
	2025	2024	2023
Estimated proved developed reserves:
Oil (MBbls)	21,970	20,001	19,800
Natural gas (MMcf)	213,589	204,253	204,542
Natural gas liquids (MBbls)	15,376	13,498	11,519
Total (MBoe)(6:1) (1)	72,944	67,541	65,409

(1)

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

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

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Oil, Natural Gas and NGL Production and Pricing

Production and Price History

The following table sets forth information regarding our production of oil and natural gas and certain price and cost information for each of the periods indicated:


	Year Ended December 31,
	2025		2024		2023
Production Data:
Oil and condensate (Bbls)		3,061,920		2,836,913		2,392,622
Natural gas (Mcf)		26,733,988		27,586,460		23,384,021
Natural gas liquids (Bbls)		1,884,763		1,667,089		1,082,663
Total (Boe)(6:1) (1)		9,402,348		9,101,745		7,372,622
Average daily production (Boe/d)(6:1)		25,760		24,868		20,265
Average Realized Prices:
Oil and condensate (per Bbl)	$	63.84	$	75.98	$	76.55
Natural gas (per Mcf)	$	2.93	$	1.82	$	2.55
Natural gas liquids (per Bbl)	$	23.15	$	23.34	$	23.01
Average Unit Cost per Boe (6:1)
Production and ad valorem taxes	$	2.17	$	2.24	$	2.76

(1)	“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells. As of December 31, 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:


	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	5,304,977		61,790		5,366,767
Oklahoma	2,464,825		34,131		2,498,956
North Dakota	1,097,983		1,000		1,098,983
Wyoming	301,330		771		302,101
Kansas	608,320		2,001		610,321
Louisiana	618,711		1,045		619,756
Arkansas	407,848		1,218		409,066
Montana	165,955		5,059		171,014
New Mexico	211,391		3,146		214,537
Utah	144,053		—		144,053
Other	836,591		17,671		854,262
Total	12,161,984	(1)	127,832	(2)	12,289,816

(1)	Reflects mineral interests in approximately 12,161,984 total gross (92,454 net) developed acres.

(2)	Reflects mineral interests in approximately 127,832 total gross (9,760 net) undeveloped acres.

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ORRIs

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


	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	1,415,796		680		1,416,476
Oklahoma	1,346,251		16,440		1,362,691
North Dakota	419,177		—		419,177
Wyoming	350,846		—		350,846
Utah	235,432		—		235,432
Colorado	192,402		—		192,402
Pennsylvania	124,298		—		124,298
West Virginia	116,938		—		116,938
Louisiana	119,062		450		119,512
New Mexico	113,946		960		114,906
Other	271,074		24		271,098
Total	4,705,222	(1)	18,554	(2)	4,723,776

(1)	Reflects ORRIs in approximately 4,705,222 total gross (56,047 net) developed acres.

(2)	Reflects ORRIs in approximately 18,554 total gross (92 net) undeveloped acres.

Drilling Results

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

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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

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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 in Sackett. 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 in Sackett. 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.

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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

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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

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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

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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:

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the location of wells;

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the method of drilling and casing wells;

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the timing of construction or drilling activities, including seasonal wildlife closures;

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the rates of production or “allowables;”

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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notice to, and consultation with, surface owners and other third parties.

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

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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

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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.

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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.

Item 1A. Risk Factors

There are many factors that could have a material adverse effect on our operating results, financial condition and cash flows. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect financial performance. Each of the risks described below could adversely impact the value of our common units.

Risks Related to Our Organization and Structure

We may not have sufficient available cash to pay any quarterly distribution on our common units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. The holders of our Series A preferred units (to the extent of a distribution equal to 6.0% per annum plus accrued and unpaid distributions) and Class B units representing limited partnership interests in the Partnership (“Class B Units”) (to the extent of a distribution equal to 2.0% per quarter on such holder’s Class B Contribution (as defined below)) are entitled to receive quarterly cash distributions prior to distributions to holders of our common units. Substantially all of the cash we have to distribute each quarter depends upon the amount of oil, natural gas and NGL revenues we generate, which is dependent upon the prices that the operators of our properties realize from the sale of oil and natural gas production. 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.

The holders of our Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. In addition, each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B 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.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability, which may prevent us from paying cash distributions during periods when we record net income.

The amount of cash we have available for distribution to holders of our common units depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items such as impairment expense or unit-based compensation expense. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution to holders of our common units with respect to such quarter. 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.

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The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and is directly dependent on the performance of our business. We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could pay no distribution with respect to any particular quarter.

Our future business performance may be volatile, and our cash flows may be unstable. Please read “—All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.” We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy and Restrictions on Distributions.”

Furthermore, unlike other public companies, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (“replacement capital expenditures”). The Board of Directors may change our distribution policy and decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash each quarter. As a result, we will have limited cash available to reinvest in our business or to fund acquisitions, and we may rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. To the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. In addition, the incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our common unitholders.

We have funded a significant portion of the consideration paid in connection with many of our acquisitions with the issuance of equity securities, including common units and securities that are convertible or exchangeable into common units. There are no limitations in our partnership agreement on our ability to issue additional common units and, as a limited partnership, we are not required to seek unitholder approval for issuances of common units (including issuances in excess of 20% of our outstanding equity securities or issuances of equity to certain affiliates). 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.

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.

The limited liability company agreement of our General Partner, which is controlled by our Sponsors, contains provisions that prohibit certain actions without a supermajority vote of at least 66²/₃% of the members of the Board of Directors, including:

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the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;

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the reservation of a portion of cash generated from operations to finance acquisitions;

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modifications to the definition of “available cash” in our partnership agreement; and

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the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.

The Board of Directors is made up of seven members. Therefore, the vote of three directors would be sufficient to prevent us from undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that these restrictions impose on us. Our inability to execute financings or acquire additional properties may materially adversely affect our results of operations and cash available for distribution on common units.

Our General Partner and its affiliates, including our Sponsors and their respective affiliates, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsors and their respective affiliates, which are under no obligation to adopt a business strategy that favors us.

As of February 20, 2026, the owners of our Sponsors own or control up to an aggregate of approximately 2.5% of our outstanding common units and Class B units (or approximately 2.3% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner. Our General Partner has sole responsibility for conducting our business and managing our operations. Although our General Partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Conflicts of interest may arise between our Sponsors and their respective affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our General Partner may favor its own interests and the interests of its affiliates, including our Sponsors and their respective affiliates, over the interests of our unitholders. These conflicts include, among others, the following situations:

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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;

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our Sponsors may change their strategy or priorities in a way that is detrimental to our future growth and acquisition opportunities;

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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;

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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;

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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;

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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

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remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;

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except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;

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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;

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disputes may arise under agreements we have with our General Partner or its affiliates;

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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;

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our General Partner determines which costs incurred by it or its affiliates are reimbursable by us;

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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;

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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;

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our General Partner intends to limit its liability regarding our contractual and other obligations;

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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);

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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

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our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement does not restrict our Sponsors and their respective affiliates or the Contributing Parties from competing with us. Certain of our directors and officers may in the future spend significant time serving, and may have significant duties with, investment partnerships or other private entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Our partnership agreement provides that our General Partner is restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. Affiliates of our General Partner are not prohibited from owning projects or engaging in businesses that compete directly or indirectly with us. Similarly, our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us.

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Affiliates of our Sponsors currently hold interests in, and may make investments in and purchases of, entities that acquire and own mineral and royalty interests. In addition, certain of our officers and directors, including the individuals who control our Sponsors, may in the future hold similar positions with investment partnerships or other private entities that are in the business of identifying and acquiring mineral and royalty interests. In such capacities, these individuals would likely devote significant time to such other businesses and would be compensated by such other businesses for the services rendered to them. The positions of these directors and officers may give rise to duties that are in conflict with duties owed to us. In addition, these individuals may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these potential future affiliations, they may have duties to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. Our Sponsors and their respective affiliates are under no obligation to make any acquisition opportunities available to us, except as provided for under the contribution agreement entered into in connection with our IPO.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers and directors, our Sponsors and their respective affiliates or the Contributing Parties. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us does not have any duty to communicate or offer such opportunity to us. Any such person or entity is not liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and holders of our units.

Our General Partner intends to limit its liability regarding our obligations.

Our General Partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our partnership agreement permits our General Partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. 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. The management team of Kimbell Operating, which includes the individuals who will manage us, also provides substantially similar services to other entities and thus is not solely focused on our business.

Neither we, our General Partner nor our subsidiaries have any employees, and we rely solely on Kimbell Operating to manage us and operate our assets. 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.

Kimbell Operating also provides substantially similar services and personnel to other entities, including certain of the Contributing Parties, and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Kimbell Operating may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of other entities or other affiliates of our General Partner. There is no requirement that Kimbell Operating favor us over these other entities in providing its services. If the employees of Kimbell Operating do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to our unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

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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;

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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;

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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

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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:

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approved by the conflicts committee of the Board of Directors, although our General Partner is not obligated to seek such approval;

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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;

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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

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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.

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. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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Our partnership agreement replaces our General Partner’s fiduciary duties to our unitholders with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:

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how to allocate corporate opportunities among us and its other affiliates;

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whether to exercise its limited call right;

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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors or by the unitholders;

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how to exercise its voting rights with respect to the units it owns;

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whether to sell or otherwise dispose of any units or other partnership interests it owns; and

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whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By acquiring an interest in us, a limited partner agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right on an annual or ongoing basis to elect our General Partner or its Board of Directors. The Board of Directors, including the independent directors, is chosen entirely by our Sponsors, as a result of such Sponsors controlling our General Partner, and not by our unitholders. Please read “Item 13. 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. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if our unitholders are dissatisfied, they cannot initially remove our General Partner without its consent.

If our unitholders are dissatisfied with the performance of our General Partner, they will have limited ability to remove our General Partner. 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 66²/₃% of all outstanding units (including common units and Class B units held by the General Partner and its affiliates).

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of the interests in any class of our securities, subject to certain exceptions.

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

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Board of Directors, holders of Series A preferred units in connection with any vote, consent or approval of holders of the Series A preferred units, voting as a separate class or on an as-converted basis with the holders of common units, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units or any conversion of the Series A preferred units at our option, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our unitholders to influence the manner or direction of management.

Cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. Our partnership agreement and the limited liability company agreement of the Operating Company do not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to paying any distribution on our common units, we will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all expenses they incur and payments they make on our behalf. Our partnership agreement and limited liability company agreement of the Operating Company do not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our partnership agreement and the limited liability company agreement of the Operating Company provide that our General Partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our General Partner and its affiliates will reduce the amount of cash available for distribution to our common unitholders. Please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities— Cash Distribution Policy and Restrictions on Distributions.”

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. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to our common unitholders. 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—Management Services Agreements.”

Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

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. After any such transfer, the new member or members of our General Partner would then be in a position to replace the Board of Directors and executive officers of our General Partner with its own designees and thereby exert significant control over the decisions taken by the Board of Directors and executive officers of our General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

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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.

We are a holding company, and we have no material assets other than our membership interest in the Operating Company. We have no independent means of generating revenue. To the extent the Operating Company has available cash, we intend to cause the Operating Company to make distributions to its unitholders, including us, in an amount sufficient to cover all applicable taxes at assumed tax rates, to reimburse us for our expenses and to allow us to make distributions to our unitholders. To the extent that we need funds and the Operating Company is restricted from making such distributions under applicable law or regulation or under the terms of any financing arrangements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not pay a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our General Partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our General Partner if a limited partner were to lose limited liability through any fault of our General Partner.

Increases in interest rates may cause the market price of our common units to decline.

The recent increases in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline. A global economic slowdown or recession and macroeconomic trends (such as higher inflation, volatility in the financial markets, increasing interest rates and currency rate fluctuations) may also result in unfavorable impact to the trading price of our common units.

Our General Partner has a call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our General Partner and its affiliates (including our Sponsors and their respective affiliates) own more than 80% of the sum of the number of our common units then outstanding and the number of Class B units then outstanding, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units and Class B units (being treated as a single class of units) held by unaffiliated persons at a price not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement. As a result, unitholders may be required to sell their common units or Class B units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. 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. 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. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

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Under our partnership agreement, we are authorized, without the vote of unitholders, to issue an unlimited number of additional 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, rank junior to the Series A preferred units. The issuance of additional partnership interests that rank equal to or senior to the Series A preferred units requires the consent of the holders of 66²/₃% of the outstanding Series A preferred units. The terms of our partnership agreement and the limited liability company agreement of the Operating Company also authorize us and it to issue an unlimited number of Class B units and OpCo common units, respectively, which are together exchangeable on a one-for-one basis into common units. The issuance by us of additional common units or other equity interests of equal or senior rank to the common units would have the following effects:

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the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;

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the amount of cash distributions on each common unit may decrease;

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the ratio of our taxable income to distributions may increase;

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the relative voting strength of each previously outstanding common unit may be diminished; and

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the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior in right of distributions or liquidation to our common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that rank senior in right of distributions, liquidation or voting to our common units. In prior years, we have issued preferred units that ranked senior in right of distributions and liquidation to our common units, and we may issue senior partnership interests again in the future. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be materially adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our Sponsors, the Contributing Parties and other selling unitholders pursuant to any registration rights agreements.

As of December 31, 2025, we had 93,396,488 common units outstanding and 14,491,540 Class B units outstanding. Our Class B units are exchangeable on a one-for-one basis, together with an equal number of common units of the Operating Company (“OpCo common units”), for common units. In addition, our Series A preferred units may be converted into common units at the then-applicable conversion rate.

A large percentage of our equity securities, including securities that are convertible or exchangeable into common units, are held by a relatively limited number of investors. Further, we have entered into registration rights agreements with many of such investors, pursuant to which we have filed registration statements with the SEC to facilitate potential future sales of such common units by them. 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.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

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changes in commodity prices;

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public reaction to our press releases, announcements and filings with the SEC;

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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;

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changes in market valuations of similar companies;

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departures of key personnel;

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commencement of or involvement in litigation;

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variations in our quarterly results of operations or those of other oil and natural gas companies;

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changes in general economic conditions, financial markets or the oil and natural gas industry;

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announcements by us or our competitors of significant acquisitions or other transactions;

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variations in the amount of our quarterly cash distributions to our unitholders;

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changes in accounting standards, policies, guidance, interpretations or principles;

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the failure of securities analysts to cover our common units or changes in their recommendations and estimates of our financial performance;

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future sales of our common units; and

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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.

Because we are a publicly traded partnership, the NYSE does not require us to have, and we do not have, a majority of independent directors on our Board of Directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Item 10. Directors, Executive Officers and Corporate Governance.”

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. 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.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. 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.

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. Ineligible holders are limited partners whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our General Partner with the advice of counsel. If a unitholder is an ineligible holder, in certain circumstances as set forth in our partnership agreement, the units held by

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such unitholder may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

Our Series A preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

On September 13, 2023, we issued 325,000 preferred units representing limited partner interests in the Partnership. On May 7, 2025, we completed the redemption of 162,500 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. Our Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

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. 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. If we make such an election in consecutive quarters or if we fail to pay in full, in cash and when due, any distribution owed to the Series A preferred units 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 in full in cash, or any such material breach is cured, as applicable. 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. We cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of our common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions. Our obligation to pay distributions on our Series A preferred units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general partnership purposes. Our obligations to the holders of the Series A preferred units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

The terms of our Series A preferred units contain covenants that may limit our business flexibility.

The terms of our Series A preferred units contain covenants preventing us from taking certain actions without the approval of the holders of 66²/₃% of the outstanding Series A preferred units, voting separately as a class. The need to obtain the approval of holders of the Series A preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our common unitholders.

The affirmative vote of 66²/₃% of the outstanding Series A preferred units, voting separately as a class, will be necessary to amend our partnership agreement in any manner that is materially adverse to any of the rights, preferences and privileges of the Series A preferred units. The affirmative vote of 66²/₃% 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.

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Risks Related to Economic Conditions and Our Industry

All of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and NGLs produced from the acreage underlying our interests is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, results of operations and cash available for distribution on common units.

Our revenues, operating results, cash available for distribution on common units and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil, natural gas and NGLs. 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:

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the domestic and foreign supply of and demand for oil, natural gas and NGLs;

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the level of prices and expectations about future prices of oil, natural gas and NGLs;

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the level of global oil and natural gas exploration and production;

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the cost of exploring for, developing, producing and delivering oil and natural gas;

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the price and quantity of foreign imports;

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the level of United States domestic production;

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political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;

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the ability of members of the OPEC to agree to and maintain oil price and production controls;

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the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions;

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speculative trading in crude oil, natural gas and NGL derivative contracts;

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the level of consumer product demand;

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weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change;

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risks associated with operating drilling rigs;

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technological advances affecting energy consumption;

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domestic and foreign governmental regulations and taxes;

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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;

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the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;

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the price and availability of alternative fuels; and

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overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for WTI, has ranged

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from a low of $47.47 per Bbl in January 2021 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. On December 31, 2025, the WTI posted price for crude oil was $57.26 per Bbl and the Henry Hub spot market price of natural gas was $4.00 per MMBtu. On February 17, 2026, the WTI posted price for crude oil was $62.53 per Bbl and the Henry Hub spot market price of natural gas was $3.13 per MMBtu. Reductions in prices can be caused by many factors, including increases in oil and natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand, as well as actions by the OPEC to maintain or raise production levels. This environment could cause prices to remain at current levels or to fall to lower levels.

Any substantial decline in the price of oil, natural gas and NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. 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. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and cash available for distribution on common units.

Concerns over global economic conditions, higher interest rates, supply chain constraints, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States can contribute to economic uncertainty and diminish expectations for the global economy. In addition, consequences associated with the ongoing invasion of Ukraine by Russia, the conflict in the Middle East, recent U.S. military action in Venezuela and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. 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. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which oil, natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash available for distribution on common units.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.

Competition in the oil and natural gas industry is intense, which may adversely affect our operators’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry

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on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our operators’ larger competitors have substantially greater financial and technological resources and may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

We also compete with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face increasing competition due to the development and adoption of new technologies and incentives granted to develop such technologies.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

The operators of our properties may use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. Certain of the new techniques that the operators of our properties may adopt, such as horizontal drilling, infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. 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. Newer or emerging formations and areas often have limited or no production history and consequently the operators of our properties will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties because of capital constraints, lease expirations, access to gathering systems or declines in oil and natural gas prices, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash available for distribution on common units could be materially adversely affected.

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators’ operations could be interrupted and our results of operations and cash available for distribution on common units could be materially adversely affected.

The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor the operators of our properties control these third party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. 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.

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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.

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. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

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unusual or unexpected geological formations;

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loss of drilling fluid circulation;

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title problems;

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facility or equipment malfunctions;

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unexpected operational events;

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shortages or delivery delays of equipment and services;

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compliance with environmental and other governmental requirements; and

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adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash available for distribution to our common unitholders may be materially adversely affected.

Risks Related to Our Indebtedness and Derivatives

Our derivative activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars and basis swaps. We have not designated and do not plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:

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production is less than expected;

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the counterparty to the derivative contract defaults on its contract obligation; or

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the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

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In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.

Restrictions in our secured revolving credit facility and future debt agreements could limit our growth and our ability to engage in certain activities, including our ability to pay distributions to our unitholders.

Our secured revolving credit facility has commitments up to $625.0 million. Our secured revolving credit facility is secured by substantially all of our assets. Our secured revolving credit facility contains various covenants and restrictive provisions that limit our ability to, among other things:

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incur or guarantee additional debt;

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make distributions on, or redeem or repurchase, common units, including if an event of default or borrowing base deficiency exists;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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transfer, sell or otherwise dispose of assets.

Our secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 3.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. Our ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise or paying distributions to our common unitholders or OpCo common unitholders because of the limitations that the restrictive covenants under our secured revolving credit facility impose on us. For example, our secured revolving credit facility restricts us from paying distributions to our common unitholders and OpCo common unitholders if our Debt to EBITDAX Ratio exceeds 3.0 to 1.0 on a trailing twelve-month basis.

A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Our secured revolving credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.”

Any significant reduction in our borrowing base under our secured revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our secured revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base is determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We have non-wholly owned subsidiaries whose assets are not subject to a lien and not included in borrowing base valuations. 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. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the

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available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other oil and natural gas properties as additional collateral after applicable grace periods. We do not have substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our secured revolving credit facility.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

As of December 31, 2025, we had approximately $441.5 million in borrowings outstanding under our senior secured credit facility. Our existing and any future indebtedness could have important consequences to us, including:

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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;

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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;

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our access to the capital markets may be limited;

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our borrowing costs may increase;

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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

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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 ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Risks Related to Our Operations

Our business is difficult to evaluate because we have made several significant acquisitions.

We have grown our business primarily through acquisitions, which have significantly expanded our portfolio of mineral and royalty interests. We do not have historical financial statements with respect to our mineral and royalty interests for periods prior to their acquisition by the respective sellers. As a result, with respect to many of our assets, including any assets that we may acquire in the future, there is, or may be, only limited historical financial information available upon which to base an evaluation of our performance.

We depend on unaffiliated operators for all of the exploration, development and production on the properties in which we own mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on the acreage underlying our interests by these operators or the failure of these operators to adequately and efficiently develop and operate the underlying acreage could materially adversely affect our results of operations and cash available for distribution on common units.

Because we depend on our third party operators for all of the exploration, development and production on our properties, we have no control over the operations related to our properties. As of December 31, 2025, we received revenue from approximately 1,300 operators and we received approximately 47.1% of revenues from the top ten purchasers of our properties. During the year ended December 31, 2025, payments we received from our top purchaser accounted for

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approximately 7.7% of our revenues. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law). The operators of our properties could determine to drill and complete fewer wells on our acreage than we currently expect. 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:

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the capital costs required for drilling activities by the operators of our properties, which could be significantly more than anticipated;

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the ability of the operators of our properties to access capital;

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prevailing commodity prices;

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the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

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the operators’ expertise, operating efficiency and financial resources;

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approval of other participants in drilling wells;

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the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

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the selection of technology;

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the selection of counterparties for the marketing and sale of production; and

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the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our oil, natural gas and NGL revenues and cash available for distribution on common units. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us. Sustained reductions in production by the operators of our properties may also materially adversely affect our results of operations and cash available for distribution on common units.

We may not be able to terminate our leases if any of the operators of the properties in which we own mineral interests declare bankruptcy, and we may experience delays and be unable to replace operators that do not make royalty payments.

A failure on the part of the operators of the properties in which we own mineral interests to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of the properties in which we own mineral interests, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to bankruptcy proceedings that could prevent the execution of a new lease or the assignment of the existing lease to another operator. In addition, if we enter into a new lease, the replacement operator may not achieve the same levels of production or sell oil, natural gas or NGLs at the same price as the operator it replaced.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of the operators of our properties.

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. Because we depend on our third party operators for all of the exploration, development and

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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. 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.

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. The successful acquisition of properties requires an assessment of several factors, including:

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recoverable reserves;

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future oil, natural gas and NGL prices and their applicable differentials;

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development plans;

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operating costs; and

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. 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. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. 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.

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Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:

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the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures and production costs;

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a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

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a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

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the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

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mistaken assumptions about the overall cost of equity or debt;

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our inability to obtain satisfactory title to the assets we acquire;

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our inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

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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.

In addition, we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire. The services to be provided under such transition services agreements may not be performed timely and effectively, and any significant disruption in such transition services or unanticipated costs related to such services could adversely affect our business and results of operations.

If we are unable to make acquisitions on economically acceptable terms from our Sponsors, the Contributing Parties or third parties, our future growth will be limited.

Our ability to grow depends in part on our ability to make acquisitions that increase our cash generated from our mineral and royalty interests. The acquisition component of our strategy is based, in large part, on our expectation of ongoing acquisitions from industry participants, including our Sponsors and the Contributing Parties. There can be no assurance that, should the Contributing Parties choose to sell any additional mineral and royalty interests, any offer will be made to us, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities. Furthermore, many factors could impair our access to future acquisitions, including a change in control of any of our Sponsors and the Contributing Parties. 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.

Prospect areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations and cash available for distribution on common units may be materially adversely affected.

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Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove to be incorrect.

Our historical estimates of proved reserves and related valuations as of December 31, 2025, 2024 and 2023 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us. 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. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the “FASB”), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

We do not intend to retain cash from our operations for replacement capital expenditures. Unless we replenish our oil and natural gas reserves, our cash generated from operations and our ability to pay distributions to our unitholders could be materially adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our oil and natural gas reserves and the operators’ production thereof and our cash generated from operations and ability to pay distributions are highly dependent on the successful development and exploitation of our current reserves. As of December 31, 2025, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 13.5%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also 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 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 do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells.

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Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain or grow our asset base, we would expect to reduce our distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of the unitholders’ investment in us as opposed to a return on the unitholders’ investment.

We rely on a few key individuals whose absence or loss could materially adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on our founders for their knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with certain entities controlled by affiliates of certain of our Sponsors, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services agreements, affiliates of certain of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. 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. As a result, we are not insured against any losses resulting from the death of these key individuals.

Loss of our or our operators’ information and computer systems could materially adversely affect our business.

We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third party service providers are not adequately functioning, we could experience loss of important data. Any of the foregoing consequences could materially adversely affect our business.

Title to the properties in which we have an interest may be impaired by title defects.

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. Rather, we may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and cash available for distribution on common units. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The potential drilling locations identified by the operators of our properties are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of the operators of our properties to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. 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. The use of technologies and the study of producing fields in the same area will not enable the operators of our properties to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, the operators of our properties may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or

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abandonment of the well. If the operators of our properties drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure our unitholders that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. 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. Our operators’ failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. If our royalties are derived from mineral interests and production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. Any such losses of our operators or lessees could materially and adversely affect the growth of our financial condition, results of operations and cash available for distribution on common units.

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, the operators of our properties rely on independent third party service providers to provide many of the services and equipment necessary to drill new wells. If the operators of our properties are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs, and the operator of those rigs may choose to cease providing services to them. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

Operating hazards and uninsured risks may result in substantial losses to the operators of our properties, and any losses could materially adversely affect our results of operations and cash available for distribution on common units.

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. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

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If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash available for distribution on common units may be adversely affected.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, and in subsequent acquisitions, record title to a significant amount of the acquired mineral and royalty interests was conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries became the record owner of these interests. Upon such a change in ownership, and at regular intervals pursuant to routine audit procedures at each of our operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. 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. Certain of our operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests are placed in suspense, our quarterly distribution may be reduced significantly. With each acquisition, we expect the risk of payment suspense to be greatest during the immediately succeeding fiscal quarters due to the number of title transfers that will take place.

Accounting standards require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.

We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025. We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million for the years ended December 31, 2024 and 2023, respectively, as a result of the decline in oil and natural gas prices.

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Tax Risks to Common Unitholders

We may incur substantial income tax liabilities on our allocable share of income from the Operating Company.

We are classified as a corporation for United States federal income tax purposes and for state income tax purposes in most states in which we do business. Current law provides that we are subject to federal income tax on our taxable income at the United States corporate tax rate, which is currently 21.0%, and to state income tax at rates that vary from state to state. The amount of cash available for distribution to you will be reduced by the amount of any such income taxes payable by us.

Taxable gain or loss on the sale of our common units could be more or less than expected.

A holder of common units generally will recognize capital gain or loss on a sale, an exchange, certain redemptions, or other taxable dispositions of our common units equal to the difference, if any, between the amount realized upon the disposition of such common units and the holder’s adjusted tax basis in those units. To the extent that the amount of our distributions exceeds our current and accumulated earnings and profits, the distributions will be treated as a tax-free return of capital and will reduce a holder’s tax basis in the common units. Because our distributions in excess of our earnings and profits decrease a holder’s tax basis in the common units, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the common units.

Our tax liability may be greater than expected if we do not generate sufficient depletion deductions to offset our taxable income and reduce our tax liability.

We expect to generate depletion deductions that we can use to offset our taxable income; however, there is no guarantee that we will not have any taxable income as a result of our equity interests in the Operating Company. 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.

While we expect that our depletion deductions will be available to us as a benefit, in the event that the depletion deductions are not available as expected, are successfully challenged by the Internal Revenue Service (“IRS”) (in a tax audit or otherwise) or are subject to future limitations, our ability to realize these benefits may be limited. Further, the IRS or other tax authorities could challenge one or more tax positions we or the Operating Company take. Further, any change in law may affect our tax positions.

Future tax legislation could have an adverse impact on our cash tax liabilities, results of operations and financial condition, which could affect our cash available for distribution on common units and the value of our common units.

Changes in federal income tax law relating to our tax treatment could result in (i) 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 and (ii) a greater portion of our distributions being treated as taxable dividends. Congress could, in the future, enact tax law changes, such as increasing the corporate tax rate or reducing or eliminating certain tax preferences currently available with respect to production of oil and gas. We are unable to predict whether any such changes will be enacted, but any such changes could have a material impact on our cash tax liabilities, results of operations or financial condition. Moreover, we are subject to tax in numerous jurisdictions. Changes in current law in these jurisdictions could result in our being subject to additional taxation at the entity level with the result that we would have less cash available for distribution on common units.

Certain decreases in the price of our common units could adversely affect our amount of cash available for distribution on common units.

Changes in certain market conditions may cause the price of our common units to decrease. If holders of our OpCo common units and Class B units exercise their right to exchange those units for common units at a point in time when the price of our common units is relatively low, the ratio of our income tax deductions to gross income could decline. Any resulting decline in the ratio of our income tax deductions to gross income could result in our being subject to tax

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sooner than expected, our tax liability being greater than expected or a greater portion of our distributions being treated as taxable dividends.

The IRS Form 1099-DIV that you receive from your broker may over-report your dividend income with respect to our units for United States federal income tax purposes, and failure to report your dividend income in a manner consistent with the IRS Form 1099-DIV that you receive from your broker may cause the IRS to assert audit adjustments to your United States federal income tax return.

Distributions we pay with respect to our units constitute “dividends” for United States federal income tax purposes to the extent of our current and accumulated earnings and profits. 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 you are a holder of our common units, the IRS Form 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” to you for United States federal income tax purposes or you may receive a corrected IRS Form 1099-DIV (and you may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify you of available information to assist you with your income tax reporting (such as posting the correct information on our website). 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.

If we make distributions from current or accumulated earnings and profits as computed for United States federal income tax purposes, such distributions will generally be taxable to our common unitholders as dividend income for United States federal income tax purposes. Under current law, distributions paid to non-corporate United States common unitholders will be subject to United States federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. It is difficult to predict whether we will generate earnings and profits in any given tax year. Although we expect that a significant portion of our distributions to common unitholders will exceed our current and accumulated earnings and profits as computed for United States federal income tax purposes, and therefore constitute a non-taxable return of capital to each unitholder to the extent of such unitholder’s basis in its common units, this may not occur. In addition, although distributions treated as a return of capital are generally non-taxable to the extent of a unitholder’s basis in its common units, such distributions will reduce such unitholder’s adjusted tax basis in its common units, which will result in an increase in the amount of gain (or a decrease in the amount of loss) that will be recognized by the unitholder on a future disposition of our common units, and to the extent any such distribution exceeds a unitholder’s basis in its common units, such distribution will be treated as gain on the sale or exchange of such common units.

If the Operating Company were to become a publicly traded partnership taxable as a corporation for United States federal income tax purposes, we and the Operating Company might be subject to potentially significant tax inefficiencies.

We intend to operate such that the Operating Company does not become a publicly traded partnership taxable as a corporation for United States federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, it is possible that certain exchanges of the OpCo common units could cause the Operating Company to be treated as a publicly traded partnership. Applicable United States Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges of the OpCo common units qualify for one or more such safe harbors. If the Operating Company were to become a publicly traded partnership taxable as a corporation for United States federal income tax purposes, significant tax inefficiencies might result for us and for the Operating Company including as a result of our inability to file a consolidated United States federal income tax return with the Operating Company. In addition, we would no longer have the benefit of increases in the tax bases of the Operating Company’s assets.

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Legal, Environmental and Regulatory Risks

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce our cash available for distribution on common units.

Operations on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, discharges or releases of pollutants or wastes and production and conservation matters (discussed in more detail below). From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days. In addition, President Biden issued certain Executive Orders focused on addressing climate change, which, among other things, directed the Secretary of the Interior to pause entering into new oil and natural gas leases on public lands or offshore waters “to the extent possible” pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In addition, some states have taken legal measures to restrict new oil and gas leases on state lands or to otherwise challenge new oil and gas development, including through restriction or prohibition of hydraulic fracturing in certain circumstances. In January 2025, President Trump issued certain Executive Orders directing federal agencies to facilitate the identification, leasing, siting, production, transportation, refining, and generation of domestic energy resources, including, but not limited to, on federal lands, and to expedite completion of infrastructure, energy, environmental and natural resources projects that fall under their purview. Potential legal challenges to President Trump’s Executive Orders, or other contrary actions by state or local agencies, 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.

In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and safety and the environment. Failure to comply with these laws and regulations by the operators of our properties may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of their operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management.

Laws and regulations governing exploration and production may also affect production levels. The operators of our properties must comply with federal and state laws and regulations governing conservation matters, including:

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provisions related to the unitization or pooling of the oil and natural gas properties;

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the establishment of maximum rates of production from wells;

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the spacing of wells;

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the plugging and abandonment of wells; and

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the removal of related production equipment.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital costs on the part of our operators and third party downstream natural gas transporters associated with production from our properties.

The operators of our properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

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The operators of our properties may be required to make significant expenditures to comply with the governmental laws and regulations described above and are subject to potential fines and penalties if they are found to have violated these laws and regulations. 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. As a result, they may incur significant delays, costs and liabilities that could materially adversely affect our business and financial condition.

The operators of our properties may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety laws and regulations applicable to their exploration, development and production activities on our properties. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety. These laws, regulations and enforcement policies have become increasingly strict over time, resulting in longer waiting periods to receive permits and other regulatory approvals, and we believe this trend will continue. 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).

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Additionally, actions taken by federal or state agencies under these laws and regulations, such as the designation of previously unprotected species as being endangered or threatened or the designation of previously unprotected areas as a critical habitat for such species, can cause the operators of our properties to incur additional costs or become subject to operating restrictions.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause the operators of our properties to become liable for the conduct of others or for consequences of our operators’ actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of operations by the operators of our properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities, significantly increase our operating or compliance costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business. If the operators of our properties are not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be materially and adversely affected. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The operators of our properties use hydraulic fracturing for the completion of their wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the wellbore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. If the operators of our properties are unable to obtain water to use in their

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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.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that hydraulic fracturing activities can impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical integrity of wells. These and other ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for the operators of our properties to perform fracturing and increase the costs of compliance and doing business. Additional legislation or regulation could also make it easier for 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. There has also been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, the use of water and the potential for impacts to surface water, groundwater and the environment generally. The imposition of stringent new regulatory and permitting requirements related to the practice of hydraulic fracturing could significantly increase our cost of doing business, could create adverse effects on our operators, including creating delays related to the issuance of permits and, depending on the specifics of any particular proposal that is enacted, could be material.

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. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and 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. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

The adoption of climate change legislation and regulations could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.

Climate change and sustainability and other environmental considerations are a growing global concern with increasing focus from the public, investors and other stakeholders. In 2009, the EPA found that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment. Relying on this finding, referred to as the 2009 Endangerment Finding, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore oil and natural gas production sources in the United States on an annual basis, which include operations on certain of our properties. 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. Potential legal challenges to EPA’s rescission of the 2009 Endangerment Finding, or the imposition of additional regulatory burden on oil and gas development by state or local agencies in response to EPA’s repeal of federal GHG regulations, could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties.

During his presidency, President Biden issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In his current presidential term, President Trump has reversed many

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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. Potential legal challenges to President Trump’s Executive Orders, imposition of additional regulatory burden on oil and gas development by state or local agencies, or any expansion of federal climate regulations could increase the costs of development and production, reducing the profits available to us and potentially impairing our operator’s ability to economically develop our properties. Please read “Item 1. Business—Regulation” for a description of the laws and regulations that affect the operators of our properties and that may affect us.

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. For example, 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 line with a June 2017 announcement from President Trump, the United States withdrew from the Paris Agreement in November 2020. However, on January 20, 2021, President Biden signed an instrument that reversed this withdrawal, and the United States formally re-joined the Paris Agreement on February 19, 2021. 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 COP26. During more recent COP meetings, including COP26, multiple efforts (not having the effect of law) were announced, including a call for countries to eliminate certain fossil fuel subsidies and pursue further action to reduce non-carbon dioxide GHG emissions. 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. 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. Initiatives to implement pledges made at COP meetings, the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.

Congress has from time to time considered legislation to reduce emissions of GHGs and may consider adopting legislation to reduce GHG emissions at the federal level in the coming years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties. 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.

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 for operators to engage in exploration and production activities.

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Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Several recent tariff announcements by the U.S. federal government have been followed by announcements of limited exemptions and temporary pauses. These actions are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods and commodities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

General Risk Factors

Increased costs of capital could materially adversely affect our business.

Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities and place us at a competitive disadvantage. Certain institutional lenders who provide financing to oil and gas companies have become more attentive to sustainable lending practices and some of them may substantially reduce, or elect not to provide, funding for oil and gas companies. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available for distribution on common units.

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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.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. For example, the oil and natural gas industry depends on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with customers, employees and third party partners. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The United States government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. 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, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Our systems for protecting against cyber security risks may not be sufficient. Further, as cyber-attacks continue to evolve, including by state actors or other abroad, we or our service providers, who we are generally obligated to reimburse for costs incurred in connection with the provision of their services to us, may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. 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.

Ineffective internal controls could impact our business and operating results.

Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, failure or interruption of information technology systems, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and operating results could be harmed and we could fail to meet our financial reporting obligations.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Risk Management and Strategy

We have established policies and processes for assessing, identifying, and managing material risk from cybersecurity threats. Our processes for assessing, identifying, and managing material risks from cybersecurity threats have been integrated into our overall risk management system and processes.

Our privacy and cybersecurity policies encompass incident response procedures, information security and operator management. In order to help develop these policies and procedures, we monitor the privacy and cybersecurity

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laws, regulations and guidance applicable to us, as well as proposed privacy and cybersecurity laws, regulations, guidance and emerging risks.

We conduct periodic risk assessments to identify cybersecurity threats, as well as assessments in the event of a material change in our business practices that may affect information systems that are vulnerable to such cybersecurity threats. These risk assessments include identification of reasonably foreseeable internal and external risks, software which helps identify potential weaknesses in our systems, the likelihood and potential damage that could result from such risks, and the sufficiency of existing policies, procedures, systems, and safeguards in place to manage such risks.

We continually monitor our network and firewall for security weaknesses using third party applications and we perform external penetration testing which is performed by a third party consultant on an annual basis. In total, we engage third parties in connection with our risk assessment processes. These service providers work closely with our team and our managed service providers to assist us to design and implement our cybersecurity policies and procedures, as well as to monitor and test our safeguards.

We require each third-party service provider to certify that it has the ability to implement and maintain appropriate security measures, consistent with all applicable laws, to implement and maintain reasonable security measures in connection with their work with us, and to promptly report any suspected breach of its security measures that may affect our company.

As described in Item 1A “Risk Factors,” our operations rely on the secure processing, storage and transmission of confidential and other information in our computer systems and networks. Computer viruses, hackers, or employee misconduct and other external hazards could expose our information systems to security breaches, cybersecurity incidents or other disruptions, any of which could materially and adversely affect our business. If any of such programs or systems were to fail 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.

While we have experienced cybersecurity incidents, to date, we are not aware that we have experienced a material cybersecurity incident during the 2025 fiscal year.

The sophistication of cybersecurity threats, including through the use of artificial intelligence, continues to increase, and the controls and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems, including the regular testing of our cybersecurity incident response plan, may be insufficient. In addition, new technology that could result in greater operational efficiency may further expose our computer systems to the risk of cybersecurity incidents.

Governance

As part of our overall risk management approach, we prioritize the identification and management of cybersecurity risk at several levels, including oversight from our Board of Directors, executive commitment and employee training. Our Audit Committee, comprised of independent directors from our Board of Directors, oversees the Board’s responsibilities relating to the operational (including information technology (IT) risks, business continuity and data security) risk affairs of the Partnership.

Our Chief Operating Officer and Security Officer/Director of IT are primarily responsible for assessing and managing our material risks from cybersecurity threats with assistance from third-party service providers.

Our Chief Operating Officer and Security Officer/Director of IT oversee our cybersecurity policies and processes, including those described in “Risk Management and Strategy” above. The cybersecurity risk management program includes tools and activities to prevent, detect, and analyze current and emerging cybersecurity threats, and plans and strategies to address threats and incidents.

Our Security Officer/Director of IT provide periodic briefings to the audit committee regarding the Partnership’s cybersecurity risks and activities, including any recent cybersecurity incidents and related responses, cybersecurity systems

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testing, activities of third parties, and the like. Our audit committee provides regular updates to the board of directors on such reports.

At the employee level, we maintain an experienced information technology team who are tasked with implementing our privacy and cybersecurity program and support the Chief Operating Officer and Security Officer/Director of IT in carrying out reporting, security and mitigation functions. We also hold employee trainings on privacy and cybersecurity, records and information management, conduct phishing tests and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population.

Item 2. Properties

The information required by Item 2 is contained in “Item 1. Business,” and such information is incorporated into this Item 2 by reference herein.

Item 3. Legal Proceedings

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

Items 4. Mine Safety Disclosures

Not applicable.

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Part II

Our common units are listed on the NYSE under the symbol “KRP.” As of February 20, 2026, there were 93,396,488 common units outstanding held by 126 holders of record and 14,491,540 Class B units outstanding held by 14 holders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record.

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. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company and our partnership agreement. 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.

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2025 for the repayment of $13.4 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2025. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future. Any such allocation, whether for debt repayment or another purpose, would have the effect of reducing the amount of cash distribution to our common unitholders.

Unlike other public companies, we do not currently intend to retain cash from our operations for capital expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base (“replacement capital expenditures”). The Board of Directors may change our distribution policy and decide to withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the quarter(s) in which any such amounts are withheld. Over the long term, if our reserves are depleted and our operators become unable to maintain production on our existing properties and we have not been retaining cash for replacement capital expenditures, the amount of cash generated from our existing properties will decrease and we may have to reduce the amount of distributions payable to our unitholders. To the extent that we do not withhold replacement capital expenditures, a portion of our cash available for distribution will represent a return of your capital.

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. For the quarter ending December 31, our partnership agreement requires that we distribute all of

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our available cash to common unitholders of record on the applicable record date by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 90 days following the end of such quarter. Our partnership agreement generally defines “available cash” for any quarter as:

●

the sum of:

●

all of our and our subsidiaries’ cash and cash equivalents on hand at the end of that quarter;

●

as determined by our General Partner, all of our and our subsidiaries’ cash or cash equivalents 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; and

●

all of our cash and cash equivalents received by us from distributions on OpCo common units by the Operating Company made with respect to that quarter subsequent to the end of that quarter and prior to the date of distribution of available cash;

●

less the amount of cash reserves established by our General Partner to:

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provide for the proper conduct of our business (including reserves for our future capital expenditures and for our future credit needs);

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comply with applicable law or any debt instrument or other agreement or obligation to which we or our subsidiaries are a party or to which our or our subsidiaries’ assets are subject; or

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provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters;

Working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to unitholders, and with the intent of the borrower to repay such borrowings within 12 months with funds other than additional working capital borrowings.

The limited liability company agreement of the Operating Company requires that, for the quarters ending March 31, June 30 and September 30, 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) 60 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 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;

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●

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);

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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.

In addition, the limited liability company agreement of our General Partner contains provisions that prohibit certain actions without a supermajority vote of at least 66²/₃% of the members of the Board of Directors, including:

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the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio for the preceding four quarters;

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the reservation of a portion of cash generated from operations to finance acquisitions;

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modifications to the definition of “available cash” in our partnership agreement; and

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the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units.

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. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter. The Series A preferred units and Class B units will receive the distribution preference described below.

Series A preferred units

As of February 20, 2026, we had 162,500 Series A preferred units outstanding. 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. 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. 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. 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. We cannot pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

Class B units

As of February 20, 2026, we had 14,491,540 Class B units outstanding. Each holder of Class B units pays five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution” and such per unit amount, the “Class B Capital Contribution Per Unit Amount”) in exchange for Class B 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 subsequent to distributions on the Series A preferred units but prior to distributions on our common units.

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Common Units

As of February 20, 2026, we had 93,396,488 common units outstanding. 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. 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. 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.

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, 2025.

Unregistered Sales of Equity Securities

On February 12, 2025, we issued 3,162 common units to Gregory James Rasmussen in exchange for 3,162 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).

On February 14, 2025, we issued 29,418 common units to Gregory Scott Rasmussen in exchange for 29,418 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.

The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act in reliance upon Section 4(a)(2) of the Securities Act.

Item 6. [Reserved]

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources and should be read together with “Item 8. Financial Statements and Supplementary Data” and related notes included elsewhere in this Annual Report.

This discussion contains forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Such views, beliefs, assumptions and estimates may, and often do, vary from actual results and the differences can be material. Actual results could differ materially from such forward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.

Overview

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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 following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of December 31, 2025:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	660	393	3.53	1.63
Mid‑Continent	96	57	0.40	0.34
Terryville/Cotton Valley/Haynesville	62	27	0.34	0.18
Appalachian Basin	6	4	0.02	0.04
Bakken/Williston Basin	39	116	0.17	0.13
Eagle Ford	29	25	0.16	0.09
DJ Basin/Rockies/Niobrara	8	6	0.04	0.02
Total	900	628	4.66	2.43

(1)	The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future.

The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of December 31, 2025:


Basin or Producing Region	Gross Locations(1)	Net Locations(1)	Average Gross Horizontal Wells/DSU(2)
Permian Basin	4,446	32.50	12.0
Mid‑Continent	2,056	10.73	6.8
Haynesville	911	11.61	5.9
Appalachia	230	2.03	7.6
Bakken	1,308	2.50	8.5
Eagle Ford	1,242	12.76	6.9
Rockies	148	0.98	10.5
Total	10,341	73.11	8.3

(1)

These locations only include our major properties and do not include locations from our minor properties, which generally include properties with less than a 0.1% net revenue interest and are time consuming to quantify, but in the estimation of our management, could add up to an additional 15% to our net inventory in the aggregate.

(2)	Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of December 31, 2025. DSUs vary in size.

Recent Developments

Quarterly Distributions

On February 26, 2026, the Board of Directors declared a quarterly cash distribution of $0.37 per common unit and $0.357502 per OpCo common unit for the quarter ended December 31, 2025. We intend to pay the distributions on March 25, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2026.

The $0.012498 excluded from the OpCo common unit distribution corresponds to a tax refund received by us in the fourth quarter of 2025. Under the limited liability company agreement of the Operating Company, we do not reimburse the Operating Company for federal income tax refunds received by us.

We will pay a quarterly cash distribution on the Series A preferred units of approximately $2.5 million for the quarter ended December 31, 2025. We intend to pay the distribution subsequent to February 26, 2026, and prior to the distribution on the common units and OpCo common units.

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Business Environment

Global Conflicts

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas. These conflicts, along with the recent U.S. military action in Venezuela, and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. 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.

Government Legislation

On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “Act”), was enacted by the U.S. government. Key provisions of the Act affecting us include: (i) the permanent reduction of the corporate tax rate, (ii) the permanent extension of 100% bonus depreciation for qualified property, and (iii) modifications to the calculation for excess business interest expense limitation under § 163(j) to adjusted taxable income calculation on the business interest expense limitation. In accordance with ASC Topic 740, Income Taxes, we have recognized the effects of the new tax law in the period of enactment. The impact of the Act for the quarter ended September 30, 2025, the reporting period that included the enactment date, resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (the “EIA”).


	Year Ended December 31, 2025				Year Ended December 31, 2024				Year Ended December 31, 2023
	High		Low		High		Low		High		Low
Oil ($/Bbl)	$	80.73	$	55.44	$	87.69	$	66.73	$	93.67	$	66.61
Natural gas ($/MMBtu)	$	9.86	$	2.65	$	13.20	$	1.21	$	3.78	$	1.74

On February 17, 2026, the WTI posted price for crude oil was $62.53 per Bbl and the Henry Hub spot market price of natural gas was $3.13 per MMBtu.

The following table, as reported by the EIA, sets forth the average prices for oil and natural gas.


	Year Ended December 31,
	2025		2024		2023
Oil ($/Bbl)	$	65.39	$	76.63	$	77.58
Natural gas ($/MMBtu)	$	3.52	$	2.19	$	2.53

Rig Count

Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The Baker Hughes United States rotary rig count decreased 8.0% to 527 active land rigs at December 31, 2025 compared to 573 active land rigs at December 31, 2024. The decrease in rig count is primarily related to a decrease in the average prices received for oil, partially offset by an increase in the average price received for natural gas, coupled with domestic and international uncertainties, as noted above.

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The 573 active rig count at December 31, 2024 decreased 4.8% compared to 602 active land rigs at December 31, 2023. The overall decrease in rig count at December 31, 2024 compared December 31, 2023 was primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.

The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated.


	December 31,
Basin or Producing Region	2025	2024	2023
Permian Basin	46	46	50
Mid‑Continent	14	18	17
Terryville/Cotton Valley/Haynesville	11	9	13
Appalachian Basin	—	—	3
Bakken/Williston Basin	5	7	6
Eagle Ford	7	5	8
DJ Basin/Rockies/Niobrara	2	1	1
Other	—	1	—
Total	85	87	98

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices received.

The following table presents the breakdown of our oil, natural gas, and NGL revenues for the following periods:


	Year Ended December 31,
	2025		2024		2023
Revenue
Oil revenue	62	%	71	%	69	%
Natural gas revenue	25	%	16	%	22	%
NGL revenue	13	%	13	%	9	%
	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through December 2027, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.”

Reserves and Pricing

The tables below identify our proved reserves at December 31, 2025, 2024 and 2023, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective periods were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.


	December 31,
Estimated Net Proved Reserves	2025	2024	2023
Oil (MBbls)	21,970	20,001	19,800
Natural gas (MMcf)	213,589	204,253	204,542
Natural gas liquids (MBbls)	15,376	13,498	11,519
Total (MBoe)(6:1)	72,944	67,541	65,409

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	December 31,
Unweighted Arithmetic Average First‑Day‑of‑the‑Month Prices	2025		2024		2023
Oil (Bbls)	$	65.34	$	75.48	$	78.22
Natural gas (Mcf)	$	3.39	$	2.13	$	2.64

Factors Affecting the Comparability of Our Results

Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.

Ongoing Acquisition Opportunities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. 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, 2025, 2024 and 2023 include the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”), the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”) and the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”).

Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.

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Impairment of Oil and Natural Gas Properties

We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025. We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas.

Principal Components of Our Cost Structure

As an owner of mineral and royalty interests, 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.

Production and Ad Valorem Taxes

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are jurisdictional taxes levied on the value of oil, natural gas and NGLs minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities.

Depreciation and Depletion

We follow the full cost method of accounting for costs related to our oil, natural gas and NGL mineral and royalty properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10%, including the effect of income taxes. The full cost ceiling is evaluated at the end of each fiscal quarter and additionally when events indicate possible impairment. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to whether or not proved reserves can be assigned to the properties. 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. 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.

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

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services. 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. In addition, under each of their respective services agreements, affiliates of our Sponsors will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions.

Interest Expense

We finance a portion of our capital requirements and acquisitions with borrowings under our secured revolving credit facility. 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. As a result, we are subject to federal income tax on our taxable income at the United States corporate tax rate, which is currently 21.0%.

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A significant portion of our mineral and royalty interests are located in Texas basins and producing regions.

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Results of Operations

The table below summarizes our revenue and expenses and production data for the periods indicated.


	Year Ended December 31,
	2025		2024		2023

	(In thousands, except production data)
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	317,473	$	304,605	$	267,586
Lease bonus and other income		4,266		6,047		5,594
Gain (loss) on commodity derivative instruments, net		12,091		(1,345)		20,888
Total revenues		333,830		309,307		294,068
Costs and expenses
Production and ad valorem taxes		20,440		20,407		20,326
Depreciation and depletion expense		124,554		135,123		96,477
Impairment of oil and natural gas properties		—		62,118		18,220
Marketing and other deductions		16,350		16,122		12,566
General and administrative expense		39,657		38,543		35,678
Consolidated variable interest entities related:
General and administrative expense		—		—		927
Total costs and expenses		201,001		272,313		184,194
Operating income		132,829		36,994		109,874
Other (expense) income
Interest expense		(34,470)		(26,695)		(25,950)
Loss on extinguishment of debt		—		—		(480)
Other expense		(12)		—		(181)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		—		3,509
Net income before income taxes		98,347		10,299		86,772
Income tax (benefit) expense		(1,304)		(771)		3,766
Net income		99,651		11,070		83,006
Distribution and accretion on Series A preferred units		(34,852)		(21,091)		(6,310)
Net (income) loss and distributions and accretion on Series A preferred units attributable to non-controlling interests		(8,704)		1,254		(16,465)
Distribution to Class B unitholders		(58)		(72)		(89)
Net income (loss) attributable to common units of Kimbell Royalty Partners, LP	$	56,037	$	(8,839)	$	60,142
Production Data:
Oil (Bbls)		3,061,920		2,836,913		2,392,622
Natural gas (Mcf)		26,733,988		27,586,460		23,384,021
Natural gas liquids (Bbls)		1,884,763		1,667,089		1,082,663
Combined volumes (Boe) (6:1)		9,402,348		9,101,745		7,372,622

Comparison of the Year Ended December 31, 2025 to the Year Ended December 31, 2024 and the Year Ended December 31, 2024 to the Year Ended December 31, 2023

Oil, Natural Gas and NGL Revenues

For the year ended December 31, 2025, our oil, natural gas and NGL revenues were $317.5 million, an increase of $12.9 million from $304.6 million for the year ended December 31, 2024. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas coupled with an increase in combined production volumes for the year ended December 31, 2025, partially offset by a decrease in the average prices received for oil and NGLs, as discussed below.

Our revenues for the year ended December 31, 2024 increased by $37.0 million, from $267.6 million for the year ended December 31, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the year ended December 31, 2024 as discussed below.

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Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 9,402,348 Boe or 25,760 Boe/d, for the year ended December 31, 2025, an increase of 300,603 Boe or 892 Boe/d, from 9,101,745 Boe or 24,868 Boe/d, for the year ended December 31, 2024. The increase in production volumes for the year ended December 31, 2025 was primarily attributable to production associated with the Boren Acquisition.

Our production volumes for the year ended December 31, 2024 increased by 1,729,123 Boe or 4,603 Boe/d, from 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023. The increase in production for the year ended December 31, 2024 was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of production for the year ended December 31, 2024, compared to a partial year of production for the year ended December 31, 2023.

Our operators received an average of $63.84 per Bbl of oil, $2.93 per Mcf of natural gas and $23.15 per Bbl of NGL for the volumes sold during the year ended December 31, 2025 and $75.98 per Bbl of oil, $1.82 per Mcf of natural gas and $23.34 per Bbl of NGL for the volumes sold during the year ended December 31, 2024. The year ended December 31, 2025 decreased 16.0% or $12.14 per Bbl of oil and increased 61.0% or $1.11 per Mcf of natural gas compared to the year ended December 31, 2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 14.7% or $11.24 per Bbl of oil and increase of 60.7% or $1.33 per Mcf of natural gas for the comparable periods.

Average prices received by our operators during the year ended December 31, 2024 decreased 0.7% or $0.57 per Bbl of oil and 28.6% or $0.73 per Mcf of natural gas compared to the year ended December 31, 2023, which our operators received an average of $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 1.2% or $0.95 per Bbl of oil and 13.4% or $0.34 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

For the year ended December 31, 2025 lease bonus and other income was $4.3 million, a decrease of $1.7 million compared to $6.0 million for the year ended December 31, 2024. The decrease in lease bonus and other income was due to a large lease bonus received during the year ended December 31, 2024.

Our lease bonus and other income for the year ended December 31, 2024 increased by $0.4 million compared to $5.6 million for the year ended December 31, 2023. The increase in lease bonus and other income is primarily due to a large number of lease bonuses received during the year ended December 31, 2024.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the year ended December 31, 2025 included $7.2 million of mark-to-market gains and $4.9 million of gains on the settlement of commodity derivative instruments compared to $12.2 million of mark-to-market losses and $10.9 million of gains on the settlement of commodity derivative instruments for the year ended December 31, 2024. We recorded a mark-to-market gain for the year ended December 31, 2025 as a result of the maturity of derivative contracts with lower strike pricing. We recorded a mark-to-market loss for the year ended December 31, 2024 as a result of the increase in oil and natural gas strip pricing from the year ended December 31, 2023, offset by realized gains on the settlement of commodity derivative instruments.

Gain on commodity derivative instruments for the year ended December 31, 2023 included $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments.

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Production and Ad Valorem Taxes

Production and ad valorem taxes for the years ended December 31, 2025 and 2024 remained flat at $20.4 million.

For the year ended December 31, 2024, production and ad valorem taxes remained relatively flat compared to $20.3 million for the year ended December 31, 2023.

Depreciation and Depletion Expense

Depreciation and depletion expense for the year ended December 31, 2025 was $124.6 million, a decrease of $10.5 million from $135.1 million for the year ended December 31, 2024. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.

For the year ended December 31, 2024, depreciation and depletion expense increased by $38.6 million from $96.5 million for the year ended December 31, 2023. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Our average depletion rate per barrel was $13.22 for the year ended December 31, 2025, a decrease of $1.58 per barrel from the $14.80 average depletion rate per barrel for the year ended December 31, 2024. The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.

For the year ended December 31, 2024, our average depletion rate per barrel increased by $1.77 per barrel from the $13.03 average depletion rate per barrel for the year ended December 31, 2023. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Impairment of Oil and Natural Gas Properties

We did not record an impairment on our oil and natural gas properties for the year ended December 31, 2025.

We recorded an impairment on our oil and natural gas properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023, respectively, primarily attributable to the decline in the 12-month average price of oil and natural gas.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2025 remained relatively flat at $16.4 million compared to $16.1 million for the year ended December 31, 2024.

Marketing and other deductions for the year ended December 31, 2024 increased by $3.5 million from $12.6 million for the year ended December 31, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition, which included a full year of marketing and other deductions for the year ended December 31, 2024, compared to a partial year of marketing and other deductions for the year ended December 31, 2023.

General and Administrative Expense

General and administrative expenses for the year ended December 31, 2025 were $39.7 million, an increase of $1.2 million from $38.5 million for the year ended December 31, 2024. The increase in general and administrative expenses was attributable to an increase in costs associated with Partnership growth.

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General and administrative expenses for the year ended December 31, 2024 increased by $2.8 million from $35.7 million for the year ended December 31, 2023. The increase in general and administrative expenses was attributable to a $3.3 million increase in unit-based compensation expense, partially offset by a $0.4 million decrease in cash expenses.

Interest Expense

Interest expense for the year ended December 31, 2025 was $34.5 million as compared to interest expense of $26.7 million for the year ended December 31, 2024. The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the partial redemption of the Series A preferred units and the Boren Acquisition.

Interest expense for the year ended December 31, 2024 increased by $0.7 million compared to interest expense of $26.0 million for the year ended December 31, 2023. The increase in interest expense was attributable to an increase in the overall long-term debt balance as a result of borrowings associated with the MB Minerals Acquisition and the LongPoint Acquisition in May 2023 and September 2023, respectively. This increase was partially offset by a decrease in the weighted average interest rate on our outstanding borrowings from 8.62% at December 31, 2023 to 8.42% at December 31, 2024, coupled with the repayment of $60.0 million on our secured revolving credit facility for the year ended December 31, 2024.

Income Tax (Benefit) Expense

For the year ended December 31, 2025 we recognized an income tax benefit of $1.3 million, resulting in an effective tax benefit of 1.33%, compared to an income tax benefit of $0.8 million for the year ended December 31, 2024, resulting in an effective tax rate of 7.49%. We recognized an income tax expense of $3.8 million for the year ended December 31, 2023, resulting in an effective tax rate of 4.34%.

Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of December 31, 2025, 2024 and 2023, we recorded a full valuation allowance on our deferred tax assets. As a result, we did not recognize a benefit from our net operating losses for the respective periods. See Note 13—Income Taxes for further discussion.

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. On December 16, 2025, we entered into a Second Amended and Restated Credit Agreement (the “Second A&R Credit Agreement”). See “Indebtedness” below for further discussion of our secured revolving credit facility.

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. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company, and in “Item 5. 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

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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.

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. For example, the purchase price paid in the Boren Acquisition was partially funded by the proceeds from the underwritten public offering of 11,500,000 common units which resulted in net proceeds of approximately $163.6 million (the “2025 Equity Offering”), we issued 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and the purchase price paid in the LongPoint Acquisition was partially funded by the net proceeds from the Preferred Unit Transaction. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Fourth Quarter Distributions” above for discussion of our fourth quarter 2025 distributions.

Cash Flows

The following table presents our cash flows for the periods indicated.


	Year Ended December 31,
	2025		2024		2023

	(In thousands)
Cash Flow Data:
Net cash provided by operating activities	$	246,462	$	250,916	$	174,268
Net cash used in investing activities		(223,481)		(210)		(246,677)
Net cash (used in) provided by financing activities		(13,172)		(247,531)		78,375
Net increase in cash and cash equivalents	$	9,809	$	3,175	$	5,966

Operating Activities

Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2025 were $246.5 million, a decrease of $4.4 million compared to $250.9 million for the year ended December 31, 2024.

Cash flows provided by operating activities for the year ended December 31, 2024 increased by $76.6 million compared to $174.3 million for the year ended December 31, 2023.

Investing Activities

Cash flows used in investing activities for the year ended December 31, 2025 were $223.5 million compared to $0.2 million for the year ended December 31, 2024. For the year ended December 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the year ended December 31, 2024, cash flows used in investing activities included the purchase of equipment.

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For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to Kimbell Tiger Acquisition Corporation (“TGR”) and $0.9 million in cash received from the dissolution of TGR.

Financing Activities

Cash flows used in financing activities were $13.2 million for the year ended December 31, 2025 compared to $247.5 million of cash flows provided by financing activities for the year ended December 31, 2024. Cash flows used in financing activities for the year ended December 31, 2025 consists primarily of $179.9 million used to redeem a portion of the Series A preferred units, $187.3 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $493.3 million used to repay borrowings under our secured revolving credit facility and $5.1 million of restricted units repurchased for tax withholding, partially offset by $163.6 million in proceeds from the 2025 Equity Offering and $695.6 million of additional borrowings under our secured revolving credit facility.

Cash flows used in financing activities for the year ended December 31, 2024 consists primarily of $187.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $60.0 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and $0.3 million paid in connection with the redemption of Class B units, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.

Cash flows provided by financing activities for the year ended December 31, 2023 consists of $314.0 million in net proceeds from the issuance of Series A preferred units, $201.1 million of additional borrowings under our secured revolving credit facility, $110.7 million in proceeds from the 2023 Equity Offering, and $0.3 million in Class B contributions, partially offset by $243.2 million of distributions to common unitholders of TGR, $153.0 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.

Capital Expenditures

During the year ended December 31, 2025, we paid approximately $222.8 million primarily to fund the Boren Acquisition. During the year ended December 31, 2023, we paid approximately $490.7 million primarily to fund the MB Minerals Acquisition and the LongPoint Acquisition.

Indebtedness

On December 16, 2025, we entered into a Second A&R Credit Agreement, which amended and restated our existing Amended and Restated Credit Agreement, dated as of June 13, 2023 (as amended on July 24, 2023, December 8, 2023, and May 1, 2025). The Second A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $1.5 billion with an initial borrowing base of $625.0 million and an initial aggregate elected commitments amount of up to $625.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the Second A&R Credit Agreement to December 16, 2030.

For additional information on our Second A&R Credit Agreement, please read Note 8―Long-Term Debt to the consolidated financial statements included elsewhere in this Annual Report.

Off-Balance Sheet Arrangements

As of December 31, 2025, we did not have any off-balance sheet arrangements.

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate

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rates on our net taxable income. The non-controlling interest, which is held by the OpCo common unitholders, is not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2025. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder’s tax basis in its common units or produce capital gain to the extent they exceed a common unitholder’s tax basis. Any reduced tax basis will increase a common unitholder’s capital gain when it sells its common units. 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. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter. Please read “Item 1A. Risk Factors—Tax Risks” elsewhere in this Annual Report.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies within the financial statements included elsewhere in this Annual Report.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. Below, we have provided expanded discussion of our more significant accounting estimates.

See Note 2—Summary of Significant Accounting Policies to our financial statements for a summary of our significant accounting policies.

Oil, Natural Gas and NGL Reserves

We account for oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion in our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.

Our independent engineers prepare our estimates of oil, natural gas and NGL reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including development activity, evolving production history and a continual reassessment of the viability of production

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under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. Revisions of previous quantity estimates accounted for the change in the total standardized measure of our reserves from December 31, 2024 to December 31, 2025, and were primarily related to technical revisions due to changes in commodity prices, historical and projected performance and other factors. Additionally, we continue to not intend to book PUD reserves.

Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves, which is primarily based upon when such properties become producing. We assess all items classified as unevaluated property on a periodic basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. 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. During any period in which these factors indicate an impairment, carrying value in excess of estimated recoverable value for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization or potential impairment.

Acquisitions of Mineral and Royalty Interests

Acquisitions of mineral and royalty interests were accounted for as asset acquisitions, whereby the purchase price and associated transaction costs are capitalized and allocated to the acquired mineral and royalty interests. The allocation is determined based on whether the interests acquired relate to proved or unproved oil and natural gas properties, utilizing the estimated fair value of proved reserves as of the date of acquisition. The valuation of proved reserves is based on a projection of future cash flows using objective future pricing assumptions and a discount rate consistent with our estimated cost of capital at the time of the acquisition. The remaining capitalized acquisition costs are allocated to the unproved properties acquired.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production and ad valorem taxes and post-production expenses. The pricing of oil, natural gas and NGLs from the properties in which we own a mineral or royalty interest is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no involvement or operational control over the volumes and method of sale of the oil, natural gas and NGLs produced and sold from the property. We have no rights or obligations to explore, develop or operate the property and do not incur any of the costs of exploration, development and operation of the property. Oil, natural gas and NGL revenues from our mineral and royalty interests are recognized at the point control of the product is transferred to the purchaser. The price and volumes of certain sales are based on estimates that are sometimes not available until future periods. In such cases, estimated realizations are accrued when the sale is recognized and are finalized when the price and volume is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. 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. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of

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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.

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 oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. 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. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2025, we had seven counterparties to our derivative contracts, which are also lenders under our credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. During the years ended December 31, 2025, 2024 and 2023, our top purchaser accounted for approximately 7.7%, 9.1% and 6.7%, respectively, of our oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2025, we had total borrowings outstanding under our secured revolving credit facility of $441.5 million. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense of approximately $4.4 million annually, assuming that our indebtedness remained constant throughout the year.

Inflation

Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 2023 through December 31, 2025. However, rising inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

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Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

Adjusted EBITDA and cash available for distribution on common units are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution on common units are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of a variable interest entity, which include general and administrative expense and interest income. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed 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.

Adjusted EBITDA and cash available for distribution on common units should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies.

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The tables below present a reconciliation of Adjusted EBITDA and cash available for distribution on common units to net income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated.


	Year Ended December 31,
	2025		2024		2023

	(In thousands)
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	99,651	$	11,070	$	83,006
Depreciation and depletion expense		124,554		135,123		96,477
Interest expense		34,470		26,695		25,950
Income tax (benefit) expense		(1,304)		(771)		3,766
EBITDA		257,371		172,117		209,199
Impairment of oil and natural gas properties		—		62,118		18,220
Unit-based compensation		16,323		16,386		13,112
Loss on extinguishment of debt		—		—		480
(Gain) loss on derivative instruments, net of settlements		(7,227)		12,211		(26,371)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		—		(3,509)
General and administrative expense		—		—		927
Consolidated Adjusted EBITDA		266,467		262,832		212,058
Adjusted EBITDA attributable to non-controlling interest		(35,793)		(44,884)		(46,476)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		230,674		217,948		165,582
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		27,624		20,988		18,519
Cash distribution to Series A preferred unitholders		10,523		16,223		4,552
Cash income tax (refund) expense		(2,112)		—		1,642
Distribution to Class B unitholders		58		72		89
Cash available for distribution on common units	$	194,581	$	180,665	$	140,780

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	Year Ended December 31,
	2025		2024		2023

	(In thousands)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:
Net cash provided by operating activities	$	246,462	$	250,916	$	174,268
Interest expense		34,470		26,695		25,950
Income tax (benefit) expense		(1,304)		(771)		3,766
Impairment of oil and natural gas properties		—		(62,118)		(18,220)
Amortization of right-of-use assets		(348)		(349)		(336)
Amortization of loan origination costs		(2,356)		(2,126)		(1,943)
Loss on extinguishment of debt		—		—		(480)
Unit-based compensation		(16,323)		(16,386)		(13,112)
Forfeiture of restricted units		57		—
Gain (loss) on derivative instruments, net of settlements		7,227		(12,211)		26,371
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(9,343)		(13,096)		12,027
Accounts receivable and other current assets		(1,352)		1,071		(1,863)
Accounts payable		917		90		(509)
Other current liabilities		(1,039)		20		(1,264)
Operating lease liabilities		303		382		348
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		—		3,509
Other assets and liabilities		—		—		687
EBITDA		257,371		172,117		209,199
Add:
Impairment of oil and natural gas properties		—		62,118		18,220
Unit-based compensation		16,323		16,386		13,112
Loss on extinguishment of debt		—		—		480
(Gain) loss on derivative instruments, net of settlements		(7,227)		12,211		(26,371)
Consolidated variable interest entities related:
Interest earned on marketable securities in Trust Account		—		—		(3,509)
General and administrative expense		—		—		927
Consolidated Adjusted EBITDA		266,467		262,832		212,058
Adjusted EBITDA attributable to non-controlling interest		(35,793)		(44,884)		(46,476)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		230,674		217,948		165,582
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		27,624		20,988		18,519
Cash distribution to Series A preferred unitholders		10,523		16,223		4,552
Cash income tax (refund) expense		(2,112)		—		1,642
Distribution to Class B unitholders		58		72		89
Cash available for distribution on common units	$	194,581	$	180,665	$	140,780

Item 8. Financial Statements and Supplementary Data

The Partnership’s consolidated financial statements required by this item are included in this Annual Report beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Disclosure controls and procedures are defined as controls designed to ensure that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2025.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed under the supervision of our General Partner’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting includes those policies and procedures that:

●

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

●

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our General Partner’s management and directors; and

●

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, the risk.

As of December 31, 2025, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that our internal controls over financial reporting were effective as of December 31, 2025.

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Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Kimbell Royalty GP, LLC and Unitholders of

Kimbell Royalty Partners, LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Kimbell Royalty Partners, LP (a Delaware limited partnership) and subsidiaries (collectively, the “Partnership”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2025, and our report dated February 26, 2026 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Dallas, Texas

February 26, 2026

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Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for the executive officers, directors and director nominees of our General Partner as of December 31, 2025. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the Board of Directors. Messrs. R. Ravnaas and D. Ravnaas are father and son, respectively.


Name		Age		Position With Our General Partner
Robert D. Ravnaas		68		Chief Executive Officer and Chairman of the Board of Directors
R. Davis Ravnaas		40		President and Chief Financial Officer
Matthew S. Daly		53		Chief Operating Officer
R. Blayne Rhynsburger		39		Controller
Brett G. Taylor		65		Executive Vice Chairman of the Board of Directors
T. Scott Martin		75		Director
Mitch S. Wynne		67		Director
William H. Adams III		67		Independent Director
Craig Stone		62		Independent Director
Erik B. Daugbjerg		56		Independent Director

Robert D. Ravnaas. Robert D. Ravnaas was appointed Chief Executive Officer of our General Partner and Chairman of the Board of Directors in November 2015. Mr. R. Ravnaas served as President of Cawley, Gillespie & Associates, Inc., a petroleum engineering firm, from 2011 until February 2017. He also served as President and director of Rivercrest Royalties II, LLC from 2014 until December 2017, and as President and director of our Predecessor from 2013 until our IPO, and he is a partial owner of certain of the Contributing Parties. Prior to joining Cawley, Gillespie & Associates, Inc. in 1983, he worked as a Production Engineer for Amoco Production Company from 1981 to 1983. Mr. R. Ravnaas received a Bachelor of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder and a Master of Science degree in Petroleum Engineering from the University of Texas at Austin. He is a registered professional engineer in Texas and a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers and the American Association of Petroleum Geologists. Mr. R. Ravnaas was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

R. Davis Ravnaas. R. Davis Ravnaas was appointed President and Chief Financial Officer of our General Partner in November 2015. Mr. D. Ravnaas co-founded our Predecessor in October 2013, served as Vice President and Chief Financial Officer from November 2013 to October 2015 and served as President and Chief Financial Officer of our Predecessor from October 2015 until our IPO. He has also served as Vice President and Chief Financial Officer of Rivercrest Royalties Holdings II, LLC and/or its predecessor, Rivercrest Royalties II, LLC, since August 2014, and he is a partial owner of certain of the Contributing Parties. From 2010 to 2012, Mr. D. Ravnaas was responsible for sourcing, evaluating and monitoring investments in energy and industrials companies as an associate investment professional with Crestview Partners, a New York based private equity fund with $6.0 billion under management. Mr. D. Ravnaas left Crestview Partners in 2012 to attend the Stanford Graduate School of Business, where he earned his Master in Business Administration in 2014. Mr. D. Ravnaas also has an AB in Economics from Princeton University and a MSc in Finance and Economics from the London School of Economics.

Matthew S. Daly. Matthew S. Daly was appointed Chief Operating Officer of our General Partner in May 2017. Mr. Daly has served as Senior Vice President—Corporate Development of our General Partner since September 2016.

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Mr. Daly served as Senior Vice President—Corporate Development of our Predecessor from August 2016 until our IPO. From 2014 to 2016, Mr. Daly served as Senior Analyst—Energy at Hirzel Capital Management LLC, a Dallas-based hedge fund, where he managed public energy investments. From 2004 to 2013, he served as Senior Analyst—Energy at Kleinheinz Capital Partners, Inc., where he managed public and private energy investments and assisted with macro hedging trades. From 2002 to 2004, Mr. Daly was a Vice President—Mergers and Acquisitions at Lazard Frères & Co. in New York City. Mr. Daly has a Bachelor of Business Administration from the University of Texas at Austin and a Master of Business Administration from the University of Chicago Booth School of Business and is a certified public accountant.

R. Blayne Rhynsburger. R. Blayne Rhynsburger has served as the Controller of the General Partner since February 2017. Mr. Rhynsburger previously served as the Controller of our Predecessor from November 2015 until our IPO. Prior to that time, Mr. Rhynsburger served as audit manager from July 2014 to November 2015, audit senior from July 2011 to June 2014, and audit staff from September 2009 to June 2011 at Whitley Penn LLP, where he specialized in assurance and advisory services for clients in multiple industries, primarily energy clients in the public and private sectors. Mr. Rhynsburger also has served as an adjunct professor of petroleum accounting in the graduate school of Texas Christian University’s Neeley School of Business since 2015. Mr. Rhynsburger holds a Bachelor of Business Administration degree in Accounting and Finance and a Master of Accounting degree from Texas Christian University. He is also a member of the Texas Society of Certified Public Accountants.

Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the Board of Directors in November 2015. Mr. Taylor has over 40 years of experience in the oil and gas industry as a petroleum landman. He began his career at Texas Oil and Gas Corporation from 1982 to 1985. He then spent thirteen years at Fortson Oil Company, where he served as Land Manager and Vice President—Land from 1985 to 1998. In 1998, Mr. Taylor co-founded, with Joe B. Neuhoff, Neuhoff-Taylor Royalty Company and began acquiring producing royalties and minerals. He has also served as President and Chief Executive Officer of various private companies since 1998, and certain of such companies are Contributing Parties. Mr. Taylor has a Bachelor of Business Administration—Petroleum Land Management degree from the University of Texas at Austin and is a member of the American Association of Professional Landmen. Mr. Taylor was selected to serve as a director because of his broad knowledge of land management, oil and gas title, due diligence and related matters.

T. Scott Martin. T. Scott Martin was appointed as a director of our General Partner in November 2015. Mr. Martin served as Chief Executive Officer of our Predecessor since July 2014 until our IPO. He has also served as Chairman of the board of directors of Rivercrest Royalties Holdings II, LLC and/or its predecessor, Rivercrest Royalties II, LLC, since July 2015. In October 2023, Mr. Martin was appointed CEO and Chairman of the Board of Evergreen Natural Resources, LLC. He has over 46 years of experience in the oil and gas industry. Mr. Martin founded Ellora Energy LLC in 1995 and was Chairman and Chief Executive Officer of Ellora Energy Inc. from 2002 to 2010. Before that, he was Chief Operating Officer of Alta Energy Corporation from 1992 to 1994, Chief Executive Officer of TPEX Exploration, Inc. from 1990 to 1992 and a consulting engineer at BWAB, Inc. from 1985 to 1990. Mr. Martin began his career in the oil and gas industry in 1979 at Amoco Production Company. Mr. Martin has a Bachelor of Arts degree in Biology from Colorado College and a degree in Chemical Engineering from the University of Colorado at Boulder. He is a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Martin was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Mitch S. Wynne. Mitch S. Wynne was appointed as a director of our General Partner in November 2015. He has been President and owner of Wynne Petroleum Co. since 1992. Mr. Wynne has been engaged in the oil and gas industry for 40 years. In 2013, he founded MSW Royalties, LLC, a Contributing Party, where he serves as manager. Mr. Wynne served on the board of Inspire Insurance Solutions from 1997 to 2002, Millers Mutual Insurance in 1997 and the All Saints’ Episcopal School from 1994 to 1996. He has also served on the board of the Union Gospel Mission in Fort Worth since 2010. Mr. Wynne has a Bachelor of Arts degree in Political Science from Washington and Lee University. Mr. Wynne was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

William H. Adams III. William H. Adams III was appointed as a director of our General Partner effective as of the date that our common units were first listed on the NYSE. Since 2007, Mr. Adams has served as Chairman of Texas Appliance Supply, Inc., a wholesale and retail appliance distribution company. From 1981 to 2006, Mr. Adams held a variety of positions in the commercial and energy banking sector, including as Executive Regional President of Texas Bank in Fort Worth and as President of Frost Bank—Arlington. From 2001 to 2010, Mr. Adams served as a member of

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the board of directors of XTO Energy, Inc. Mr. Adams currently serves as a member of the board of directors of TXO Energy Partners, LP, a publicly traded oil and gas production company, and as a member of the board of directors of Graham Savings and Loan, SSB, a privately owned savings bank. Mr. Adams has a Bachelor of Business Administration in Finance from Texas Tech University. Mr. Adams was selected to serve as a director because of his extensive experience in the energy banking sector and as a former director of a public oil and gas company.

Craig Stone. Craig Stone was appointed as a director of our General Partner effective as of the date that our common units were first listed on the NYSE. Mr. Stone concluded a 30-year career with Ernst & Young LLP when he retired effective September 2015. Prior to his retirement from Ernst & Young LLP, Mr. Stone was an audit partner and the Fort Worth Managing Partner at Ernst & Young LLP. Over the course of his career, he has served many public oil and gas clients and assisted in numerous mergers, acquisitions and public offerings, including initial public offerings, secondary offerings and public debt transactions. Prior to retiring in 2023, Mr. Stone held a ministry position with the Hills Church where he oversaw and managed campus construction and enhancement plans and other strategic expansion initiatives. He has a Bachelor of Science in Accounting from Abilene Christian University and is a certified public accountant. Mr. Stone was selected to serve as a director because of his extensive financial experience with public oil and gas companies.

Erik Daugbjerg. Erik Daugbjerg was appointed as a director of our General Partner in April 2018. Mr. Daugbjerg has more than 24 years of experience in upstream and midstream energy companies, including founding roles at two oil and gas operators based in the Permian Basin. Prior to Concho Resources, Inc.’s acquisition of RSP Permian, Inc. in July 2018, Mr. Daugbjerg served as the Executive Vice President of Land and Business Development of RSP Permian, Inc., a role to which he was appointed in March 2017. Starting in 2010, Mr. Daugbjerg served in various other roles for RSP Permian, Inc. and its affiliates, including Vice President of Business Development and Vice President of Marketing. Mr. Daugbjerg has a Bachelor in Business Administration degree from Southern Methodist University and is active with several Texas energy industry organizations. Mr. Daugbjerg was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Board Leadership Structure

Robert D. Ravnaas currently serves as the Chief Executive Officer and Chairman of the Board of Directors. The Board of Directors has no policy with respect to the separation of the offices of chairman of the Board of Directors and chief executive officer. Instead, that relationship is defined and governed by the limited liability company agreement of our General Partner, which permits the same person to hold both offices. Directors of the Board of Directors are appointed by Kimbell Holdings, which is jointly owned by our Sponsors. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Director Independence

Because we are a limited partnership, we rely on an exemption from the provisions of the NYSE Listed Company Manual that would otherwise require our Board of Directors to be composed of a majority of independent directors. We are not required to have a compensation committee or a nominating and governance committee, although we have elected to confer matters related to the compensation of the executive officers and directors of our General Partner to the conflicts and compensation committee. In addition, we are required to have an audit committee composed of at least three members who meet the independence and experience tests established by the NYSE and the Exchange Act. Our Board of Directors has determined that William H. Adams III, Craig Stone and Erik B. Daugbjerg, each of whom serves on our audit committee (the “Audit Committee”) and our conflicts and compensation committee (the “Conflicts and Compensation Committee”), are independent under the independence standards of the NYSE and the Exchange Act.

Board Role in Risk Oversight

Our corporate governance guidelines (“Governance Guidelines”) provide that the Board of Directors is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by the Audit Committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies. Our

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Governance Guidelines are available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Committees of the Board of Directors

The Board of Directors has an audit committee and a conflicts and compensation committee. The Board of Directors may also have such other committees as it determines from time to time.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act. The Audit Committee is composed of William H. Adams III, Craig Stone and Erik B. Daugbjerg. The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approves all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approves any non-audit services and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee and our management, as necessary.

Each of Messrs. Adams, Stone and Daugbjerg is deemed to be “financially literate” as defined by the listing standards of NYSE, and Mr. Stone is deemed an “audit committee financial expert,” as defined in SEC regulations. Each of the members of the Audit Committee is independent under the independence standards of the NYSE. Our Audit Committee charter is available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Conflicts and Compensation Committee

In accordance with the terms of our partnership agreement, at least two members of the Board of Directors will serve on our Conflicts and Compensation Committee to review specific matters that may involve conflicts of interest. The Conflicts and Compensation Committee is also responsible for the oversight, and periodic review of, the General Partner’s compensation philosophy and the effectiveness of the various elements of the General Partner’s compensation program. The Conflicts and Compensation Committee is currently composed of William H. Adams III, Craig Stone and Erik B. Daugbjerg. The members of our Conflicts and Compensation Committee cannot be officers or employees of our General Partner or directors, officers or employees of its affiliates or the Contributing Parties and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our Conflicts and Compensation Committee cannot own any interest in our General Partner, its affiliates or the Contributing Parties or any interest in us or our subsidiaries other than common units and awards, if any, under our long-term incentive plan. Our Conflicts and Compensation Committee charter is available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires directors, executive officer and persons who beneficially own more than 10 percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that during fiscal year 2025 all of our directors, executive officers and persons who beneficially own more than 10 percent of a registered class of our equity securities complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act, except that one Form 4 filing was filed late in 2025 by Mitch S. Wynne, related to a single transaction.

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Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics applicable to all employees, directors and officers, including our principal executive officer, principal financial officer, and principal accounting officer. Our Code of Business Conduct and Ethics covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Business Conduct and Ethics is posted on the “Corporate Governance” section of our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.” Any amendment to, or waiver from, our Code of Business Conduct and Ethics relating to any of our executive officers will be posted on our website.

Insider Trading Policy

We have adopted an insider trading policy and procedures governing the purchase, sale, and/or other dispositions of our securities by our directors, officers and employees, as well as by the Partnership itself, that are reasonably designed to promote compliance with insider trading laws, rules and regulations, and any NYSE listing standards. A copy of our Insider Trading Policy is filed hereto as Exhibit 19.1.

Corporate Governance Information

Interested parties may communicate directly with the independent members of the Board of Directors by submitting correspondence in an envelope marked “Confidential” addressed to the “Independent Members of the Board” in care of the secretary of the General Partner at the following address:

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

Our Governance Guidelines, which contain our definition of director independence, provide that the non-management directors of the Board of Directors will meet periodically in executive sessions without management participation. Additionally, all of the independent directors of the Board of Directors meet in executive sessions without management participation or participation by non-independent directors at least once a year. Currently, the chairman of the Audit Committee of the Board of Directors, Craig Stone, presides at the executive sessions of the non-management directors and the executive sessions of the independent directors. This information is also available on our website at www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Item 11. Executive Compensation and Other Information

Compensation Discussion and Analysis

This compensation discussion and analysis (the “CD&A”) provides information about the compensation objectives and policies for our principal executive officer, our principal financial officer and our two other executive officers (collectively our named executive officers or “NEOs”) during the last completed fiscal year. Our NEOs for the year ended December 31, 2025 include:


Name		Principal Position
Robert D. Ravnaas		Chairman and Chief Executive Officer (“CEO”)
R. Davis Ravnaas		President and Chief Financial Officer (“CFO”)
Matthew S. Daly		Chief Operating Officer (“COO”)
R. Blayne Rhynsburger		Controller

This discussion is intended to provide context for the tabular disclosure provided in the executive compensation tables below and to provide investors with the material information necessary to understanding our executive compensation program.

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Overview of Our Executive Compensation Program

Our General Partner has sole responsibility for conducting our business and managing our operations, and its executive officers and its Board of Directors make decisions on our behalf. As is typical of publicly traded limited partnerships, we do not directly employ any of the persons responsible for managing our business. Our General Partner’s executive officers manage and operate our business as part of the services provided by Kimbell Operating to our General Partner under a management services agreement. All of our General Partner’s executive officers and other employees necessary to operate our business are employed and compensated by Kimbell Operating or an entity with which Kimbell Operating arranges for the provision of services. The compensation for all our executive officers is indirectly paid by us pursuant to the management services agreement with Kimbell Operating as described in “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements.” Neither Kimbell Operating nor any affiliated entity has entered into any employment agreement with any of its executive officers.

Our General Partner’s Conflicts and Compensation Committee has adopted an annual review process for our executive compensation program. This annual review typically occurs in December of each year, and the most recent review was conducted in December 2025. This process allows us to adjust our compensation practices and targets based on prevailing market and industry conditions at the time, which aligns our compensation philosophy with our business objectives and, thereby, the interests of our executive officers with those of our unitholders.

Our Compensation Philosophy

Our compensation program is designed to reward performance and to align the interests of our executive officers with those of our unitholders. As discussed further below, we seek to tie our compensation metrics to the achievement of performance goals and the creation of unitholder value. Our long-term incentives, in the form of restricted unit awards, represent a significant portion of the total compensation paid to our executive officers. In addition, these equity awards incentivize the creation of unitholder value and encourage retention of executives and key employees through the use of multi-year vesting schedules.

Use of an Independent Compensation Advisory Firm

Our General Partner’s Conflicts and Compensation Committee has engaged Pearl Meyer LLC (“Pearl Meyer”) to review our compensation practices against the norms of its competitive markets and to evaluate and recommend appropriate changes to our compensation practices consistent with our objectives.

The Conflicts and Compensation Committee is responsible for approving the scope of work performed by Pearl Meyer and considering its independence in light of the rules of the SEC and the NYSE. Pearl Meyer provides the Conflicts and Compensation Committee with a letter confirming its independence and the Conflicts and Compensation Committee determined that Pearl Meyer was independent under the relevant rules.

Peer Group Used in Determining 2025 Compensation

Pearl Meyer was engaged to perform a formal survey to identify a peer group of upstream oil and gas companies, as well as mineral and royalty companies, of comparable size to the Partnership. This peer group, which was updated in Fall of 2024 to set compensation metrics for 2025 performance, is used by the Conflicts and Compensation Committee to provide comparative market compensation data and guideposts on the basis of which the Conflicts and Compensation Committee determines NEO compensation.

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The peer group is comprised of the following thirteen companies:


Black Stone Minerals, L.P.	Magnolia Oil & Gas Corporation
Callon Petroleum Company	Northern Oil and Gas, Inc.
Comstock Resources, Inc.	SM Energy Company
Crescent Energy Company	Sitio Royalties Corp.
Gulfport Energy Corporation	Talos Energy Inc.
HighPeak Energy, Inc.	Vital Energy Inc.
Mach Natural Resources LP

Key Components of Our 2025 Executive Compensation Program and Compensation Mix

Our executive compensation program has been customized to align with our business objectives and to align the interests of our executive officers with those of our unitholders. We annually evaluate the various components of our compensation program relative to the competitive market. Our compensation and benefit programs for 2025 consisted of the following key components, which are described in greater detail below:

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Base salary;

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Long-term incentive restricted units;

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Non-equity incentive plan compensation, consisting of short-term incentive cash bonuses (“STI Bonuses”);

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Other compensation, consisting of distributions received from restricted unit awards; and

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Broad-based retirement, health and welfare benefits.

In allocating compensation among the various components, we emphasize performance-based, at-risk compensation while also seeking to provide competitive levels of fixed compensation. Long-term incentives constitute the largest portion of total compensation and provide an important alignment to common unitholder interests. We do not target a specific percentage for each element of compensation relative to total compensation. We evaluate each element against the competitive market within the parameters of our compensation strategy. Therefore, the relative weighting of each element of our total pay mix may change over time as the competitive market moves or other market conditions that affect us change. Our resulting compensation mix reflects alignment with our compensation strategy of competitively targeting the market for all elements of compensation. Below expected performance against the goals in our short or long-term plans will generally yield below market total pay but performance above our operational and financial targets can yield pay above market median into the upper third quartile of the market.

Base Salary

Each NEO’s base salary is a fixed component of compensation based on the position, the incumbent’s experience and demonstrated level of expertise. Base pay, once set each year, does not vary depending on the level of performance achieved. As a result, our philosophy is to set base salary at a sufficient level necessary to attract and retain individuals with superior talent, expertise and experience. We review the base salaries for each NEO annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review, we consider individual and company performance over the course of that year.

Long-Term Incentive Awards

The Conflicts and Compensation Committee makes determinations regarding long-term incentive restricted unit awards for NEOs in the first quarter of each year, subsequent to year-end results. The target awards for 2025 performance were set in December 2024, with the actual number of restricted units granted determined in February 2026, after the Conflicts and Compensation Committee reviews the Partnership’s 2025 performance. The Conflicts and Compensation Committee believes that this approach furthers its philosophy of rewarding performance by determining the number of restricted stock units only after the achievement of performance metrics is known. Mr. Rhynsburger does not participate in the executive compensation programs described in this CD&A; his compensation is determined in accordance with the

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compensation programs applicable to employees generally, which did not include Partnership performance criteria, and instead is based on peer benchmarking for similar positions as well as his individual contributions and performance.

Because the determination of the number of restricted units in respect to 2025 performance is made in February 2026, after year end, pursuant to SEC reporting requirements, the value of those awards is not included in the compensation tables included herein, and will be included in the following year. For example, this year’s Summary Compensation Table reports the value of the restricted units that were granted to NEOs in February 2025 in relation to 2024 fiscal year performance.

Long-term incentive restricted unit awards are made pursuant to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan. Additionally, each award is subject to the terms and conditions of the award agreement that we entered into with the applicable NEO. The restricted units vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through each applicable vesting date. Upon a grantee’s termination of service for any reason other than death or disability, all unvested restricted units will be immediately forfeited as of the date of termination. In the case of termination resulting from death or disability, all unvested restricted units will become fully vested as of the date of termination. Long-term incentive awards under the executive compensation program have quantitative measures directly linked to the desired financial and operational goals, as described below under “—Factors Used in Determining Incentive Compensation.” The target restricted unit awards set in December 2023 for 2024 performance were 186,000, 165,000 and 102,000 restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively. In February 2025, the Conflicts and Compensation Committee determined that, based on the achievement of performance criteria as set forth in last year’s Form 10-K, that 150.0% of the target restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be granted for 2024 performance, resulting in awards of 279,000, 247,500 and 153,000 restricted units, respectively. As described above, Mr. Rhynsburger’s compensation was determined based on benchmarking of similar positions, and he was granted 16,025 restricted units. Because these grants were made in 2025, they are included in the compensation tables included in this Form 10-K.

In December 2024, the Conflicts and Compensation Committee set the target restricted unit awards for 2025 performance at 186,000, 165,000 and 102,000 restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively. The Conflicts and Compensation Committee’s decisions as to the actual number of restricted units granted were made in February 2026, after the review of the achievement of compensation factors, as described below.

The Conflicts and Compensation Committee has not granted, nor does it intend to grant, equity awards in anticipation of the release of material, nonpublic information. Similarly, the Partnership has not timed, nor does it intend to time, the release of material, nonpublic information based on equity award grant dates. The Partnership has not previously granted option awards to its directors or employees.

STI Bonuses

The STI Bonuses provide our NEOs with an incentive in the form of an annual cash bonus to achieve our overall qualitative business goals. Bonuses for each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly are based on their achievement of the targets relating to the four factors described below and KRP’s core competency goals, which include achievement of strategic objectives, goals in compliance and ethics and teamwork within the Partnership. The prioritization of KRP’s various core competencies varies by year based in part on the previous year’s performance, and the various core competencies bear differently on the Conflicts and Compensation Committee’s determination of the NEO’s STI Bonuses depending on facts and circumstances considered, with no single factor being determinative to the overall bonus decision. In making the bonus determinations for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, other post-performance evaluation criteria taken into account include performance in internal and public financial reporting, budgeting and forecasting processes, compliance and infrastructure and investment and cost-savings initiatives. Non-financial factors considered also included, among other items, providing strategic leadership and direction for the Partnership, including corporate governance matters, managing the strategic direction of the Partnership, increasing operational efficiency, expanding our asset base and communicating to investors and other important constituencies. The actual amounts of the annual bonus for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly are determined by the Conflicts and Compensation Committee in its sole discretion and may be higher or lower than their target amounts.

100

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As described above, Mr. Rhynsburger’s STI Bonus was determined based on benchmarking of similar positions, and he was awarded a STI Bonus of $97,800 for the year ended December 31, 2025.

In December 2024, the Conflicts and Compensation Committee set the target STI Bonuses for 2025 performance at $677,040, $649,740 and $529,620 for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively. The Conflicts and Compensation Committee’s decisions as to the actual STI Bonuses earned for 2025 performance was made in February 2026, after the review of the achievement of compensation factors, as described below.

Factors Used for Determining Incentive Compensation and Compensation Decisions for 2024 Performance

The Conflicts and Compensation Committee approved five factors, which are described in further detail below, to be used in determining the 2023 long-term and short-term incentive awards for our NEOs, other than Mr. R. Blayne Rhynsburger. Four of the five factors are quantitative in nature and one is qualitative. The four quantitative factors consist of target objectives relating to (i) increase in barrels of oil produced (“production growth”), (ii) replacing proved developed producing reserves (“PDP reserve replacement”), (iii) controlling cash general and administrative expense per barrel of oil equivalent (“Cash G&A expense per Boe”) and (iv) unitholder return relative to select peer companies (“relative unitholder return”). The fifth and only qualitative factor is the achievement of certain core competencies, with such core competencies and the achievement thereof to be determined by the Conflicts and Compensation Committee in its discretion.

The chart below displays each compensation factor for 2025, its relative weight, the target objective and the percentage of the target STI Bonuses and target restricted units to be awarded based on the level of achievement for such related target objective.

Kimbell Royalty Partners, LP 10-K