10-K

f

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, 2023
☐	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, 2023, was $898.8 million, based on the closing price of such common units of $14.71 as reported on the New York Stock Exchange on June 30, 2023. As of February 16, 2024, the registrant had outstanding 73,851,458 common units representing limited partner interests and 20,847,295 Class B units representing limited partner units.

Documents Incorporated by Reference: None

Kimbell Royalty Partners, LP

TABLE OF CONTENTS

PART I
Item 1. Business	12
Item 1A. Risk Factors	34
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	89
Item 8. Financial Statements and Supplementary Data	92
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
Item 9A. Controls and Procedures	93
Item 9B. Other Information	97
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	97
PART III
Item 10. Directors, Executive Officers and Corporate Governance	97
Item 11. Executive Compensation and Other Information	102
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	112
Item 13. Certain Relationships and Related Party Transactions, and Director Independence	116
Item 14. Principal Accounting Fees and Services	122
PART IV
Item 15. Exhibits, Financial Statement Schedules	122
Item 16. Form 10-K Summary	125
Signatures	126

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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.

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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:

● our ability to replace our reserves;

● 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;

● our ability to execute our business strategies;

● 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;

● the level of production on our properties;

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

● 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;

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

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

● 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 and the conflict in the Middle East;

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

● impacts of impairment expense on our financial statements;

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

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

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

● 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;

● the availability of transportation facilities;

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

● 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 the Biden administration’s proposals and recent executive orders focused on addressing climate change;

● future operating results;

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

● operating hazards faced by the operators of our properties;

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

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

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

● 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

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

● Our cash flow may prevent us from paying cash distributions.

● 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.

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

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

● 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.

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

● 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.

● 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.

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

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

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

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

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

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

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

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

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

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

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

● 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.

● 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.

● 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.

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

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

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

● 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.

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

Risks Related to Economic Conditions and Our Industry

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

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

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

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

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

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

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

Risks Related to Our Indebtedness and Derivatives

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

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

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

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

Risks Related to Our Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

● 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

● We may incur substantial income tax liabilities.

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

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

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

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

● The IRS Form 1099-DIVthat 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.

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

● 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

● 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.

● 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.

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

● 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.

General Risk Factors

● Increased costs of capital could materially adversely affect our business.

● A terrorist attack or armed conflict could harm our business.

● 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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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” 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, Ben J. Fortson, 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 16, 2024:

(1) The Sponsors are affiliates of our founders, Messrs. Fortson, R. Ravnaas, Taylor and Wynne.

(2) Includes common units representing limited partner interests in the Partnership (“common units”) beneficially owned by the Sponsors other than those reflected as held by Kimbell GP Holdings, LLC. Also includes common units beneficially owned by our directors and officers and other of our affiliates.

(3) Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP, certain affiliates of Hatch Royalty LLC and MB Minerals, L.P.

(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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Significant Acquisitions

On May 17, 2023, we completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 common units of the Operating Company (“OpCo common units”) and an equal number of Class B common units representing limited partner interests in the Partnership (“Class B units”) and (b) 557,302 common units. We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas.

On September 13, 2023, we completed the acquisition of all of the issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $455.0 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Item 5— Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities).

Kimbell Tiger Acquisition Corporation

On February 8, 2022, we announced the initial public offering (the “TGR IPO”) of our recently dissolved special purpose acquisition company, Kimbell Tiger Acquisition Corporation (“TGR”) for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants (“Private Placement Warrants”), net of underwriters’ discounts and commissions and other costs and expenses. The proceeds held in the trust account were not available to be used by us at any time.

On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock of TGR included as part of the units issued in its initial public offering. The per-share redemption price for the TGR public shares was $10.57. The public shares of TGR ceased trading as of the close of business on May 8, 2023.

As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s IPO. The non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying consolidated balance sheet as of December 31, 2023.

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,

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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, 2023, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2023, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including approximately 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. 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, 2023, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 65,409 MBoe (47.9% liquids, consisting of 30.3% oil and 17.6% NGLs) based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). All of our reserves were classified as proved developed reserves. The properties underlying our mineral and royalty interests typically have low estimated decline rates. Our PDP reserves have an average estimated yearly decline rate of 14.1% during the initial five-years.

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, 2023, there were approximately 1,100 operators actively producing on our acreage, with our top ten operators (EP Energy E&P Company, L.P., SWN Production Company LLC, XTO Energy, Inc., Chesapeake Operating, Inc., EOG Resources, Inc., Vital Energy, Mewbourne Oil Company, Pioneer Natural Resources Company, Chevron USA, Inc., and Diamondback E&P, LLC) together accounting for approximately 38.0% of our revenues.

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During the years ended December 31, 2023, 2022 and 2021, payments we received from our top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of our revenues. 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, 2023, there were 98 rigs (representing 16.3% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 92 rigs operating on our acreage as of December 31, 2022. Please read “Item 7. 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, 2023, our oil, natural gas and NGL revenues were generated 69% from oil sales, 22% from natural gas sales and 9% 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:

● 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. For example, in 2023, we completed the MB Minerals Acquisition and the LongPoint Acquisition, further enhancing our asset base.

We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. 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.”

● 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 assets to us or to accept any offer that we may make for any additional assets, and we may decide not to acquire such additional assets even if such Contributing Parties offer them to us. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

● Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests. Our assets consist of diversified mineral and royalty interests. As of December 31, 2023, 55% and 54% of our well count and gross aggregate acreage, respectively, are located in the Permian Basin and Mid-Continent, which are among the most active areas in the country. 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.

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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.

● 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 $550.0 million secured revolving credit facility. On December 8, 2023, we amended our secured revolving credit facility to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million. During the year ended December 31, 2023, the Board of Directors approved the repayment of $50.6 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units. Of the $50.6 million, $13.8 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2024. With respect to future quarters, the Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility. 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:

● 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, 2023, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent, and as of December 31, 2023, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including approximately 100% of our overriding royalty interests), and substantially all of those leases were held by production. The estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 65,409 MBoe (47.9% liquids, consisting of 30.3% oil and 17.6% NGLs) based on the reserve report prepared by Ryder Scott. All of our reserves were classified as proved developed reserves. The 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 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 129,000 gross wells, including over 50,000 wells in the Permian Basin.

● 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.

● 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 31 years of oil and gas experience. Our management team and Board of Directors, which includes our founders, have a long history of buying mineral and royalty interests in high-quality producing acreage throughout the United States. Certain members of our management team have managed a significant investment program, investing in over 160 acquisitions. We believe we have a proven competitive advantage in our ability to source, engineer, evaluate, acquire and manage mineral and royalty interests in high-quality producing acreage.

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.

● 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 Springs formation in the Delaware Basin, which are among the most active plays in the country.

● 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.

● 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

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modern completion techniques has resulted in high recoveries relative to drilling and completion costs, high initial production rates with high liquids yields and long reserve life with multiple stacked producing zones.

● Appalachian Basin. 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.

● 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.

● 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.

● 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, 2023
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Leased
Permian Basin (1)	3,003,486	22,463	99.1	%
Mid‑Continent	3,663,657	30,830	99.0	%
Terryville/Cotton Valley/Haynesville	1,301,662	6,725	99.6	%
Appalachian Basin (2)	434,116	16,968	99.8	%
Eagle Ford	476,193	5,059	96.8	%
Barnett Shale/Fort Worth Basin	316,408	3,548	99.1	%
Bakken/Williston Basin (3)	1,214,446	3,132	99.9	%
San Juan Basin	85,604	159	99.2	%
Onshore California	67,139	286	95.7	%
DJ Basin/Rockies/Niobrara	46,398	680	96.1	%
Illinois Basin	11,163	97	100.0	%
Other Western (onshore) Gulf Basin	614,310	4,247	98.0	%
Other TX/LA/MS Salt Basin	308,850	3,841	95.3	%
Other	677,084	3,305	99.1	%
Total (4)	12,220,516	101,340	99.0	%

(1) Includes mineral interests in approximately 1,480,274 gross (10,375 net) acres in the Wolfcamp/Bone Spring.

(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, 2023
	Gross	Net	Percent
Basin or Producing Region	Acres	Acres	Producing
Permian Basin (1)	333,243	4,465	100.0	%
Mid‑Continent	2,205,269	18,002	99.1	%
Terryville/Cotton Valley/Haynesville	127,245	1,194	99.6	%
Appalachian Basin (2)	307,238	6,235	100.0	%
Eagle Ford	147,955	1,671	100.0	%
Barnett Shale/Fort Worth Basin	76,755	593	100.0	%
Bakken/Williston Basin (3)	425,631	3,006	100.0	%
San Juan Basin	98,633	1,313	99.0	%
Onshore California	10,668	22	100.0	%
DJ Basin/Rockies/Niobrara	27,754	356	100.0	%
Illinois Basin	16,848	1,080	100.0	%
Other Western (onshore) Gulf Basin	89,209	1,215	100.0	%
Other TX/LA/MS Salt Basin	45,502	1,443	99.9	%
Other	814,387	15,544	100.0	%
Total (4)	4,726,337	56,139	99.6	%

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

(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, 2023
Permian Basin	50,604
Mid‑Continent	20,898
Terryville/Cotton Valley/Haynesville	16,297
Appalachian Basin	3,929
Eagle Ford	4,277
Barnett Shale/Fort Worth Basin	5,925
Bakken/Williston Basin	5,358
San Juan Basin	1,887
Onshore California	975
DJ Basin/Rockies/Niobrara	12,556
Other	6,657
Total	129,363

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

Our historical reserve estimates as of December 31, 2023, 2022 and 2021 were prepared by Ryder Scott, an independent third party petroleum engineering firm. 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, 2023 is attached as an exhibit to this Annual Report.

Our Chief Executive Officer, Robert D. Ravnaas, has agreed to provide us with reserve engineering services. Mr. R. Ravnaas is a petroleum engineer with over 34 years of reservoir and operations experience. Mr. R. 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:

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

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

● 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

● 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, 2023, 2022 and 2021 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 and undeveloped 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, 2023, 2022 and 2021 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2023, 2022 and 2021, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.22, $93.67 and $66.56 per Bbl for oil and $2.64, $6.36 and $3.60 per MMBtu for natural gas at December 31, 2023, 2022 and 2021, respectively. The price per Bbl for NGLs was modeled as a percentage of oil price, which was derived from historical accounting data. 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,
	2023	2022	2021
Estimated proved developed reserves:
Oil (MBbls)	19,800	12,355	12,511
Natural gas (MMcf)	204,542	160,298	157,764
Natural gas liquids (MBbls)	11,519	7,388	6,669
Total (MBoe)(6:1) (1)	65,409	46,459	45,474

(1) Estimated proved developed reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the years ended December 31, 2023, 2022 and 2021 was used, the conversion factor would be approximately 29.66 Mcf per Bbl of oil, 14.7 Mcf per Bbl of oil and 18.5 Mcf per Bbl of oil, respectively.

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, 2023, 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,
	2023		2022		2021
Production Data:
Oil and condensate (Bbls)		2,392,622		1,425,842		1,343,771
Natural gas (Mcf)		23,384,021		20,310,991		19,085,400
Natural gas liquids (Bbls)		1,082,663		746,865		714,494
Total (Boe)(6:1) (1)		7,372,622		5,557,872		5,239,165
Average daily production (Boe/d)(6:1)		20,265		15,025		14,354
Average Realized Prices:
Oil and condensate (per Bbl)	$	76.55	$	91.74	$	64.86
Natural gas (per Mcf)	$	2.55	$	6.04	$	3.51
Natural gas liquids (per Bbl)	$	23.01	$	38.19	$	29.33
Average Unit Cost per Boe (6:1)
Production and ad valorem taxes	$	2.76	$	2.92	$	2.00

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

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development or extension wells that are not dry wells. As of December 31, 2023, we owned mineral or royalty interests in over 129,000 gross productive wells, which consisted of over 94,000 oil wells and over 34,000 natural gas wells.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to the acreage underlying our mineral and nonparticipating royalty interests at December 31, 2023:

	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	5,235,677		61,790		5,297,467
Oklahoma	2,464,825		34,131		2,498,956
North Dakota	1,097,983		1,000		1,098,983
Wyoming	301,330		771		302,101
Kansas	608,320		2,001		610,321
Louisiana	618,711		1,045		619,756
Arkansas	407,848		1,218		409,066
Montana	165,955		5,059		171,014
New Mexico	211,391		3,146		214,537
Utah	144,053		—		144,053
Other	836,591		17,671		854,262
Total	12,092,684	(1)	127,832	(2)	12,220,516

(1) Reflects mineral interests in approximately 12,092,684 total gross (91,580 net) developed acres.

(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, 2023:

	Developed		Undeveloped		Total
State	Acreage		Acreage		Acreage
Texas	1,415,796		680		1,416,476
Oklahoma	1,346,250		19,000		1,365,250
North Dakota	419,177		—		419,177
Wyoming	350,846		—		350,846
Utah	235,432		—		235,432
Colorado	192,402		—		192,402
Pennsylvania	124,298		—		124,298
West Virginia	116,938		—		116,938
Louisiana	119,062		450		119,512
New Mexico	113,946		960		114,906
Other	271,075		25		271,100
Total	4,705,222	(1)	21,115	(2)	4,726,337

(1) Reflects ORRIs in approximately 4,705,222 total gross (56,028 net) developed acres.

(2) Reflects ORRIs in approximately 21,115 total gross (111 net) undeveloped acres.

Drilling Results

As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells. 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 affect production from the acreage underlying our mineral and royalty interests and materially adversely affect 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 continues to provide a narrower scope of federal Clean Water Act jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal Clean Water Act jurisdiction. On August 30, 2021, the U.S. District Court for the District of Arizona vacated and remanded the 2020 Rule, and in June 2021, the EPA and the Army Corp of Engineers announced their intention to initiate a new rulemaking process to restore the pre-2015 definition of “waters of the United States.” The proposed rule was published on December 7, 2021. Following a standard comment period, the EPA and Army Corp of Engineers announced a final rule establishing a revised and “durable” WOTUS definition on December 30, 2022, which restored many of the elements of the 2015 rule. Multiple legal challenges to the 2022 final rule followed. 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. Then in August 2023, the EPA and Army Corps of Engineers released the text of a rule further revising the WOTUS definition to incorporate certain limitations on jurisdictional reach explained in the Supreme Court’s May 2023 decision in Sackett v. EPA. Additional legal challenges to the August 2023 regulation are proceeding in federal courts. If the final rule announced in December 2022 or the new regulation from August 2023 is ultimately implemented, the expansion of Clean Water Act jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.

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

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response

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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, most recently in May 2016, the EPA finalized additional regulations under the federal Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of the regulations applicable to sources in the production and processing segments and removed the transmission and storage segments from the source category, which removes them from the scope of the regulations. However, these 2020 rules are being challenged in the U.S. 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 public comment period for the proposed rule is expected to close in March 2024. More stringent laws and regulations, including finalizing of the draft rule announced in January 2024, may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In response to findings that emissions of greenhouse gases (“GHGs”), including carbon dioxide and methane, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

President Biden has issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden administration’s climate policies. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although Congress has not adopted such legislation at this time, it may do so in the future, and many states continue to pursue regulations to reduce GHG emissions. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Additionally, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. As an example, the United States participated in the United Nations Conference on Climate Change in 2015, which led to the creation of the Paris Climate Agreement (the “Paris Agreement”). In April 2016, the United States was one of 175 countries to sign the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered

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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. More recently, President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50 percent to 52 percent from 2005 levels in economy-wide net GHG emissions by 2030, and in November 2021, the international community gathered again in Glasgow at the 26th Conference of the Parties (“COP26”). 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. More recently, the United States and other participating countries reaffirmed these emission reduction goals at the 27th Conference of the Parties (“COP27”) in November 2022. The impacts of these efforts, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international conventions cannot be predicted at this time. 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. The Inflation Reduction Act also imposes the first-ever federal fee on GHG emissions, which focuses on methane emissions.

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

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

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. From time to time, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. In March 2015, the Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for wellbore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. That rule was rescinded in December 2017. This rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision has been appealed. If these requirements went into effect, they could result in delays in operations at well sites and increased costs to make wells productive.

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On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured natural gas wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. In May 2016, the EPA finalized similar rules that impose VOC emissions limits on certain oil and natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions limits for certain new or modified oil and natural gas emissions sources. The EPA is currently reconsidering the rules and has proposed to stay their requirements. However, the rules currently remain in effect.

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. 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.

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Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. 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, on January 27, 2021, President Biden issued an Executive Order directing 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,” and launch a review of all existing leasing and permitting practices related to fossil fuel development on public lands and waters. The Executive Order also directed federal agencies to eliminate fossil fuel subsidies. 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:

● the location of wells;

● the method of drilling and casing wells;

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

● the rates of production or “allowables”;

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

● the plugging and abandoning of wells; and

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

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

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natural gas that the operators of our properties can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of our properties operate. The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the United States Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

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

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

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

Historically, the natural gas industry has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Oil Sales and Transportation

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

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

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service

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on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax (2.3% for enhanced recovery) on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.

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

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

Title to Properties

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties. Under our secured revolving credit facility, we have granted the lenders a lien on substantially all of the mineral and royalty interests of our wholly owned subsidiaries.

Human Capital Resources

The officers of our General Partner manage our operations and activities. However, neither we, our General Partner nor our subsidiaries have employees. We have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services for us, including the operation of our properties, and we may refer to individuals providing these services as our employees for ease of reference. The compensation for all of our employees is indirectly paid by us pursuant to the management services agreement with Kimbell Operating. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements” for more information regarding such management services agreements.

Our success depends on our ability to continue to attract, retain and motivate qualified employees. We recognize that we are in a competitive marketplace when it comes to finding top talent. As a result, talent acquisition and the retention of employees continue to be a priority initiative for us. We strive to continue to attract, retain and motivate qualified employees by offering competitive compensation and benefits in an inclusive and safe workplace, with opportunities for our employees to grow and develop in their careers. Our employees may participate in a robust benefits program, which includes a focus on health and wellness, and we offer a variety of other employee perks.

As of December 31, 2023, Kimbell Operating had approximately 29 employees performing services for our operations and activities. Women represent approximately 36% of our workforce, and men represent approximately 64%. We believe that our employees are one of our greatest assets and that we are made up of talented and dedicated employees

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working together to achieve common and rewarding goals. We value integrity, hard work, dedication and teamwork. Our goal is to promote an environment where employees are encouraged to do their best work with high professional standards.

Facilities

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

Additional Information

We electronically file various reports with the SEC including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The SEC maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our website at www.kimbellrp.com. These reports are accessible at no charge through our website and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this Annual Report.

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 (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

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record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.

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.

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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:

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

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

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

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

The Board of Directors is made up of eight members. Therefore, the vote of three directors would be sufficient to prevent us from undertaking the items discussed above. These restrictions may limit our ability to obtain future financings and acquire additional oil and gas properties. 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 16, 2024, the owners of our Sponsors own or control up to an aggregate of approximately 8.4% of our outstanding common units and Class B units (or approximately 6.8% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner. 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:

● neither our partnership agreement nor any other agreement requires our Sponsors or the Contributing Parties to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our Sponsors to undertake acquisition opportunities for themselves or any other investment partnership that they control, and the directors and officers of our Sponsors and the Contributing Parties have a fiduciary duty to make these decisions in the best interests of our Sponsors and such Contributing Parties, which may be contrary to our interests;

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

● many of the officers and directors of our General Partner are also officers or directors of, and equity owners in, our Sponsors and the Contributing Parties and owe fiduciary duties to our Sponsors, or any other investment partnership that they control, and the Contributing Parties and their respective owners;

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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;

● our Sponsors may be constrained by the terms of their current or future debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

● our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities, and restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;

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

● contracts between us, on the one hand, and our General Partner and its affiliates, on the other hand, may not be the result of arm’s length negotiations;

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

● our General Partner determines the amount and timing of acquisitions and dispositions, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

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

● our partnership agreement does not restrict our General Partner from causing us to reimburse it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

● we have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with entities controlled by affiliates of certain of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us, and such entities also provide these services to certain other entities, including certain of the Contributing Parties;

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

● our General Partner may exercise its right to call and purchase all of the common units and Class B units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units and Class B units (taken as a single class);

● our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including under the contribution agreement entered into in connection with our IPO and other agreements with our Sponsors and the Contributing Parties; and

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

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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.

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

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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.

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:

● whenever our General Partner (acting in its capacity as our General Partner), the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our General Partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in, or not adverse to, our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;

● our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

● our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful; and

● our General Partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

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

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

● determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from third parties; or

● determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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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.

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:

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

● whether to exercise its limited call right;

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

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

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

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

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

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(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). As of February 16, 2024, the owners of our Sponsors own or control an aggregate of approximately 8.4% of our outstanding common units and Class B units (or approximately 6.8% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner.

Our 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 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”). As of February 16, 2024, the owners of our Sponsors own or control up to an aggregate of approximately 8.4% of our outstanding common

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units and Class B units (or approximately 6.8% of our units, including our Series A preferred units on an as-converted basis), and our Sponsors indirectly own and control our General Partner.

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.

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:

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

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

● the ratio of our taxable income to distributions may increase;

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

● 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, 2023, we had 73,851,458 common units outstanding and 20,847,295 Class B units outstanding. Our Class B units are exchangeable on a one-for-one basis, together with an equal number of 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.

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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:

● changes in commodity prices;

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

● fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

● changes in market valuations of similar companies;

● departures of key personnel;

● commencement of or involvement in litigation;

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

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

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

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

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

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

● future sales of our common units; and

● the other factors described in these “Risk Factors.”

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

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.

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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 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. 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:

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

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

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

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

● the price and quantity of foreign imports;

● the level of United States domestic production;

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

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

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

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

● the level of consumer product demand;

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

● risks associated with operating drilling rigs;

● technological advances affecting energy consumption;

● domestic and foreign governmental regulations and taxes;

● the continued threat of terrorism and the impact of military and other action, including military actions involving Russia and Ukraine and the conflict in the Middle East;

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

● the price and availability of alternative fuels; and

● overall domestic and global economic conditions.

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 $(36.98) per Bbl in April 2020 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. On December 29, 2023, the WTI posted price for crude oil was $71.89 per Bbl and the Henry Hub spot market price of natural gas was $2.58 per MMBtu. On February 5, 2024, the WTI posted price for crude oil was $73.21 per Bbl and the Henry Hub spot market price of natural gas was $2.12 per MMBtu. 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, 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 on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis.

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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:

● unusual or unexpected geological formations;

● loss of drilling fluid circulation;

● title problems;

● facility or equipment malfunctions;

● unexpected operational events;

● shortages or delivery delays of equipment and services;

● compliance with environmental and other governmental requirements; and

● adverse weather conditions.

Any 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:

● production is less than expected;

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

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

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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 $550.0 million. On December 8, 2023, we amended our secured revolving credit facility to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 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:

● incur or guarantee additional debt;

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

● make certain investments and acquisitions;

● incur certain liens or permit them to exist;

● enter into certain types of transactions with affiliates;

● merge or consolidate with another company; and

● transfer, sell or otherwise dispose of assets.

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

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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 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, 2023, we had approximately $294.2 million in borrowings outstanding under our senior secured credit facility. Our existing and any future indebtedness could have important consequences to us, including:

● our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;

● covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

● our access to the capital markets may be limited;

● our borrowing costs may increase;

● we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

● our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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, 2023, we received revenue

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from approximately 1,100 operators and we received approximately 38.0% of revenues from the top ten purchasers of our properties. During the year ended December 31, 2023, payments we received from our top purchaser accounted for approximately 6.7% 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:

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

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

● prevailing commodity prices;

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

● the operators’ expertise, operating efficiency and financial resources;

● approval of other participants in drilling wells;

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

● the selection of technology;

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

● the rate of production of the reserves.

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

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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 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:

● recoverable reserves;

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

● development plans;

● operating costs; and

● potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. 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

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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.

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:

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

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

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

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

● mistaken assumptions about the overall cost of equity or debt;

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

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

● the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

In addition, we entered into a transition services agreement in connection with the LongPoint Acquisition, and we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire. 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. Although a portion of the mineral and royalty interests acquired in connection with the dropdown were subject to the right of first offer provided by the Contributing Parties, that right of first refusal is now expired, and there can be no assurance that, should the Contributing Parties choose to sell any additional mineral and royalty interests, any offer will be made to us, and there can be no assurance we will reach agreement on the terms with respect to the assets or any other acquisition opportunities offered to us by any of our Sponsors and the Contributing Parties or be able to obtain financing for such acquisition opportunities. 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.

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

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

Our estimated reserves are based on many assumptions that may prove to be inaccurate. 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, 2023, 2022 and 2021 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us. 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, 2023, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 14.1%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. 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.

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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.

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,

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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 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

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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.

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.

We will be required to take write-downs of the carrying values of our proved properties if commodity prices decrease to a level such that the future cash flows discounted at 10% from our proved properties are less than their carrying value.

Accounting standards require that we periodically review the carrying value of our properties for possible impairment. 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 recorded an impairment on our oil and natural gas properties of $18.2 million for the year ended December 31, 2023 as a result of the decline in oil and natural gas prices. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

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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. President Biden also issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions during the prior administration that may be inconsistent with the current administration’s policies. Further actions of President Biden, and the Biden Administration, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.

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:

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

● the establishment of maximum rates of production from wells;

● the spacing of wells;

● the plugging and abandonment of wells; and

● the removal of related production equipment.

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.

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

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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 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.

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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 response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. 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. Recently, President Biden has issued Executive Orders seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies, including, for example, directing the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.  An 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

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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. Initiatives to implement pledges made at COP26, the Paris Agreement goals or other or similar initiatives or regulatory changes could result in increased costs of development and production, reducing the profits available to us and potentially impairing our operators’ ability to economically develop our properties.

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.

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.

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

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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.

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.

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 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.

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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 2023 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 to assess and manage our material risks from cybersecurity threats with assistance from third-party service providers.

Our Chief Operating Officer and Security Officer/Director of IT oversee our cybersecurity policies and processes, including those described in “Risk Management and Strategy” above. 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 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.

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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

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the NYSE under the symbol “KRP.” As of February 16, 2024, there were 73,851,458 common units outstanding held by 146 holders of record and 20,847,295 Class B units outstanding held by 21 holders of record. 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 approximately 25% of our cash available for distribution on common units for the fourth quarter of 2023 for the repayment of $13.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2023. 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.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

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.

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities, although the Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well.

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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 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:

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

● 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

● 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

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for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter;

● less the amount of cash reserves established by the managing member of the Operating Company to:

● provide for the proper conduct of the business of the Operating Company and its subsidiaries (including reserves for future capital expenditures and for future credit needs of the Operating Company and its subsidiaries);

● comply with applicable law or any debt instrument or other agreement or obligation to which the managing member of the Operating Company, the Operating Company or any of their subsidiaries is a party or to which its assets are subject; and

● provide funds for distributions to the Operating Company’s unitholders for any one or more of the next four quarters.

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:

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

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

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

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

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

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 16, 2024, we had 20,847,295 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

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Class B Contribution subsequent to distributions on the Series A preferred units but prior to distributions on our common units.

Common Units

As of February 16, 2024, we had 75,851,458 common units outstanding. 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, 2023.

Unregistered Sales of Equity Securities

On May 17, 2023, in connection with the closing of the MB Minerals Acquisition, we and the Operating Company issued (a) 5,369,218 Opco common units and an equal number of Class B units and (b) 557,302 common units, to MB Minerals, L.P., a Delaware limited partnership, Barry K. Clark, Michael F. Dignam Jr., Thomas A. Medary, Wayne A. Psencik in a private placement.

On September 13, 2023, in connection with the closing of the LongPoint Acquisition, we completed the private placement of 325,000 Series A preferred units to certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) for $1,000 per Series A preferred unit, resulting in gross proceeds to us of $325.0 million (the “Preferred Unit Transaction”). We used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company (“OpCo preferred units”). The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition.

On September 28, 2023, we issued 6,323 common units to Ranch Road Holdings, LLC in exchange for 6,323 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018 (the “Exchange Agreement”), by and among us, the General Partner, the Operating Company and the other holders of OpCo Common Units and Class B units from time to time party thereto.

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.

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We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For further information on items that could impact our future operating performance or financial condition, please read the sections entitled “Risk Factors” and “Forward-Looking Statements” elsewhere in this Annual Report.

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. 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.

As of December 31, 2023, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres located in the Permian Basin and Mid-Continent. As of December 31, 2023, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including approximately 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin.

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of December 31, 2023:

Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	495	396	2.55	2.22
Mid‑Continent	139	68	0.96	0.52
Terryville/Cotton Valley/Haynesville	66	30	0.51	0.37
Appalachian Basin	3	9	0.01	0.02
Bakken/Williston Basin	55	148	0.13	0.11
Eagle Ford	45	61	0.33	0.47
DJ Basin/Rockies/Niobrara	4	15	0.06	0.12
Total	807	727	4.55	3.83

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

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The following table summarizes estimates of our remaining horizontal drilling inventory by basin as of December 31, 2023:

Basin or Producing Region	Gross Locations(1)	Net Locations(1)	Average Gross Horizontal Wells/DSU(2)
Permian Basin	5,216	32.14	12.0
Mid‑Continent	2,440	12.64	6.8
Haynesville	1,022	12.90	5.9
Appalachia	257	2.13	7.6
Bakken	1,708	3.59	8.5
Eagle Ford	1,577	14.42	6.9
Rockies	197	1.27	10.5
Total	12,417	79.09	8.3

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

(2) Gross horizontal wells per drilling spacing unit (“DSU”) from our internal reserves database as of December 31, 2023. DSUs vary in size.

Recent Developments

Acquisitions

On May 17, 2023, we completed the MB Minerals Acquisition. The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo common units and an equal number of Class B Units and (b) 557,302 common units. We funded the cash payment of the purchase price with borrowings under our secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas.

On September 13, 2023, we completed the LongPoint Acquisition in a cash transaction valued at approximately $455.0 million. We funded the cash transaction with borrowings under our secured revolving credit facility and net proceeds from the Preferred Unit Transaction.

Series A Preferred Units

On August 2, 2023, we entered into a Series A preferred unit purchase agreement with the Series A Purchasers to issue and sell up to 400,000 Series A preferred units. On September 13, 2023, in connection with the closing of the LongPoint Acquisition, we completed the Preferred Unit Transaction. We used the net proceeds from the Preferred Unit Transaction to purchase 325,000 OpCo preferred units. The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation.

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 breaches its 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 their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

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Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to our liquidation, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.

At any time on or after the second anniversary of the original issuance date, we will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) we have an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years. The Series A preferred units may be redeemed by us at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the original issuance date, a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units.

In connection with the issuance of the Series A preferred units, we granted holders of the Series A preferred units board observer rights beginning on the fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date.

The terms of the 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.

Equity Offering

On August 7, 2023, we completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). We used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under our secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes.

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Quarterly Distributions

On February 21, 2024, the Board of Directors declared a quarterly cash distribution of $0.43 per common unit and $0.453897 per OpCo common units for the quarter ended December 31, 2023. We intend to pay the distributions on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024.

As to us, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by us in the fourth quarter of 2023. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.

We will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2023. We intend to pay the distribution subsequent to March 13, 2024 and prior to the distribution on the common units and OpCo common units.

Business Environment

Global Conflicts

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. As noted above, the supply and demand imbalance resulting from various OPEC announcements, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine and in the Middle East, have created increased volatility in oil and natural gas prices. The table below demonstrates such volatility for the periods presented as reported the United States Energy Information Administration (the “EIA”).

	Year Ended December 31, 2023				Year Ended December 31, 2022				Year Ended December 31, 2021
	High		Low		High		Low		High		Low
Oil ($/Bbl)	$	93.67	$	66.61	$	123.64	$	71.05	$	85.64	$	47.47
Natural gas ($/MMBtu)	$	3.78	$	1.74	$	9.85	$	3.46	$	23.86	$	2.43

On February 5, 2024, the WTI posted price for crude oil was $73.21 per Bbl and the Henry Hub spot market price of natural gas was $2.12 per MMBtu.

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

	Year Ended December 31,
	2023		2022		2021
Oil ($/Bbl)	$	77.58	$	94.90	$	68.14
Natural gas ($/MMBtu)	$	2.53	$	6.45	$	3.89

Rig Count

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

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The Baker Hughes United States Rotary Rig count decreased 21% to 602 active land rigs at December 31, 2023 compared to 762 active land rigs at December 31, 2022. The overall decrease in rig count December 31, 2023 compared December 31, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas.

The 762 active rig count at December 31, 2022 increased significantly compared to 570 active land rigs at December 31, 2021. The increase in rig count for the 2022 period was primarily attributable to an uptake in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.

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

	December 31,
Basin or Producing Region	2023	2022	2021
Permian Basin	50	47	25
Mid‑Continent	17	12	8
Terryville/Cotton Valley/Haynesville	13	15	12
Appalachian Basin	3	1	1
Bakken/Williston Basin	6	6	6
Eagle Ford	8	7	6
DJ Basin/Rockies/Niobrara	1	—	1
Other	—	4	2
Total	98	92	61

Sources of Our Revenue

Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our 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,
	2023		2022		2021
Revenue
Oil revenue	69	%	46	%	50	%
Natural gas revenue	22	%	44	%	38	%
NGL revenue	9	%	10	%	12	%
	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through December 2025, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 4—Derivatives.”

Reserves and Pricing

The tables below identify our proved reserves at December 31, 2023, 2022 and 2021, in each case based on the reserve report prepared by Ryder Scott. The prices used to estimate proved reserves for the respective periods were held

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constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

	December 31,
Estimated Net Proved Reserves	2023	2022	2021
Oil (MBbls)	19,800	12,355	12,511
Natural gas (MMcf)	204,542	160,298	157,764
Natural gas liquids (MBbls)	11,519	7,388	6,669
Total (MBoe)(6:1)	65,409	46,459	45,474

	December 31,
Unweighted Arithmetic Average First‑Day‑of‑the‑Month Prices	2023		2022		2021
Oil (Bbls)	$	78.22	$	93.67	$	66.56
Natural gas (Mcf)	$	2.64	$	6.36	$	3.60

Factors Affecting the Comparability of Our Results

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

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, 2023, 2022 and 2021 include the MB Minerals Acquisition, the Longpoint Acquisition, the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”) and the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”).

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

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. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.

We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.

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.

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General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services. We 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,
	2023		2022		2021
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021
Lease bonus and other income		5,594,855		3,073,609		3,319,104
Gain (loss) on commodity derivative instruments, net		20,888,972		(36,978,550)		(42,791,909)
Total revenues		294,068,612		248,059,185		135,615,216
Costs and expenses
Production and ad valorem taxes		20,326,477		16,238,814		10,480,481
Depreciation and depletion expense		96,477,003		50,086,414		36,797,881
Impairment of oil and natural gas properties		18,220,173		—		—
Marketing and other deductions		12,564,619		13,383,074		12,048,643
General and administrative expense		35,677,851		29,128,659		26,977,519
Consolidated variable interest entities related:
General and administrative expense		927,699		2,304,445		—
Total costs and expenses		184,193,822		111,141,406		86,304,524
Operating income		109,874,790		136,917,779		49,310,692
Other income (expense)
Equity income in affiliate		—		2,668,844		1,119,819
Interest expense		(25,950,600)		(13,818,310)		(9,182,103)
Loss on extinguishment of debt		(480,244)		—
Other (expense) income		(180,765)		4,043,530		1,263,566
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		3,508,691		3,721,145		—
Net income before income taxes		86,771,872		133,532,988		42,511,974
Income tax expense		3,766,302		2,738,702		74,100
Net income		83,005,570		130,794,286		42,437,874
Distribution and accretion on Series A preferred units		(6,310,215)		—		(11,249,969)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(16,464,890)		(18,822,552)		(8,496,104)
Distribution on Class B units		(88,786)		(42,243)		(76,780)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Production Data:
Oil (Bbls)		2,392,622		1,425,842		1,343,771
Natural gas (Mcf)		23,384,021		20,310,991		19,085,400
Natural gas liquids (Bbls)		1,082,663		746,865		714,494
Combined volumes (Boe) (6:1)		7,372,622		5,557,872		5,239,165

Comparison of the Year Ended December 31, 2023 to the Year Ended December 31, 2022 and the Year Ended December 31, 2022 to the Year Ended December 31, 2021

Oil, Natural Gas and NGL Revenues

For the year ended December 31, 2023, our oil, natural gas and NGL revenues were $267.6 million, a decrease of $14.4 million from $282.0 million for the year ended December 31, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the year ended December 31, 2023 as discussed below.

Our revenues for the year ended December 31, 2022 increased by $106.9 million, from $175.1 million for the year ended December 31, 2021. The significant increase in oil, natural gas and NGL revenues was primarily related to the increase in the average prices we received for oil, natural gas and NGL production, and to a lesser extent, an increase in production volumes for the year ended December 31, 2022 as discussed below.

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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 7,372,622 Boe or 20,265 Boe/d, for the year ended December 31, 2023, an increase of 1,814,750 Boe or 5,240 Boe/d, from 5,557,872 Boe or 15,025 Boe/d, for the year ended December 31, 2022. The increase in production for the year ended December 31, 2023 was primarily attributable to production associated with the Hatch Acquisition, which included a full year of production for the year ended December 31, 2023, compared to approximately three months of production for the year ended December 31, 2022, the MB Minerals Acquisition, and to a lesser extent, production associated with the LongPoint Acquisition.

Our production volumes for the year ended December 31, 2022 increased by 318,707 Boe or 671  Boe/d, from 5,239,165 Boe or 14,354 Boe/d, for the year ended December 31, 2021. The increase in production for the year ended December 31, 2022 was primarily attributable to production associated with the Cornerstone Acquisition, which included a full year of production for the year ended December 31, 2022, compared to approximately three months of production for the year ended December 31, 2021, and to a lesser extent, production associated with the Hatch Acquisition.

Our operators received an average of $76.55 per Bbl of oil, $2.55 per Mcf of natural gas and $23.01 per Bbl of NGL for the volumes sold during the year ended December 31, 2023 and $91.74 per Bbl of oil, $6.04 per Mcf of natural gas and $38.19  per Bbl of NGL for the volumes sold during the year ended December 31, 2022. The year ended December 31, 2023 decreased 16.6% or $15.19 per Bbl of oil and 57.8% or $3.49 per Mcf of natural gas compared to the year ended December 31, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 18.3% or $17.32 per Bbl of oil and 60.8% or $3.92 per Mcf of natural gas for the comparable periods.

Average prices received by our operators during the year ended December 31, 2022 increased 41.4% or $26.88 per Bbl of oil and 72.1% or $2.53 per Mcf of natural gas compared to the year ended December 31, 2021, which our operators received an average of $64.86 per Bbl of oil, $3.51 per Mcf of natural gas and $29.33 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 39.3% or $26.76 per Bbl of oil and 65.8% or $2.56 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

For the year ended December 31, 2023 lease bonus and other income was $5.6 million, an increase of $2.5 million compared to $3.1 million for the year ended December 31, 2022. The increase in lease bonus and other income is primarily related to legal settlements received during the year ended December 31, 2023.

Our lease bonus and other income remained relatively flat at $3.3 million for the year ended December 31, 2021, compared to December 31, 2022.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the year ended December 31, 2023 included $26.4 million of mark-to-market gains and $5.5 million of losses on the settlement of commodity derivative instruments compared to $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2022. We recorded a mark-to-market gain for the year ended December 31, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was partially offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the year ended December 31, 2022 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the losses on the settlement of commodity derivative instruments.

Loss on commodity derivative instruments for the year ended December 31, 2021 included $22.1 million of mark-to-market losses and $20.7 million of losses on the settlement of commodity derivative instruments.

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Production and Ad Valorem Taxes

Production and ad valorem taxes for the year ended December 31, 2023 were $20.3 million, an increase of $4.1 million from $16.2 million for the year ended December 31, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition. The increase was partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.

For the year ended December 31, 2022, production and ad valorem taxes increased by $5.7 million from $10.5 million for the year ended December 31, 2021. The increase in production and ad valorem taxes was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2022, and to a lesser extent, production and ad valorem taxes associated with the Cornerstone Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the year ended December 31, 2023 was $96.5 million, an increase of $46.4 million from $50.1 million for the year ended December 31, 2022. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.

For the year ended December 31, 2022, depreciation and depletion expense increased by $13.3 million from $36.8 million for the year ended December 31, 2021. The increase in depreciation and depletion expense was due to the Cornerstone Acquisition and the Hatch Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $13.03 for the year ended December 31, 2023, an increase of $4.19 per barrel from the $8.84 average depletion rate per barrel for the year ended December 31, 2022. 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.

For the year ended December 31, 2022, our average depletion rate per barrel increased by $2.06 per barrel from the $6.78 average depletion rate per barrel for the year ended December 31, 2021. The increase in our average depletion rate per barrel was due to the Cornerstone Acquisition and the Hatch Acquisition, which collectively increased our net capitalized oil and natural gas properties.

Impairment of Oil and Natural Gas Properties

We recorded an impairment on our oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the years ended December 31, 2022 and 2021.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the year ended December 31, 2023 were $12.6 million, a decrease of $0.8 million from $13.4 million for the year ended December 31, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition, and to a lesser extent, the LongPoint Acquisition.

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Marketing and other deductions for the year ended December 31, 2022 increased by $1.4 million from $12.0 million for the year ended December 31, 2021. The increase in marketing and other deductions was primarily attributable the increase in prices for oil, natural gas and NGL production.

General and Administrative Expense

General and administrative expenses for the year ended December 31, 2023 were $35.7 million, an increase of $6.6 million from $29.1 million for the year ended December 31, 2022. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $2.0 million increase in unit-based compensation expense, expenses related to a one-time cash bonus paid to employees and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

General and administrative expenses for the year ended December 31, 2022 increased by $2.1 million from $27.0 million for the year ended December 31, 2021. The increase in general and administrative expenses was primarily attributable to legal and professional fees incurred related to the special meeting of unitholders of the Partnership in May 2022, at which our unitholders approved the adoption of our Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan and our Amended and Restated Agreement of Limited Partnership, and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

Interest Expense

Interest expense for the year ended December 31, 2023 was $26.0 million as compared to interest expense of $13.8 million for the year ended December 31, 2022. The increase in interest expense was primarily due to an increase in the weighted average interest rate on our outstanding borrowings  from 5.28% at December 31, 2022 to 8.62% at December 31, 2023. Also contributing to the increase in interest expense was an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition, the MB Minerals Acquisition and the LongPoint Acquisition.

Interest expense for the year ended December 31, 2022 increased by $4.6 million compared to interest expense of $9.2 million for the year ended December 31, 2021. The increase in interest expense was primarily due to debt incurred in the latter part of 2021 to fund the redemption of the Series A preferred units and the Cornerstone Acquisition and additional debt incurred in 2022 to fund the purchase of private placement warrants concurrently with the TGR IPO and to fund the cash purchase price paid in the Hatch Acquisition. Also contributing to the increase in interest expense was an increase in the weighted average interest rate from 3.86% at December 31, 2021 to 5.28% at December 31, 2022.

Income Tax Expense

For the year ended December 31, 2023, we recognized an income tax expense of $3.8 million, resulting in an effective tax rate of 4.34%, compared to income tax expense of $2.7 million for the year ended December 31, 2022, resulting in an effective tax rate of 2.05%. We recognized an income tax expense of $0.1 million for the year ended December 31, 2021, resulting in an effective tax rate of 0.17%. The overall change in our effective tax rate for the year ended December 31, 2023 is primarily due estimated current federal and state income tax that cannot be sheltered by a net operating loss carryforward.

Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of December 31, 2023, 2022 and 2021, we recorded a full valuation allowance on our deferred tax assets. 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

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and royalty interests in oil and natural gas properties. On June 13, 2023, we entered into the A&R Credit Agreement (as defined below). On July 24, 2023, we entered into the First Amendment (as defined below) to the A&R Credit Agreement that, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit us to issue certain preferred equity interests. On December 8, 2023, we entered into the Second Amendment (as defined below) to the A&R Credit Agreement that, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million. See “Indebtedness” below for further discussion of our secured revolving credit facility.

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 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 2023 for the repayment of $13.8 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2023. 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.

We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.

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, we issued 5,369,218 OpCo common units and an equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition and we completed the LongPoint Acquisition partially with net proceeds from the Preferred Unit Transaction. 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 2023 distributions.

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Cash Flows

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

	Year Ended December 31,
	2023		2022		2021
Cash Flow Data:
Net cash provided by operating activities	$	174,267,667	$	166,636,493	$	91,442,481
Net cash used in investing activities		(246,676,974)		(374,723,901)		(55,572,551)
Net cash provided by (used in) financing activities		78,375,409		226,061,562		(38,622,493)
Net increase (decrease) in cash and cash equivalents	$	5,966,102	$	17,974,154	$	(2,752,563)

Operating Activities

Operating cash flow is impacted by many variables, the most significant of which are the changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs we receive from our operators on those volumes. 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, 2023 were $174.3 million, an increase of $7.7 million compared to $166.6 million for the year ended December 31, 2022.

Cash flows provided by operating activities for the year ended December 31, 2022 increased by $75.2 million compared to $91.4 million for the year ended December 31, 2021. The increase in cash flows provided by operating activities was primarily attributable to the increase in the average prices we received for oil, natural gas and NGL production for the year ended December 31, 2022.

Investing Activities

Cash flows used in investing activities for the year ended December 31, 2023 were $246.7 million compared to $374.7 million for the year ended December 31, 2022. For the year ended December 31, 2023, cash flows used in investing activities included $490.7 million used to fund costs associated with the MB Minerals Acquisition and the LongPoint Acquisition and $0.1 million used to fund the purchase of equipment, partially offset by $243.2 million of cash received from investment held in trust related to TGR and $0.9 million in cash received from the dissolution of TGR.

Cash flows used in investing activities for the year ended December 31, 2022 include $236.9 million of investments held in marketable securities related to TGR, $141.3 million used primarily to fund the Hatch Acquisition and $0.2 million used to fund the purchase of equipment, partially offset by $3.6 million in cash distributions received in connection to the joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP (the “Joint Venture”).

Cash flows used in investing activities for the year ended December 31, 2022 increased by $319.1 million compared to cash flows used in used in investing activities of $55.6 million for the year ended December 31, 2021. For the year ended December 31, 2021, we used approximately $54.6 million to fund the Cornerstone acquisition, we used $0.8 million primarily to fund the renovation of office space, $0.5 million primarily to fund the acquisition of assets from Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP, partially offset by a $0.5 million cash distribution received in connection with the Joint Venture during the period.

Financing Activities

Cash flows provided by financing activities were $78.4 million for the year ended December 31, 2023 compared to $226.1 million of cash flows provided by financing activities for the year ended December 31, 2022. 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

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units, OpCo common units, Series A preferred units and Class B units, $139.9 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $6.7 million payment of loan origination costs.

Cash flows provided by financing activities for the year ended December 31, 2022 consists of $227.6 million in proceeds from the TGR IPO (these proceeds were held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 equity offering and $0.4 million in contributions from Class B unitholders, partially offset by $183.3 million used to repay borrowings under our secured revolving credit facility, $126.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $3.3 million of restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.

Cash flows used in financing activities for the year ended December 31, 2021 consists of $71.7 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $67.1 million to fund the redemption of Series A preferred units, $91.0 million used to repay borrowings under our secured revolving credit facility, $2.1 million of restricted units repurchased for tax withholding, $0.7 million payment of loan origination costs and $0.2 million paid in connection with the redemption of Class B units, partially offset by $57.5 million in proceeds from the 2021 equity offering and $136.6 million of additional borrowings under our secured revolving credit facility.

Capital Expenditures

During the year ended December 31, 2023, we paid approximately $490.7 million primarily to fund the MB Minerals Acquisition and the LongPoint Acquisition. During the year ended December 31, 2022, we paid approximately $141.3 million primarily to fund the Hatch Acquisition. During the year ended December 31, 2021, we paid approximately $55.3 million, which was primarily attributable to the completion of the Cornerstone acquisition.

Indebtedness

On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

On July 24, 2023, we entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit us to issue certain preferred equity interests.

On December 8, 2023, we entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.

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

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or

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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 2023. 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 the Note 2—Summary of Significant Accounting Policies to our financial statements for a summary of our significant accounting policies.

Method of Accounting for Oil and Natural Gas Properties

We account for oil, natural gas and NGL producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil, natural gas and NGL properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Sales or other dispositions of oil, natural gas and NGL properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil, natural gas and NGL properties is computed on the units of production method, whereby capitalized costs are amortized over total proved reserves. Oil, natural gas and NGL reserve quantities are used as the basis to calculate unit-of-production depletion. Depletion is calculated by taking the ratio of asset costs to total proved reserves applied to actual production. The volumes produced and asset costs are known, while proved reserves are based on estimates that are subject to some variability.

Unevaluated Properties

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves, which is primarily based upon when such properties become producing. 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

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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.

Oil, Natural Gas and NGL Reserve Quantities

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. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. 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.

There are numerous uncertainties inherent in estimating quantities of proved oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve engineering is a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil, natural gas and NGLs that are ultimately recovered. Additionally, we continue to not intend to book PUD reserves.

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.

Full Cost Ceiling Impairment

The net capitalized costs of proved oil, natural gas and NGL properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Estimated future net revenues are calculated as estimated future revenues from oil, natural gas and NGL properties less production taxes, ad valorem taxes and gas marketing expenses. To the extent capitalized costs of evaluated oil, natural gas and NGL properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil, natural gas and NGL reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, prices are calculated as the average oil, natural gas and NGL prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the reporting period.

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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 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, 2023, we had five 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, 2023, 2022 and 2021, our top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of our oil, natural gas and NGL revenues. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of December 31, 2023, we had total borrowings outstanding under our secured revolving credit facility of $294.2 million. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense of approximately $2.9 million annually, assuming that our indebtedness remained constant throughout the year.

On January 27, 2021, we entered into an interest rate swap with Citibank, which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. On May 17, 2022 we entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, we entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The terminations resulted in a $6.4 million gain for the year ended December 31, 2022, which is included in other income (expense) in the accompanying consolidated statements of operations. We used an interest rate swap for the management of interest rate

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risk exposure, as the interest rate swap effectively converted a portion of our secured revolving credit facility from a floating to a fixed rate.

Inflation

Inflation in the United States did not have a material impact on our results of operations for the period from January 1, 2021 through December 31, 2023. However, rising inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. 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.

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 VIEs, 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,
	2023		2022		2021
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	83,005,570	$	130,794,286	$	42,437,874
Depreciation and depletion expense		96,477,003		50,086,414		36,797,881
Interest expense		25,950,600		13,818,310		9,182,103
Cash distribution from affiliate		—		385,326		1,015,559
Income tax expense		3,766,302		2,738,702		74,100
EBITDA		209,199,475		197,823,038		89,507,517
Impairment of oil and natural gas properties		18,220,173		—		—
Unit-based compensation		13,111,522		11,107,639		10,632,725
Loss on extinguishment of debt		480,244		—		—
(Gain) loss on derivative instruments, net of settlements		(26,371,058)		(14,300,570)		20,343,783
Cash distribution from affiliate		—		645,451		500,389
Equity income in affiliate		—		(2,668,844)		(1,119,819)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(3,508,691)		(3,721,145)		—
General and administrative expense		927,699		2,304,445		—
Consolidated Adjusted EBITDA		212,059,364		191,190,014		119,864,595
Adjusted EBITDA attributable to non-controlling interest		(46,475,531)		(27,154,867)		(35,608,960)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		165,583,833		164,035,147		84,255,635
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		18,520,334		9,583,004		5,297,810
Cash distributions on Series A preferred units		4,551,746		—		1,943,385
Restricted units repurchased for tax withholding		—		—		1,433,265
Cash income tax expense		1,641,675		3,082,245		—
Distributions on Class B units		88,786		42,243		76,780
Cash available for distribution on common units	$	140,781,292	$	151,327,655	$	75,504,395

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	Year Ended December 31,
	2023		2022		2021
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:
Net cash provided by operating activities	$	174,267,667	$	166,636,493	$	91,442,481
Interest expense		25,950,600		13,818,310		9,182,103
Income tax expense		3,766,302		2,738,702		74,100
Impairment of oil and natural gas properties		(18,220,173)		—		—
Amortization of right-of-use assets		(336,080)		(319,674)		(298,093)
Amortization of loan origination costs		(1,943,025)		(1,872,700)		(1,556,769)
Loss on extinguishment of debt		(480,244)		—		—
Equity income in affiliate, net		—		(716,481)		1,119,819
Forfeiture of restricted units		—		19,813		—
Unit-based compensation		(13,111,522)		(11,107,639)		(10,632,725)
Gain (loss) on derivative instruments, net of settlements		26,371,058		14,300,570		(20,343,783)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		12,026,760		11,846,567		17,594,389
Accounts receivable and other current assets		(1,863,376)		511,319		2,077,637
Accounts payable		(509,400)		(399,318)		77,716
Other current liabilities		(1,263,804)		(1,590,016)		463,828
Operating lease liabilities		348,668		324,913		306,814
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		3,508,691		3,721,145		—
Other assets and liabilities		687,353		(88,966)		—
EBITDA		209,199,475		197,823,038		89,507,517
Add:
Impairment of oil and natural gas properties		18,220,173		—		—
Unit-based compensation		13,111,522		11,107,639		10,632,725
Loss on extinguishment of debt		480,244		—		—
(Gain) loss on derivative instruments, net of settlements		(26,371,058)		(14,300,570)		20,343,783
Cash distribution from affiliate		—		645,451		500,389
Equity income in affiliate		—		(2,668,844)		(1,119,819)
Consolidated variable interest entities related:
Interest earned on marketable securities in Trust Account		(3,508,691)		(3,721,145)		—
General and administrative expense		927,699		2,304,445		—
Consolidated Adjusted EBITDA		212,059,364		191,190,014		119,864,595
Adjusted EBITDA attributable to non-controlling interest		(46,475,531)		(27,154,867)		(35,608,960)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		165,583,833		164,035,147		84,255,635
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		18,520,334		9,583,004		5,297,810
Cash distributions on Series A preferred units		4,551,746		—		1,943,385
Restricted units repurchased for tax withholding		—		—		1,433,265
Cash income tax expense		1,641,675		3,082,245		—
Distributions on Class B units		88,786		42,243		76,780
Cash available for distribution on common units	$	140,781,292	$	151,327,655	$	75,504,395

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 principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023.

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, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

On September 13, 2023, we completed the Longpoint Acquisition, whose accounts are included in our consolidated financial statements beginning on the acquisition date and reflect total assets and revenues of 33% and 7%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. The scope of our assessment of internal control over financial reporting excludes the Longpoint Acquisition.

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As of December 31, 2023, 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 on this assessment, management has concluded our internal controls over financial reporting were effective as of December 31, 2023.

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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, 2023, 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, 2023, 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, 2023, and our report dated February 21, 2024 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 (“Management’s Report”). 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.

Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Cherry Creek Minerals, LLC, a wholly owned subsidiary, whose financial statements reflect total assets and revenues constituting 7 and 33 percent, respectively, of the related consolidated financial statements amounts as of and for the year ended December 31, 2023. As indicated in Management’s Report, Cherry Creek Minerals, LLC was acquired during 2023. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Cherry Creek Minerals, LLC.

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.

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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 21, 2024

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Item 9B. Other Information

On November 29, 2023, Brett G. Taylor, Executive Vice Chairman of the Board of Directors, adopted a trading plan intended to satisfy Rule 10b5-1(c) to sell up to 125,833 common units between March 1, 2024, and December 31, 2024, subject to certain conditions.

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, 2023. 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, and Messrs. Fortson and Wynne are father-in-law and son-in-law, respectively.

Name	Age	Position With Our General Partner
Robert D. Ravnaas	66	Chief Executive Officer and Chairman of the Board of Directors
R. Davis Ravnaas	38	President and Chief Financial Officer
Matthew S. Daly	51	Chief Operating Officer
R. Blayne Rhynsburger	37	Controller
Brett G. Taylor	63	Executive Vice Chairman of the Board of Directors
Ben J. Fortson	91	Director
T. Scott Martin	73	Director
Mitch S. Wynne	65	Director
William H. Adams III	65	Independent Director
Craig Stone	60	Independent Director
Erik B. Daugbjerg	54	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

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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. 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 38 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.

Ben J. Fortson. Ben J. Fortson was appointed as a director of our General Partner in November 2015. He has nearly 60 years of experience in the oil and gas industry. Mr. Fortson has served as President and Chief Executive Officer of Fortson Oil Company since 1986 and has been Chief Investment Officer and an Executive Vice President or Vice President of the Kimbell Art Foundation, a Contributing Party, since 1975. Mr. Fortson has served on the Board of Trustees of the Kimbell Art Foundation since 1964. He is also a member of the Exchange Club of Fort Worth, a Trustee Emeritus of Texas Christian University and an Emeritus Member of the All-American Wildcatters. Mr. Fortson has a Bachelor of Arts degree from the Texas Christian University. Mr. Fortson was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

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. Mr. Martin has served as Chief Executive Officer and Chairman of EE3 LLC since 2013. 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. He has over 40 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.

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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 38 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 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 23 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

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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 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.”

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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 2023 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 2023 by Ben J. Fortson, related to a single transaction.

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.

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.”

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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, 2023 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.

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 2023. 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

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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 2023 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 2022 to set compensation metrics for 2023 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.

The peer group is comprised of the following fourteen companies:

Black Stone Minerals, L.P.	Laredo Petroleum, Inc.
Brigham Minerals, Inc.	Matador Resources Company
Callon Petroleum Company	Northern Oil and Gas, Inc.
Centennial Resource Development, Inc.	Oasis Petroleum Inc.
Civitas Resources, Inc.	PDC Energy, Inc.
Gulfport Energy Corporation	SM Energy Company
HighPeak Energy, Inc.	Whiting Petroleum Corporation

Key Components of Our 2023 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 2023 consisted of the following key components, which are described in greater detail below:

● Base salary;

● Long-term incentive restricted units;

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

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

● 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.

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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 2023 performance were set in December 2022, with the actual number of restricted units granted determined in February 2024, after the Conflicts and Compensation Committee reviews the Partnership’s 2023 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 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 2023 performance is made in February 2024, 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 2023 in relation to 2022 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 2021 for 2022 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 2023, 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 110.0% of the target restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be granted for 2022 performance, resulting in awards of 204,600, 181,500 and 112,200 restricted units, respectively. As described above, Mr. Rhynsburger’s compensation was determined based on benchmarking of similar positions, and he was granted 15,409 restricted units. Because these grants were made in 2023, they are included in the compensation tables included in this Form 10-K.

In December 2022, the Conflicts and Compensation Committee set the target restricted unit awards for 2023 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 2024, after the review of the achievement of compensation factors, as described below.

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

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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. As described above, Mr. Rhynsburger’s STI Bonus was determined based on benchmarking of similar positions, and he was awarded a STI Bonus of $70,000 for the year ended December 31, 2023.

In December 2022, the Conflicts and Compensation Committee set the target STI Bonuses for 2023 performance at $620,000, $595,000 and $485,000 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 2023 performance was made in February 2024, after the review of the achievement of compensation factors, as described below.

Factors Used for Determining Incentive Compensation and Compensation Decisions for 2023 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 2023, 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.

			Percentage of Target to be Awarded Based on Level of Achievement of Target Objective for 2023
Compensation Factor	Weight	Target Objective for 2023	Below Target Objective		At Target Objective	Above Target Objective
Production growth	20%	0% - 4% Growth	50%		100%	150%
PDP reserve replacement	20%	95% - 100% Replacement	50%		100%	150%
Cash G&A expense per BOE	20%	$2.90 - $3.10	50%		100%	150%
Achievement of core competencies	20%	Committee Discretion	50%		100%	150%
			Percentage of Target to be Awarded Based on Peer Ranking of TSR for Calendar Year 2023
Relative unitholder return	20%	Peer Ranking of TSR(1)	4th	3rd	2nd	1st
			50%	75%	150%	200%

(1) Ranking of total shareholder return (“TSR”) for calendar year 2023 include the following companies: KRP, Black Stone Minerals, L.P., Viper Energy Partners LP and Sitio Royalties Corp. If a peer company is acquired during year, TSR will be calculated from January 1, 2023 through the day of the deal closing.

Pearl Meyer’s analysis determined that the proposed 2023 compensation at the target levels was below the median of the peer group for Messrs. Robert D. Ravnaas and R. Davis Ravnaas and above the median for Matthew S. Daly.

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The chart below displays our actual 2023 results for each compensation.

Compensation Factor	Weight	Target Objective for 2023	Actual 2023 Results for the Partnership	Actual 2023 Results Compared to Target Objectives
Production growth	20%	0% - 4% Growth	33% Growth	Above Target
PDP reserve replacement	20%	95% - 100% Replacement	248% Replacement	Above Target
Cash G&A expense per BOE	20%	$2.90 - $3.10	$2.73 (1)	Above Target
Achievement of core competencies	20%	Committee Discretion	At Target	At Target
Relative unitholder return	20%	Peer Ranking of TSR	3rd	Below Target

(1) Excludes the impact of one-time transaction and integration costs associated with the LongPoint Acquisition.

The 2023 STI Bonuses and restricted unit awards were calculated using the respective percentage of level of achievement of each target objective and multiplying it by the target STI Bonuses and restricted unit award. Our actual results achieved with respect to three of the four quantitative compensation factors were above the target objective for 2023 and our actual results for the fourth quantitative compensation factor was below the target objective. For the fifth and sole qualitative compensation factor, the Conflicts and Compensation Committee determined that the NEOs had met the target objective for the achievement of core competencies. As each compensation factor was equally weighted at 20% and the actual results achieved for three of the five compensation factors were above the target objective, with actual results for the fourth factor meeting the target objective, and below target objective for the fifth factor, the Conflicts and Compensation Committee determined that the STI Bonuses and restricted unit awards for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be set at amounts equal to 125.0% of their 2023 target amounts. The chart below displays the actual 2023 STI Bonuses earned and restricted unit awards granted for 2023 performance, based on the level of achievement of each compensation factor.

Name	Long-Term Restricted Units Awarded (1)	STI Bonus Earned
Robert D. Ravnaas	232,500	$	775,000
R. Davis Ravnaas	206,250	$	743,750
Matthew S. Daly	127,500	$	606,250
R. Blayne Rhynsburger (2)	15,409	$	70,000

(1) As described above, the restricted units were not granted until February 2024, after the Conflicts and Compensation Committee’s determination of the achievement of 2023 compensation factors.

(2) As described above, Mr. Rhynsburger’s compensation for 2023 was determined pursuant to the compensation programs applicable to employees generally, and not pursuant to the compensation factors described in this CD&A.

Health, Welfare and Additional Benefits

Our NEOs are eligible to participate in the employee benefit plans and programs that the Partnership offers to its employees, subject to the terms and eligibility requirements of those plans.

Retirement Benefits

We currently maintain a 401(k) Plan, which permits all eligible employees, including the NEOs, to make voluntary pre-tax or after-tax (Roth) contributions to the plan. In addition, we are permitted to make discretionary matching contributions under the plan. Company matching contributions vest immediately. All contributions under the plan are subject to certain annual dollar limitations, which are periodically adjusted for changes in the cost of living.

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Compensation Policies and Practices as they Relate to Risk Management

Our management team and our Conflicts and Compensation Committee, with the assistance of our independent compensation consultant, each play a role in evaluating and mitigating any risk that may exist relating to our compensation plans, practices, and policies for all employees, including our NEOs. We reviewed our compensation plans and philosophy and concluded that our compensation programs do not create risks that are reasonably likely to have a material adverse impact on our business or our financial condition. The objective of the review was to identify any compensation plans, practices or policies that may encourage employees to take unnecessary risks that could threaten our company. No such plans, practices or policies were identified.

Conflicts and Compensation Committee Report

The Conflicts and Compensation Committee has reviewed and discussed the compensation discussion and analysis included in this Annual Report on Form 10-K with management and, based on such review and discussions, the Conflicts and Compensation Committee recommended to the Board of Directors that the compensation discussion and analysis be included in this Annual Report on Form 10-K.

Respectfully submitted,

Members of the Conflicts and Compensation Committee,

Mr. William H. Adams III, as Chairman, Mr. Craig Stone, Mr. Erik B. Daugbjerg

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Summary Compensation Table

The table below presents the annual compensation of our Named Executive Officers for the years ended December 31, 2023, 2022 and 2021.

						Non-Equity
				Long-Term		Incentive Plan		Other
Name	Year	Salary		Restricted Units (1)(2)		Compensation (1)(3)		Compensation (4)		Total
Robert D. Ravnaas	2023	$	620,000	$	3,105,828	$	775,000	$	739,161	$	5,239,989
Chairman and CEO	2022	$	575,000	$	3,473,938	$	632,500	$	790,311	$	5,471,749
	2021	$	575,000	$	2,186,663	$	790,625	$	456,380	$	4,008,668
R. Davis Ravnaas	2023	$	595,000	$	2,755,170	$	743,750	$	615,945	$	4,709,865
President and CFO	2022	$	550,000	$	2,689,500	$	605,000	$	615,298	$	4,459,798
	2021	$	550,000	$	1,692,900	$	756,250	$	355,134	$	3,354,284
Matthew S. Daly	2023	$	485,000	$	1,703,196	$	606,250	$	412,798	$	3,207,244
COO	2022	$	450,000	$	1,905,063	$	495,000	$	440,284	$	3,290,347
	2021	$	450,000	$	1,199,138	$	618,750	$	254,625	$	2,522,513
R. Blayne Rhynsburger	2023	$	270,000	$	233,909	$	70,000	$	67,841	$	641,750
Controller	2022	$	250,000	$	232,568	$	70,000	$	67,136	$	619,704
	2021	$	190,000	$	146,390	$	70,000	$	43,349	$	449,739

(1) NEOs receive their long-term incentive restricted units and STI Bonus in the first quarter of the following year, subsequent to year-end results. Long-term incentive restricted units are recognized in the year in which they are awarded, whereas STI Bonuses are recognized in the year in which they are accrued for. As a result, the amounts set forth under “Long-Term Restricted Stock Units” in the table reflect the restricted units that were granted to the executive officers in 2023, the number of which represent the achievement of compensation factors for fiscal 2022.

(2) Amounts reflect the grant date value as determined pursuant to FASB Accounting Standards Codification (“ASC”) Topic 718, “Compensation – Stock Compensation”, without regard to potential forfeitures. Amounts for 2023, 2022 and 2021 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 21, 2023 grant date at $15.18 per common unit, the February 24, 2022 grant date at $16.30 per common unit and the February 25, 2021 grant date at $10.26 per common unit, respectively.

(3) Our non-equity incentive plan compensation consists of the STI Bonus for each of the NEOs.

(4) Amounts reflected in “Other Compensation” are presented in the table below:

		Distributions
		on Long-Term		401(k) Matching		Total Other
Name	Year	Restricted Units		Contributions		Compensation
Robert D. Ravnaas	2023	$	722,661	$	16,500	$	739,161
	2022	$	775,061	$	15,250	$	790,311
	2021	$	441,880	$	14,500	$	456,380
R. Davis Ravnaas	2023	$	599,445	$	16,500	$	615,945
	2022	$	600,048	$	15,250	$	615,298
	2021	$	340,634	$	14,500	$	355,134
Matthew S. Daly	2023	$	396,298	$	16,500	$	412,798
	2022	$	425,034	$	15,250	$	440,284
	2021	$	240,125	$	14,500	$	254,625
R. Blayne Rhynsburger	2023	$	51,341	$	16,500	$	67,841
	2022	$	51,886	$	15,250	$	67,136
	2021	$	30,349	$	13,000	$	43,349

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Grants of Plan-Based Awards

The following table provides information concerning each grant of an award made to a named executive officer for fiscal year 2023.

			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)					Estimated Future Payouts Under Equity Incentive Plan Awards (2)
Name	Grant Date		Minimum		Target		Maximum	Minimum	Target	Maximum	Total (3)
Robert D. Ravnaas	—	$	310,000	$	620,000	$	992,000
	2/21/2023							93,000	186,000	297,600	$	3,105,828
R. Davis Ravnaas	—	$	297,500	$	595,000	$	952,000
	2/21/2023							82,500	165,000	264,000	$	2,755,170
Matthew S. Daly	—	$	242,500	$	485,000	$	776,000
	2/21/2023							51,000	102,000	163,200	$	1,703,196
R. Blayne Rhynsburger	—	$	70,000	$	70,000	$	70,000
	2/21/2023							15,409	15,409	15,409	$	233,909

(1) Amounts in these columns represent the minimum, target, and maximum possible payouts for STI Bonus. The actual value of bonuses paid to our NEOs for 2023 under this program can be found in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table above. STI Bonuses were approved by the Conflicts and Compensation Committee on February 19, 2024.

(2) Amounts in these columns represent the minimum, target, and maximum possible awards for long-term incentive restricted units. The actual number of restricted units granted were: 204,600, 181,500 and 112,200 for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively.

(3) Amounts reflect the grant date value as determined pursuant to FASB Accounting Standards Codification (“ASC”) Topic 718, “Compensation – Stock Compensation”, without regard to potential forfeitures. Amounts reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 21, 2023 grant date at $15.18 per common unit. These amounts are included in the “Long Term Restricted Units” column of the Summary Compensation Table above.

Outstanding Equity Awards

The following table reflects information regarding outstanding unvested restricted units held by our NEOs as of December 31, 2023.

	Unit Awards
	Number of	Market Value of
	Restricted Units that	Restricted Units that
Name	have not vested (1)	have not vested (2)
Robert D. Ravnaas	417,723	$	6,286,731
R. Davis Ravnaas	346,500	$	5,214,825
Matthew S. Daly	229,074	$	3,447,564
R. Blayne Rhynsburger	29,677	$	446,639

(1) The NEO’s outstanding restricted units will generally vest in accordance with the schedule set forth above under “Long-Term Incentive Awards” so long as the NEO remains employed by the Partnership or one of its affiliates through such dates.

(2) Reflects the market value of our common units computed based on the closing price, $15.05, of our common units on December 29, 2023.

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Units Vested

The following table provides information related to the vesting of restricted units held by a named executive officer during fiscal year ended 2023.

Name	Date Vested	Number of Units Acquired on Vesting	Total
Robert D. Ravnaas	3/3/2023	71,043	$	1,143,082
	3/4/2023	71,041	$	1,153,706
	3/5/2023	71,041	$	1,153,706
R. Davis Ravnaas	3/3/2023	55,000	$	884,950
	3/4/2023	55,000	$	893,200
	3/5/2023	54,999	$	893,184
Matthew S. Daly	3/3/2023	38,959	$	626,850
	3/4/2023	38,958	$	632,678
	3/5/2023	38,958	$	632,678
R. Blayne Rhynsburger	3/3/2023	4,756	$	76,524
	3/4/2023	4,756	$	77,237
	3/5/2023	4,755	$	77,221

(1) Value calculated based on the closing price on the NYSE of our common units on the day prior to the vesting date.

Potential Payments upon Termination or Change in Control

Our NEOs are not party to employment or severance agreements or programs that would provide for payments in the event of a termination of employment or change in control.  The terms of the restricted unit awards do, however, have accelerated vesting provisions in certain circumstances. Upon a NEO’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. Upon a change of control, any unvested restricted units will be vested as of the date of such change in control.

The following table presents payments that would occur in the event of death or disability, or change in control, as applicable, as of the last business day of 2023.

	Unit Awards
	Number of	Market Value of
	Restricted Units Vested	Restricted Units Vested
Name	Upon Qualifying Event	Upon Qualifying Event
Robert D. Ravnaas	417,723	$	6,286,731
R. Davis Ravnaas	346,500	$	5,214,825
Matthew S. Daly	229,074	$	3,447,564
R. Blayne Rhynsburger	29,677	$	446,639

Director Compensation

Officers or employees of the Partnership who also serve as directors of our General Partner will not receive additional compensation for such service. Each director of our General Partner who is not employed by Kimbell Operating or engaged by Kimbell Operating through a management services agreement (a “non-employee director”) receives the following cash compensation:

● (i) for a non-independent director, an annual base retainer fee of $75,600 per year or (ii) for an independent director, an annual base retainer fee of $98,400 per year,

● an additional retainer of $15,000 per year for an independent director who serves as a member of the Audit Committee or the Conflicts and Compensation Committee, and

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● all retainers are paid in cash on a quarterly basis in arrears. Our non-employee directors do not receive any meeting fees, but each director is reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Board of Directors or its committees.

In addition to cash compensation, our non-employee directors receive annual equity-based compensation under the LTIP. Our non-employee directors were granted awards under the LTIP on February 21, 2023 consisting of 119,922 restricted units and 117,082 restricted units on each  February 24, 2022 and February 25, 2021.

The following table provides information concerning the compensation of our directors who are not NEOs for the year ended December 31, 2023.

						All Other
Name	Fees Earned		Unit Awards (6)		Compensation		Total
William H. Adams III (1)	$	113,400	$	155,747	$	—	$	269,147
Erik Daugbjerg (1)	$	113,400	$	155,747	$	—	$	269,147
Ben J. Fortson (2)	$	—	$	619,207	$	—	$	619,207
T. Scott Martin (3)	$	75,600	$	114,761	$	—	$	190,361
Craig Stone (1)	$	113,400	$	155,747	$	—	$	269,147
Brett G. Taylor (4)	$	—	$	2,158,535	$	545,000	$	2,703,535
Mitch S. Wynne (5)	$	—	$	619,207	$	120,000	$	739,207

(1) Mr. Adams’, Mr. Daugbjerg’s and Mr. Stone’s Fees Earned include the annual cash retainer fee and committee member fees for each non-employee director, as more fully explained above. Mr. Adams, Mr. Daugbjerg and Mr. Stone each have 19,758 unvested restricted units outstanding as of December 31, 2023.

(2) Mr. Fortson has 81,582 unvested restricted units outstanding as of December 31, 2023.

(3) Mr. Martin’s Fees Earned includes the annual cash retainer fee for each non-employee director, as more fully explained above. Mr. Martin has 14,559 unvested restricted units outstanding as of December 31, 2023.

(4) Mr. Taylor’s All Other Compensation consists of his salary and bonus earned as an employee of Kimbell Operating. Mr. Taylor has 290,315 unvested restricted units outstanding as of December 31, 2023.

(5) Mr. Wynne’s All Other Compensation consists of payments made to K3 Royalties, LLC (“K3 Royalties”) as described in “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Management Services Agreements.” Mr. Wynne has 81,582 unvested restricted units outstanding as of December 31, 2023.

(6) Amounts reflect the grant date value as determined pursuant to FASB ASC Topic 718, “Compensation – Stock Compensation”, without regard to potential forfeitures. The grant date fair value of our common units is computed based on the average of the opening and closing price on the February 21, 2023 grant date at $15.18 per common unit.

Compensation Committee Interlocks and Insider Participation

The Conflicts and Compensation Committee includes the following members: Mr. William H. Adams III, as Chairman, Mr. Craig Stone and Mr. Erik B. Daugbjerg.

None of our officers or employees has been or will be members of the Conflicts and Compensation Committee. None of our executive officers currently serve, or has served during the last year, on the board of directors or compensation committee of a company that has an executive officer that serves on our Board of Directors or Conflicts and Compensation Committee. No member of our Board of Directors is an executive officer of a company in which one of our executive officers currently serves, or has served during the last year, as a member of the board of directors or compensation committee of that company.

Pay Ratio

Pursuant to Item 402(u) of Regulation S-K, we are disclosing the pay ratio and supporting information comparing the median of the annual total compensation of our employees (including full-time, part-time, seasonal and temporary employees) other than Mr. Robert D. Ravnaas, our Chief Executive Officer, and the annual total compensation of our Chief Executive Officer. The pay ratio is calculated in a manner consistent with Item 402(u) of Regulation S-K. For the year ended December 31, 2023, our last completed fiscal year:

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● The median of the annual total compensation of all of our employees, other than our Chief Executive Officer, is $438,038

● The annual total compensation of our Chief Executive Officer is $5,239,989.

● The ratio of the annual total compensation of our Chief Executive Officer to the median of the annual total compensation of all other employees is 12 to 1.

To identify the median employee for 2023 (the “2023 Median Employee”), we reviewed our employee population as of December 31, 2023. For 2023, we used wages reported in Box 1 of IRS Form W-2 during the 12-month period ending on December 31, 2023, as a consistently applied compensation measure. We did not annualize the wages for new employees or employees on unpaid leave of absence who were employed for less than the full fiscal year, or make cost of living adjustments. Based on this methodology, we identified an employee whose compensation was at the median of the employee data.

Once we identified the 2023 Median Employee, we calculated the annual total compensation using the rules applicable to the Summary Compensation Table. With respect to the annual total compensation of our Chief Executive Officer we used the amount reported in the “Total” column for 2023 in the Summary Compensation Table above.

The pay ratio rules provide companies with flexibility to select the methodology and assumptions used to identify the median employee, calculate the median employee’s compensation and estimate the pay ratio. As a result, our methodology may differ from those used by other companies, including those within our industry, and may not be comparable to pay ratios reported by other companies.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table presents information regarding the beneficial ownership of our common units and Class B units as of February 16, 2024 by:

● each unitholder known by us to beneficially hold 5% or more of our common units and Class B units;

● each of our General Partner’s directors and executive officers; and

● all of our General Partner’s directors and executive officers as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless otherwise noted, the address for each beneficial owner listed below is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

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				Percentage of
			Common Units	Common Units
	Common	Class B	Beneficially	Beneficially
Name of Beneficial Owner	Units	Units	Owned (1)	Owned (1)
Kimbell Art Foundation (2)	—	5,135,020	5,135,020	5.4	%
MB Minerals, L.P. (3)	4,541,914	5,369,218	9,911,132	10.5	%
Directors and Officers
Robert D. Ravnaas (4)	1,183,309	—	1,183,309	1.2	%
R. Davis Ravnaas (5)	758,033	—	758,033	*	%
Matthew S. Daly (6)	488,409	—	488,409	*	%
Blayne Rhynsburger (7)	50,191	—	50,191	*	%
Brett G. Taylor (8)	824,666	—	824,666	*	%
Ben J. Fortson (9)	286,025	—	286,025	*	%
Mitch S. Wynne (10)	249,420	—	249,420	*	%
T. Scott Martin (11)	91,682	—	91,682	*	%
William H. Adams III	79,914	—	79,914	*	%
Craig Stone	54,642	—	54,642	*	%
Erik B. Daugbjerg	84,445	—	84,445	*	%
All directors and executive officers as a group (11 persons)	4,150,736	—	4,150,736	4.4	%

* Less than 1%

(1) Assumes the full exchange of all outstanding OpCo common units and Class B units for common units.

(2) The principal business address of the Kimbell Art Foundation is 301 Commerce Street, Suite 2300, Fort Worth, Texas 76102. Ben J. Fortson is Executive Vice President and Chief Investment Officer of the Kimbell Art Foundation. Mr. Fortson was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting or investment power over the securities owned by the Kimbell Art Foundation. Mr. Fortson disclaims beneficial ownership of such securities.

(3) Includes 4,541,914 Common Units that are held of record by EnCap Energy Capital Fund VIII, L.P. (“EnCap Fund VIII”), and 5,369,218 Class B Units (and an equivalent number of OpCo common units) that are held of record by MB Minerals, L.P. EnCap Partners GP is the sole general partner of EnCap Partners, LP, which is the managing member of EnCap Investments Holdings, LLC, a Delaware limited liability company, which is the sole member of EnCap Investments GP, L.L.C., a Delaware limited liability company, which is the general partner of EnCap Investments L.P., which is the general partner of EnCap Equity Fund VIII GP, L.P. and EnCap Equity Fund IX GP, L.P., a Delaware Limited partnership, which are the sole general partners of EnCap Fund VIII and EnCap Fund IX, respectively. EnCap Fund IX is the sole stockholder of Sabalo Midland Basin, which is the general partner of MB Minerals. Therefore, EnCap Partners GP, through its indirect ownership and management of EnCap Fund VIII and MB Minerals, may be deemed to share the right to direct the vote or disposition of the reported Securities. The securities reported above are beneficially owned by MB Minerals, L.P. The principal business address of MB Minerals, L.P. is 9651 Katy Freeway, Suite 600, Houston, TX, 77024.

(4) Robert D. Ravnaas is a partner, member of or trustee in certain entities that directly or indirectly hold, in the aggregate, 937,197 common units, of which 765,586 common units are deemed to be beneficially owned by Mr. Ravnaas and included in the table above. Mr. R. Ravnaas is also a partner or member in certain entities that hold, in the aggregate, 3,076,559 Class B units, however Mr. R. Ravnaas is deemed not to beneficially own any of the Class B units held by such entities. Mr. R. Ravnaas has a pecuniary interest in an aggregate of approximately 765,586 common units and 15,163 Class B units based on his ownership interest in such entities, and Mr. R. Ravnaas disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(5) R. Davis Ravnaas is a partner or member in certain entities that hold, directly or indirectly, in the aggregate, 147,986 common units, of which 35,627 common units are deemed to be beneficially owned by Mr. Ravnaas and included in the table above. Mr. D. Ravnaas is also a partner or member in certain entities that hold, in the aggregate 3,076,559 Class B units, however Mr. D. Ravnaas is deemed not to beneficially own any of the Class B units held by such entities. Mr. D. Ravnaas has a pecuniary interest in an aggregate of approximately 35,627 common units and 15,163

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Class B units based on his ownership interest in such entities, and Mr. D. Ravnaas disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(6) Matthew Daly is a member of an entity that holds 2,813,179 Class B units, however Mr. Daly is not deemed to beneficially own any of the Class B units held by such entity. Mr. Daly has a pecuniary interest in approximately 3,516 Class B units owned by the entity based on his ownership interest in that entity, and Mr. Daly disclaims beneficial ownership of the securities that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.

(7) Blayne Rhynsburger is a member of an entity that indirectly holds 2,813,179 Class B units, however Mr. Rhynsburger is not deemed to beneficially own any of the Class B units held by such entity. Mr. Rhynsburger has a pecuniary interest in approximately 563 Class B units owned by the entity based on his ownership interest in that entity, and Mr. Rhynsburger disclaims beneficial ownership of the securities that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.

(8) Brett G. Taylor is a partner in, member of or sole trustee of certain entities that hold, directly or indirectly, in the aggregate, 140,263 common units, and Mr. Taylor may be deemed to have voting or investment power with respect to such common units. Mr. Taylor has a pecuniary interest in an aggregate of approximately 120,263 common units based on his ownership interest in such entities, and Mr. Taylor disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(9) Ben J. Fortson is Executive Vice President and Chief Investment Officer of the Kimbell Art Foundation. Pursuant to a Schedule 13D/A filed on September 21, 2021, on September 14, 2021 Kimbell Art Foundation formed a four-person Investment Committee, of which Mr. Fortson serves as Chair, with authority to manage the investments of Kimbell Art Foundation, including but not limited to the power to buy, dispose of and vote, or to direct the acquisition, disposition and voting, of investment assets owned by Kimbell Art Foundation. Decisions of such committee are made by majority vote of the members of the committee. As a result, as of such date, Mr. Fortson no longer was deemed to have sole voting and investment power over the securities owned by Kimbell Art Foundation and Mr. Fortson is no longer considered a beneficial owner of such securities. Mr. Fortson is a member, sole shareholder or trustee of certain entities that hold, directly or indirectly, in the aggregate, approximately 48,642 common units, and Mr. Fortson may be deemed to have voting or investment power with respect to such common units. Mr. Fortson has a pecuniary interest in an aggregate of approximately 23,642 common units based on his ownership interest in such entities, and Mr. Fortson disclaims beneficial ownership of all of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

(10) Mitch S. Wynne is a member of or trustee of certain entities that hold, directly or indirectly, in the aggregate, 77,455 common units, and Mr. Wynne may be deemed to have voting or investment power with respect to all of such common units. Mr. Wynne has a pecuniary interest in an aggregate of approximately 40,539 common units based on his ownership interest in such entities, and Mr. Wynne disclaims beneficial ownership of the common units that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein. 27,539 common units owned by a trust for which Mr. Wynne serves as trustee are subject to a negative pledge under a loan agreement with a bank.

(11) T. Scott Martin is a member of an entity that holds, in the aggregate, 12,970 common units. Mr. Martin is deemed to beneficially own such common units, and such common units are included in the table above. Mr. Martin is also a partner or member in certain entities that hold, in the aggregate, 3,076,559 Class B units, however Mr. Martin is deemed not to beneficially own any of the Class B units held by such entities. Mr. Martin has a pecuniary interest in approximately 12,970 common units and 15,163 Class B units based on his ownership interest in such entities, and Mr. Martin disclaims beneficial ownership of the securities that may be deemed to be owned by such entities except to the extent of his pecuniary interest therein.

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In August 2023, in connection with the closing of the LongPoint Acquisition, we completed the private placement of 325,000 Series A preferred units to the Series A Purchasers. The below table sets forth the beneficial ownership of our Series A preferred units as of February 16, 2024 by each unitholder known by us to beneficially hold 5% or more of our Series A preferred units. The Series A Purchasers collectively hold all of the Series A preferred units.

	Series A	Percentage of
	Preferred Units	Series A
	Beneficially	Preferred Units
Name of Beneficial Owner (1)	Owned	Owned
APOLLO ACCORD AGGREGATOR A, L.P. (2)(3)	44,000	13.5	%
APOLLO ACCORD V AGGREGATOR A, L.P. (3)(4)	31,000	9.5	%
APOLLO CREDIT STRATEGIES MASTER FUND, LTD (3)(5)	60,000	18.5	%
APOLLO ROYALTIES FUND I, L.P. (6)(7)	40,000	12.3	%
AHVF (AIV), L.P. (7)(8)	44,816	13.8	%
AHVF TE/892/QFPF (AIV), L.P. (7)(8)	36,400	11.2	%

(1) The principal business address of each selling unitholder is c/o Apollo Capital Management, L.P., 9 West 57th Street, 41st Floor, New York, NY 10019.

(2) Apollo Accord+ Management, L.P., a Delaware limited partnership, serves as the investment manager for Apollo Accord+ Aggregator A, L.P. Apollo Accord+ Management GP, LLC, a Delaware limited liability company, serves as the general partner of Apollo Accord+ Management, L.P. Apollo Capital Management, L.P., a Delaware limited partnership (“Capital Management LP”), serves as the sole member for Apollo Accord+ Management GP, LLC.

(3) Apollo Capital Management GP, LLC, a Delaware limited liability company (“Capital Management GP”), serves as the general partner of Capital Management LP. Apollo Management Holdings, L.P., a Delaware limited partnership (“Management Holdings”), serves as the sole member and manager of Capital Management GP, and Apollo Management Holdings GP, LLC, a Delaware limited liability company (“Management Holdings GP”), serves as the general partner of Management Holdings. Marc Rowan, James Zelter and Scott Kleinman are the managers, as well as the executive officers, of Management Holdings GP, and thus have voting or investment control over the common units being offered. Each of Messrs. Kleinman, Rowan and Zelter disclaims beneficial ownership of the reported units, other than to the extent of any pecuniary interest he may have therein.

(4) Apollo Accord Management V, L.P., a Delaware limited partnership, serves as the investment manager for Apollo Accord V Aggregator A, L.P. Apollo Accord Management V GP, LLC, a Delaware limited liability company, serves as the general partner for Apollo Accord Management V, L.P. Capital Management LP serves as the sole member for Apollo Accord Management V GP, LLC.

(5) Apollo ST Fund Management LLC, a Delaware limited liability company, serves as the investment manager for Apollo Credit Strategies Master Fund Ltd. Apollo ST Operating LP, a Delaware limited partnership, serves as the sole member for Apollo ST Fund Management LLC. Apollo ST Capital LLC, a Delaware limited liability company, serves as the sole member for Apollo ST Operating LP. ST Management Holdings, LLC, a Cayman Islands limited liability company, serves as the sole member for Apollo ST Capital LLC. Capital Management LP serves as the managing member for ST Management Holdings, LLC.

(6) Apollo Royalties Management I, LLC, a Delaware limited liability company, serves as the investment manager for Apollo Royalties Fund I, L.P. Apollo Management, L.P., a Delaware limited partnership (“Management LP”), serves as the sole member for Apollo Royalties Management I, LLC.

(7) Apollo Management GP, LLC, a Delaware limited liability company, serves as the general partner for Management LP. Management Holdings serves as the sole member for Apollo Management GP, LLC. Management Holdings GP serves as the general partner for Management Holdings. Marc Rowan, James Zelter and Scott Kleinman are the managers of Apollo Management Holdings GP, LLC and thus have voting or investment control over the common units being offered. Each of Messrs. Kleinman, Rowan and Zelter disclaims beneficial ownership of the reported units, other than to the extent of any pecuniary interest he may have therein.

(8) Apollo Hybrid Value Management, L.P., a Delaware limited partnership (“Hybrid Value Management LP”), serves as the investment manager for AHVF (AIV), L.P., AHVF TE/892/QFPF (AIV), L.P. and AHVF Intermediate Holdings, L.P. Apollo Hybrid Value Management GP, LLC, a Delaware limited liability company (“Hybrid Value Management GP”), serves as the general partner for Hybrid Value Management LP. Management LP serves as the sole member for Hybrid Value Management GP.

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The below table sets forth the beneficial ownership of the equity interests in our General Partner as of February 16, 2024:

Name of Beneficial Owner (1)	Membership Interest
Kimbell GP Holdings, LLC (2)	100	%
Robert D. Ravnaas (3)	33.33	%
Brett G. Taylor (3)	33.33	%
Mitch S. Wynne / Ben J. Fortson (3)	33.33	%

(1) The address for each beneficial owner in this table is 777 Taylor Street, Suite 810, Fort Worth, Texas 76102.

(2) Kimbell GP Holdings, LLC is controlled by entities affiliated with Robert D. Ravnaas, Brett G. Taylor, Mitch S. Wynne and Ben J. Fortson.

(3) Messrs. R. Ravnaas, Taylor, Wynne and Fortson, by virtue of their indirect ownership interest in Kimbell GP Holdings, LLC, which owns our General Partner, may be deemed to beneficially own the non-economic general partner interest in us held by our General Partner. Each of Messrs. R. Ravnaas, Taylor, Wynne and Fortson disclaims beneficial ownership of this interest.

Equity Compensation Plan Information

On May 18, 2022, we held a special meeting of unitholders of the Partnership, at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by 3,700,000 common units for a total of 8,241,600 common units. The following table provides certain information with respect to this plan as of December 31, 2023:

	Number of
	Securities to be	Weighted	Number of Securities
	Issued Upon	-Average	Remaining Available for
	Exercise  of	Exercise Price	Future Issuance Under
	Outstanding	of Outstanding	Equity Compensation
	Options,	Options,	Plans (Excluding
	Warrants	Warrants and	Securities Reflected in
	and Rights(1)	Rights(2)	Column(a))
	(a)	(b)	(c)
Equity compensation plans approved by unitholders	—	—	3,167,892
Equity compensation plans not approved by unitholders	—	—	—
Total	—	—	3,167,892

(1) The long-term incentive plan currently permits the grant of awards covering an aggregate of 8,241,600 units of which, 5,073,708 restricted and common units have been granted. Because these awards have already resulted in the issuance of common units (whether or not restricted), they are not included in column (a).

Item 13. Certain Relationships and Related Party Transactions, and Director Independence

As of February 16, 2024, Kimbell Holdings owns 30,000 common units, representing 0.03% of our limited partner interests outstanding. In addition, Kimbell Holdings owns a 100.0% membership interest in the General Partner, which owns a non-economic general partner interest in us. Messrs. R. Ravnaas and Taylor each own a 33.33% interest in Kimbell Holdings, and Messrs. Wynne and Fortson each own a 16.67% interest in Kimbell Holdings. Kimbell Holdings and each of the Sponsors may be deemed to be a “parent” by virtue of their control over the General Partner. Please read “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for more information relating to each Sponsor’s beneficial ownership in us and the General Partner.

Distributions and Payments to our General Partner and its Affiliates

Distributions

We generally make cash distributions to our unitholders pro rata. 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

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units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.

Kimbell Holdings is entitled to receive its pro rata portion of the distributions we make on our common units.

The dropdown sellers are entitled to receive their pro rata portion of the distributions the Operating Company makes on the OpCo common units, and, as the holder of Class B units, they are also entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution.

Payments

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 the limited liability company agreement of the Operating Company provide that our General Partner will determine the expenses that are allocable to us, but do not limit 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.

Agreements and Transactions with Affiliates in Connection with our Initial Public Offering

In connection with our IPO, we entered into certain agreements and transactions with our Sponsors, the Contributing Parties and their respective affiliates, as described in more detail below. These agreements and transactions were not the result of arm’s-length negotiations and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties. Because some of these agreements related to formation transactions that, by their nature, would not occur in a third party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated third party. We believe the terms of these agreements to be comparable to the terms of agreements used in similarly structured transactions.

Contribution Agreement

In connection with our IPO, we entered into a contribution agreement with our Sponsors and the Contributing Parties that effected the transfer of the mineral and royalty interests owned by the Contributing Parties to us and the use of the net proceeds of our IPO, and also addressed the following matters:

● our option to participate in certain acquisitions by the Contributing Parties of mineral and royalty interests;

● our Sponsors’ and the Contributing Parties’ registration rights with respect to the registration and sale of common units held by them or their affiliates; and

● the Contributing Parties’ obligation to indemnify us for certain limited matters associated with the mineral and royalty interests and associated entities, and our obligation to indemnify the Contributing Parties for certain limited matters related to the mineral and royalty interests and associated entities to the extent they are not required to indemnify us.

Participation Right. Pursuant to the contribution agreement, 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. Unless consented to in writing by our General Partner on our behalf, the participation right shall be on terms and conditions substantially the same as or better than the acquisition by our Sponsors and the Contributing Parties. The participation right will last for so long as any of our Sponsors or their respective affiliates control our General Partner.

Registration Rights. Pursuant to the contribution agreement, the Contributing Parties have specified demand and piggyback participation rights with respect to the registration and sale of common units held by them or their affiliates. At any time following the time when we are eligible to file a registration statement on Form S-3, each of our Sponsors has

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the right to cause us to prepare and file a registration statement on Form S-3 with the SEC covering the offering and sale of common units held by its affiliates. We are not obligated to effect more than one such demand registration in any 12-month period or two such demand registrations in the aggregate. If we propose to file a registration statement pursuant to a Sponsor’s demand registration discussed above, the Contributing Parties may request to “piggyback” onto such registration statement in order to offer and sell common units held by them or their affiliates. We have agreed to pay all registration expenses in connection with such demand and piggyback registrations. Registration expenses do not include underwriters’ compensation, stock transfer taxes or counsel fees.

Indemnification. The Contributing Parties made representations and warranties to us regarding their respective mineral and royalty interests and the associated entities. In addition, the Contributing Parties are, severally but not jointly, obligated to indemnify us for any federal, state and local income tax liabilities attributable to the ownership and operation of the mineral and royalty interests and the associated entities prior to the closing of our IPO until 30 days after the applicable statute of limitations. This indemnification obligation is capped at ten percent of the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification. The Contributing Parties are not required to indemnify us for breaches of any other representations and warranties under the contribution agreement, including breaches related to other title matters, consents and permits or compliance with environmental laws, and such other representations and warranties did not survive the closing of our IPO.

In addition, the Contributing Parties will indemnify us indefinitely against losses arising from certain liens created during their ownership of the entities and breaches of special warranty of title relating to the assets contributed to us in connection with our IPO. This indemnification obligation is capped at the net proceeds received by any such Contributing Party with respect to the entity or asset that is subject to such claim for indemnification.

We have agreed to indemnify the Contributing Parties for breaches of specified representation and warranties and for events and conditions associated with the ownership or operation of the mineral and royalty interests and the associated entities (other than any liabilities for which the Contributing Parties are specifically required to indemnify us as described above). Our indemnification obligation for breaches of specified representations and warranties is capped at ten percent of the aggregate net proceeds received by all of the Contributing Parties. Our indemnification obligation for all other liabilities is capped at the aggregate net proceeds received by all of the Contributing Parties.

Management Services Agreements

Management Services Agreement with Kimbell Operating

We have entered into a management services agreement with Kimbell Operating, pursuant to which Kimbell Operating provides management, administrative, operational and acquisition services to us, including via the services agreements with the Sponsor Managers and the Non-Sponsor Managers (each as defined below). The management services agreement with Kimbell Operating is under terms and conditions similar to those described below in “—Services Agreements with Our Sponsors” and “—Other Services Agreements,” except that neither party to the agreement may terminate unless all of the services agreements with the Sponsor Managers and the Non-Sponsor Managers have terminated. During the years ended December 31, 2023, 2022 and 2021, we paid to Kimbell Operating services fees equal to $0.1 million, $0.2 million and $1.0 million, respectively, which amounts represent an estimated allocation of all projected costs to be incurred by Kimbell Operating in providing such services to us for the respective year, including pursuant to the services agreements with the Sponsor Managers and the Non-Sponsor Managers.

Services Agreements with Our Sponsors

Services. Kimbell Operating currently has services agreements with BJF Royalties, LLC (“BJF Royalties”) and K3 Royalties (collectively, the “Sponsor Managers”), which are entities controlled by Messrs. Fortson and Wynne, respectively. Pursuant to these agreements, the Sponsor Managers provide management, administrative and operational services to Kimbell Operating. In addition, the Sponsor Managers or their affiliates provide acquisition services to us,

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including identifying, evaluating and recommending to us acquisition opportunities and any related negotiating of such opportunities. The services to be provided by each Sponsor Manager are as set forth below:

● BJF Royalties: For all of our assets and the assets of our affiliates, BJF Royalties assists in sourcing, evaluating and recommending acquisitions, and assisting with business development opportunities related to potential acquisitions and other strategic transactions.

● K3 Royalties: For all of our assets and the assets of our affiliates, K3 Royalties assists in sourcing, evaluating and recommending acquisitions, and assists with business development, investor and public relations and relationship management with our sponsors, past and future sellers of mineral assets and the Kimbell Art Foundation.

The Sponsor Managers have the exclusive right to provide the acquisition services listed above in connection with acquisitions by us, as well as the exclusive right to provide any additional management services reasonably required with respect to properties newly acquired by us.

Service Fees and Reimbursement. Under the services agreements, Kimbell Operating paid to K3 Royalties a monthly services fee of $10,000 for the years ended December 31, 2023, 2022 and 2021. These amounts represent an estimated allocation of all projected costs to be incurred by such Sponsor Manager in providing services to Kimbell Operating for the respective year. Upon the approval of the Board of Directors, Kimbell Operating will continue to pay a monthly services fee of $10,000 to K3 Royalties, for the period from January 1, 2024 through December 31, 2024. In addition, BJF Royalties will continue to not receive a monthly services fee in connection with providing its services.

Subject to the approval of the Board of Directors, the monthly services fee will be adjusted in the future (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional management services (including with respect to acquisitions of new properties). In addition, Kimbell Operating is required to reimburse each Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third party expenses and expenditures) that such Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a services agreement for any reason other than the Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.

Term and Termination. The initial term of the services agreement with the Sponsor Managers was five years, after which date they will continue on a year-to-year basis unless terminated by Kimbell Operating or by the applicable Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

● The applicable Sponsor Manager may terminate its services agreement, or the provision of any service thereunder, upon at least 180 days’ notice to Kimbell Operating.

● The applicable Sponsor Manager may terminate its services agreement upon a default by Kimbell Operating, which includes (i) Kimbell Operating’s failure to perform any of its material obligations under the agreement, where such default continues unremedied for a period of 15 days after notice thereof, and (ii) the occurrence of certain events relating to the bankruptcy or insolvency of Kimbell Operating.

● Kimbell Operating may terminate a services agreement upon a default by the applicable Sponsor Manager, upon 15 days’ notice to such Sponsor Manager. A Sponsor Manager is in default upon the occurrence of any gross negligence or willful misconduct of such Sponsor Manager in performing services under its services agreement, which results in material harm to us and our affiliates, including Kimbell Operating (the “Partnership Service Group”).

● Kimbell Operating or the Sponsor Manager may terminate the applicable services agreement if, at any time, the Sponsors or their affiliates no longer control our General Partner, upon at least 90 days’ notice to the other party.

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Kimbell Operating’s only remedy for a Sponsor Manager’s default under its services agreement is the termination of the applicable agreement as described in the third bullet point above.

Indemnification. Under the services agreements with the Sponsor Managers, Kimbell Operating agreed to indemnify each Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable services agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable services agreement. The Sponsor Managers do not have corresponding indemnification obligations with respect to Kimbell Operating.

Other Services Agreements

Management Services. Kimbell Operating previously had services agreements with Nail Bay Royalties and Duncan Management, LLC (collectively, the “Non-Sponsor Managers”), which were entities controlled by Benny D. Duncan, who served on the Board of Directors during the year ended December 31, 2017 and a portion of the year ended December 31, 2018. Effective as of February 8, 2022, Kimbell Operating and each of the Non-Sponsor Managers entered into agreements to terminate the services agreements of such service providers. Pursuant to these agreements, the Non-Sponsor Managers provided management, administrative and operational services to Kimbell Operating. These services included, with respect to the serviced properties: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; collecting and disbursing payments and rendering related accounting and bookkeeping services; monitoring drilling and production activities; assisting in preparing certain federal and state tax forms; and providing certain additional accounting, title, human resources, regulatory compliance and other services.

Service Fees and Reimbursement. Under the services agreements with the Non-Sponsor Managers, Kimbell Operating paid a services fee of approximately $116,341 for the year ended December 31, 2022. Kimbell Operating paid to the Non-Sponsor Managers a monthly services fee of approximately $70,817 for the year ended December 31, 2021. These amounts represented an estimated allocation of all projected costs to be incurred by such Non-Sponsor Manager in providing services to Kimbell Operating for the respective year.

Indemnification. Under the services agreements with the Non-Sponsor Managers, Kimbell Operating agreed to indemnify each Non-Sponsor Manager, its affiliates and any of their respective employees, officers, directors and agents from and against all liability, demands, claims, actions or causes of action, assessments, losses, damages, costs and expenses (including legal fees) resulting from or arising out of (i) any material breach by Kimbell Operating of the applicable services agreement or (ii) the personal injury, death, property damage or liability of any member of the Partnership Service Group, any third party or any of their respective employees, officers, directors and agents arising from, connected with or under the applicable services agreement. The Non-Sponsor Managers did not have corresponding indemnification obligations with respect to Kimbell Operating.

Limited Liability Company Agreement of Kimbell Holdings

Our Sponsors have entered into the limited liability company agreement of Kimbell Holdings. Kimbell Holdings is the sole member of our General Partner. Pursuant to Kimbell Holdings’ limited liability company agreement, for so long as Messrs. Fortson, R. Ravnaas, Taylor and Wynne (or their designated successors) serve as directors of Kimbell Holdings, such persons will also serve as directors of our General Partner.

Other Transactions and Relationships with Related Persons

Family members of certain of our General Partner’s executive officers and directors serve as officers or employees of our General Partner and Kimbell Operating. Rand P. Ravnaas, the son of Robert D. Ravnaas and the brother of R. Davis Ravnaas, serves as Vice President—Business Development of our General Partner and Kimbell Operating, and he is a partial owner of certain of the Contributing Parties. In addition, Peter Alcorn, the son-in-law of Mitch Wynne, serves as Vice President—Land of our General Partner and Kimbell Operating, and he is a partial owner of certain of the

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Contributing Parties. Each of these family members will participate in the A&R LTIP and receive compensation comprising a base salary and bonuses commensurate with other similarly-situated employees.

John Wynne, the son of Mitch S. Wynne, acts as our agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to us. John Wynne derived a commission of approximately $26,500, $24,450 and $22,160 for the years ended December 31, 2023, 2022 and 2021, respectively, for the placement of our insurance coverage. Our annual premium expense was approximately $602,600, $611,204 and $555,640 for the years ended December 31, 2023, 2022 and 2021, respectively.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

The Board of Directors has adopted policies for the review, approval and ratification of transactions with related persons. The Board of Directors has adopted a written code of business conduct and ethics, under which a director is expected to bring to the attention of our chief executive officer or the Board of Directors any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our General Partner on the other. The resolution of any conflict or potential conflict should, at the discretion of the Board of Directors in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our General Partner or its affiliates, including our Sponsors or their respective affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the Board of Directors in accordance with the provisions of our partnership agreement. At the discretion of the Board of Directors in light of the circumstances, the resolution may be determined by the Board of Directors in its entirety or by the conflicts committee.

Under our code of business conduct and ethics, executive officers are required to avoid conflicts of interest unless approved by the Board of Directors.

The code of business conduct and ethics described above was adopted in connection with the closing of our IPO, and as a result, certain of the transactions described above were not reviewed according to such procedures.

Director Independence

Because we are a publicly traded partnership, the NYSE does not require our Board of Directors to have a majority of independent directors. For a discussion of the independence of our Board of Directors, please read “Item 10. Directors, Executive Officers and Corporate Governance.”

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Item 14. Principal Accounting Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The Audit Committee’s charter requires the Audit Committee to approve in advance all audit and non-audit services to be provided by Grant Thornton LLP. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2023, 2022 and 2021 were approved by the Audit Committee. The following table sets forth audit and non-audit fees we have paid to Grant Thornton LLP for the periods indicated (in thousands).

	Year Ended December 31,
	2023		2022		2021
Audit Fees (1)	$	1,011,000	$	915,208	$	771,214
Audit-Related Fees (2)		—		—		—
Tax Fees (3)		—		—		—
All Other Fees (4)		—		—		—
Total	$	1,011,000	$	915,208	$	771,214

(1) Audit fees represent aggregate fees for audit services, which relate to the fiscal year consolidated audit, quarterly reviews, registration statements and comfort letters.

(2) Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits or agreed upon procedures required to comply with financial, accounting or regulatory reporting.

(3) Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.

(4) All other fees represent fees for services not classifiable under the other categories listed in the table above.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying notes, please read “Index to Financial Statements” on page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) List of Exhibits

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EXHIBIT INDEX

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.2	—	Fifth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 13, 2023)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
3.5	—	Third Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
4.1	—	Amended and Restated Registration Rights Agreement, dated as of March 25, 2019, by and among Kimbell Royalty Partners, LP, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Haymaker Minerals & Royalties, LLC, AP KRP Holdings, L.P., ATCF SPV, L.P., Zeus Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo Thunder Partners, L.P., AIE III Investments, L.P., Apollo Union Street SPV, L.P., Apollo Lincoln Private Credit Fund, L.P., Apollo SPN Investments I (Credit), LLC, AA Direct, L.P., PEP I Holdings, LLC, PEP II Holdings, LLC, PEP III Holdings, LLC, Cupola Royalty Direct, LLC, Kimbell Art Foundation and Rivercrest Capital Partners LP (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on March 26, 2019)
4.2	—	Registration Rights Agreement, dated as of December 15, 2022, by and among Kimbell Royalty Partners, LP and Hatch Royalty LLC (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on December 15, 2022)
4.3	—	Registration Rights Agreement, dated as of May 17, 2023, by and among between Kimbell Royalty Partners, LP and MB Minerals, L.P. (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP Current Report on Form 8-K filed on May 18, 2023)
4.4	—	Registration Rights Agreement, dated as of September 13, 2023, by and among Kimbell Royalty Partners, LP and the parties listed on the signature page thereof (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
4.5*	—	Description of Common Units Representing Limited Partnership Interests
10.1†	—	Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 18, 2022)
10.2†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 11, 2017)
10.3†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Director Unit Agreement (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Form 10-Q filed on August 14, 2017)
10.4†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 2018 Restricted Unit Agreement (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.5	—	Amended and Restated Credit Agreement, dated as of June 13, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 20, 2023)

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10.6	—	Amendment No. 1 to Amended and Restated Credit Agreement, dated as of July 24, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 28, 2023)
10.7	—	Amendment No. 2 to Amended and Restated Credit Agreement, dated as of December 8, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on December 11, 2023)
10.8†	—	Management Services Agreement, dated February 8, 2017, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.9†	—	Amendment No. 1 to Management Services Agreement, dated December 10, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.10 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)
10.10†	—	Amendment No. 2 to Management Services Agreement, dated December 16, 2019, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.13 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.11†	—	Management Services Agreement, dated February 8, 2017, by and between BJF Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.12†	—	Management Services Agreement, dated February 8, 2017, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.13†	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.11 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.14†	—	Amendment No. 2 to Management Services Agreement, dated December 10, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.17 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)
10.15†	—	Amendment No. 3 to Management Services Agreement, dated December 16, 2019, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.18 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.16	—	Exchange Agreement, dated as of September 23, 2018, by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Kimbell Art Foundation, Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
10.17	—	Purchase and Sale Agreement, dated as of April 11, 2023, by and among MB Minerals, L.P., Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on April 12, 2023)
10.18	—	Securities Purchase Agreement, dated as of August 2, 2023, by and between LongPoint Minerals II, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)
10.19	—	Preferred Units Purchase Agreement, dated as of August 2, 2023, by and among Kimbell Royalty Partners, LP and the several purchasers party thereto (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)

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10.20	—	Board Representation and Observation Agreement, dated as of September 13, 2023, by and among Kimbell Royalty Partners, LP, Kimbell GP Holdings, LLC, Apollo Accord+ Aggregator A, L.P., Apollo Accord V Aggregator A, L.P., Apollo Defined Return Aggregator A, L.P., Apollo Calliope Fund, L.P., Apollo Excelsior, L.P., Apollo Credit Strategies Master Fund Ltd., Apollo Atlas Master Fund, LLC, Apollo Union Street SPV, L.P., Host Plus PTY Limited - Accord, Apollo Delphi Fund, L.P., Apollo Royalties Fund I, L.P., AHVF (AIV), L.P., AHVF Intermediate Holdings, L.P., AHVF TE/892/QFPF (AIV), L.P. and ACMP Holdings, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
10.21	—	Transition Services Agreement, by and between Kimbell Royalty Operating, LLC and FourPoint Energy, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
21.1*	—	List of Subsidiaries of Kimbell Royalty Partners, LP
23.1*	—	Consent of Grant Thornton LLP
23.2*	—	Consent of Ryder Scott Company, L.P.
23.3*	—	Consent of KPMG LLP
23.4*	—	Report of Independent Registered Public Accounting Firm—KPMG LLP Opinion on the Consolidated Financial Statements on Kimbell Tiger Acquisition Corporation
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350
97.1*	—	Kimbell Royalty Partners, LP Policy for the Recovery of Erroneously Awarded Compensation
99.1*	—	Report of Ryder Scott Company, L.P. as of December 31, 2023
101.INS*	—	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*      —Filed herewith.

**    —Furnished herewith.

†      —Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Annual Report pursuant to Item 15(b).

††—Certain schedules and similar attachments to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish a supplemental copy of each such omitted schedule or similar attachment to SEC upon request.

Item 16. Form 10-K Summary

The Partnership has elected not to include summary information.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Kimbell Royalty Partners, LP
	By:	Kimbell Royalty GP, LLC
		its general partner
Date: February 21, 2024	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ Robert D. Ravnaas	Chairman of the Board of Directors and Chief
Robert D. Ravnaas	Executive Officer (Principal Executive Officer)	February 21, 2024
/s/ R. Davis Ravnaas	President and Chief Financial Officer (Principal
R. Davis Ravnaas	Financial Officer)	February 21, 2024
/s/ R. Blayne Rhynsburger
R. Blayne Rhynsburger	Controller (Principal Accounting Officer)	February 21, 2024
/s/ William H. Adams III
William H. Adams III	Director	February 21, 2024
/s/ Erik B. Daugbjerg
Erik B. Daugbjerg	Director	February 21, 2024
/s/ Ben J. Fortson
Ben J. Fortson	Director	February 21, 2024
/s/ T. Scott Martin
T. Scott Martin	Director	February 21, 2024
/s/ Craig Stone
Craig Stone	Director	February 21, 2024
/s/ Brett G. Taylor
Brett G. Taylor	Director	February 21, 2024
/s/ Mitch S. Wynne
Mitch S. Wynne	Director	February 21, 2024

126

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	F-2
Consolidated Balance Sheets at December 31, 2023 and 2022	F-5
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	F-6
Consolidated Statements of Changes in Unitholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	F-8
Notes to Consolidated Financial Statements	F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Kimbell Royalty Partners, LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Kimbell Royalty Partners, LP (a Delaware limited partnership) and subsidiaries (collectively, the “Partnership”) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in unitholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 21, 2024 expressed an unqualified opinion.

We did not audit the consolidated financial statements of Kimbell Tiger Acquisition Corporation, a consolidated variable interest entity as of and for the period ended December 31, 2022, which statements reflect total assets constituting 0% and 22%, respectively, of consolidated total assets as of December 31, 2023 and 2022, and total revenues of 0% and 0%, respectively, of consolidated total revenues for the years then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Kimbell Tiger Acquisition Corporation, is based solely on the report of the other auditors.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

Critical audit matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which it they relate.

Accrued oil, natural gas, and NGL revenues

As described further in Note 2 to the financial statements, the Partnership records oil, natural gas, and NGL revenues in the month production is delivered to the purchaser. As a non-operator and an owner of mineral and royalty interests, the Partnership has no involvement or operational control over the volumes and method of sale of the oil, natural gas and

F-2

NGLs produced and sold from the properties.  The Partnership has limited visibility to when wells start producing and production settlement statements from operators may not be received for one to four months after the date of production is delivered. As a result, the Partnership is required to estimate accrued revenue at each reporting period based on estimates of production delivered to purchasers and the prices that will be received on those volumes. As of December 31, 2023, the Partnership has accrued $59 million of revenues that are included in oil, natural gas and NGL receivables. We identified the estimation of accrued oil, natural gas, and NGL revenues as a critical audit matter.

The principal consideration for our determination that the estimation of accrued oil, natural gas, and NGL revenues is a critical audit matter is that auditing the Partnership’s estimate of accrued oil, natural gas, and NGL revenues is complex and judgmental as changes in certain inputs and assumptions, such as estimated production volumes and the price that will be received on those volumes, could have a significant impact on the measurement of accrued oil, natural gas, and NGL revenues.

Our audit procedures related to the estimation of accrued oil, natural gas, and NGL revenues included the following, among others.

● We tested the design and operating effectiveness of key internal controls over the Partnership’s accrued revenue process.

● We tested a sample of revenue transactions to support inputs used in the estimation of accrued revenues, including the actual volume of production delivered to purchasers and the realized prices received on those volumes.

● We evaluated the prices used by the Partnership to estimate the price to be received for the sale of oil, natural gas, and NGL production by independently developing an expectation of price using publicly available prices and historical differentials.

● We tested the historical accuracy of prior period estimates of accrued revenues by performing a lookback analysis to evaluate the reasonableness of management’s estimates and to identify indicators of management bias in significant assumptions used to derive the revenue accrual.

● We assessed the completeness and accuracy of the accrued revenues through disaggregated analytical procedures by month, product type, and comparison of pricing used to publicly available market prices and historical differentials.

Estimation of proved reserves as it relates to the calculation and recognition of depletion expense and impairment

As described further in Notes 2 and 6 to the financial statements, the Partnership accounts for its oil and natural gas properties using the full cost method of accounting, which requires management to make estimates of proved reserves to measure depletion expense and to determine if any impairment exists for its proved oil and natural gas properties. Proved reserves are estimated quantities of oil and natural gas 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.

The net book value of the Partnership’s oil and natural gas properties was $1 billion as of December 31, 2023, and the Partnership recorded depletion expense of $96 million for the year ended December 31, 2023. The Partnership recorded an impairment of $18 million on its proved oil and natural gas properties for the year ended December 31, 2023. The Partnership’s estimates of proved reserves are prepared by an independent petroleum engineering firm.  Estimates of proved reserves depend upon several factors and assumptions, including the quantities of oil and natural gas reserves ultimately recovered by the Partnership’s third-party operators.  Significant judgment is required by the independent petroleum engineer in evaluating geological and engineering data used to estimate proved oil and natural gas reserves. Estimating reserves also requires the selection of certain subjective inputs, including price assumptions inclusive of price differentials, among others.  We identified the estimation of proved reserves as it relates to the calculation and measurement of depletion expense as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the future volumes could have a significant impact on the estimation of proved reserves, measurement of depletion expense, and determination of impairment for proved oil and natural gas properties. Auditing the Partnership’s estimate of proved reserves is complex because our work involves the use of the work of the independent petroleum engineer engaged by the Partnership and because evaluating certain inputs described above requires significant auditor judgement.

F-3

Our audit procedures related to the estimation of proved reserves included the following, among others.

● We tested the design and operating effectiveness of key internal controls over the Partnership’s process to estimate proved reserves for the purpose of calculating and measuring of depletion expense and determining impairment for proved oil and natural gas properties.

● We evaluated the level of knowledge, skill, ability, and objectivity of the independent petroleum engineer engaged by management and their relationship to the Partnership.  We made inquiries of the independent petroleum engineer regarding the process followed and judgments made to estimate the Partnership’s proved reserves, and we read the reserve report prepared by the independent petroleum engineer.

● We evaluated the pricing and differential inputs used to estimate proved reserves for consistency with requirements under the full cost method of accounting.

● We compared the Partnership’s historical production forecasts to actual production volumes to assess the Partnership’s ability to accurately forecast and we compared the future forecasted production used by the Partnership in the current period to historical production.

● We analyzed the depletion expense and ceiling test calculations for consistency with requirements under the full cost method of accounting and checked the accuracy of the depletion expense and ceiling test calculations.

● We selected a sample of wells to test the inputs used in the estimation of proved reserves, including volumes, pricing, and other assumptions.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2015.

Dallas, Texas

February 21, 2024

F-4

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	30,992,670	$	24,635,718
Oil, natural gas and NGL receivables		59,020,471		46,993,711
Derivative assets		11,427,735		—
Accounts receivable and other current assets		1,699,536		3,562,912
Total current assets		103,140,412		75,192,341
Property and equipment, net		589,895		953,781
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($222,712,844 and $207,695,343 excluded from depletion at December 31, 2023 and 2022, respectively)		2,048,690,088		1,465,985,718
Less: accumulated depreciation, depletion and impairment		(827,033,944)		(712,716,951)
Total oil and natural gas properties, net		1,221,656,144		753,268,767
Right-of-use assets, net		2,189,243		2,525,323
Derivative assets		2,888,051		754,786
Loan origination costs, net		7,325,471		3,004,104
Assets of consolidated variable interest entities:
Cash		—		390,850
Investments held in trust		—		240,621,146
Prepaid expenses		—		35,201
Total assets	$	1,337,789,216	$	1,076,746,299
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	6,594,736	$	1,210,337
Other current liabilities		6,173,314		4,909,510
Derivative liabilities		208,710		12,646,720
Total current liabilities		12,976,760		18,766,567
Operating lease liabilities, excluding current portion		1,887,693		2,236,361
Derivative liabilities		60,094		432,142
Long-term debt		294,200,000		233,015,911
Other liabilities		197,917		322,917
Liabilities of consolidated variable interest entities:
Other current liabilities		—		512,725
Deferred underwriting commissions		—		8,050,000
Total liabilities		309,322,464		263,336,623
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units and zero units issued and outstanding as of December 31, 2023 and 2022, respectively)		314,423,572		—
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		236,900,000
Kimbell Royalty Partners, LP unitholders' equity:
Common units (73,851,458 units and 64,231,833 units issued and outstanding as of December 31, 2023 and 2022, respectively)		670,530,748		601,841,776
Class B units (20,847,295 and 15,484,400 units issued and outstanding as of December 31, 2023 and 2022, respectively)		1,042,365		774,220
Total Kimbell Royalty Partners, LP unitholders' equity		671,573,113		602,615,996
Non-controlling interest (deficit) in OpCo		42,470,067		(26,106,320)
Total unitholders' equity		714,043,180		576,509,676
Total liabilities, mezzanine equity and unitholders' equity	$	1,337,789,216	$	1,076,746,299

The accompanying notes are an integral part of these consolidated financial statements.

F-5

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2023		2022		2021
Revenue
Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021
Lease bonus and other income		5,594,855		3,073,609		3,319,104
Gain (loss) on commodity derivative instruments, net		20,888,972		(36,978,550)		(42,791,909)
Total revenues		294,068,612		248,059,185		135,615,216
Costs and expenses
Production and ad valorem taxes		20,326,477		16,238,814		10,480,481
Depreciation and depletion expense		96,477,003		50,086,414		36,797,881
Impairment of oil and natural gas properties		18,220,173		—		—
Marketing and other deductions		12,564,619		13,383,074		12,048,643
General and administrative expense		35,677,851		29,128,659		26,977,519
Consolidated variable interest entities related:
General and administrative expense		927,699		2,304,445		—
Total costs and expenses		184,193,822		111,141,406		86,304,524
Operating income		109,874,790		136,917,779		49,310,692
Other income (expense)
Equity income in affiliate		—		2,668,844		1,119,819
Interest expense		(25,950,600)		(13,818,310)		(9,182,103)
Loss on extinguishment of debt		(480,244)		—		—
Other (expense) income		(180,765)		4,043,530		1,263,566
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		3,508,691		3,721,145		—
Net income before income taxes		86,771,872		133,532,988		42,511,974
Income tax expense		3,766,302		2,738,702		74,100
Net income		83,005,570		130,794,286		42,437,874
Distribution and accretion on Series A preferred units		(6,310,215)		—		(11,249,969)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(16,464,890)		(18,822,552)		(8,496,104)
Distribution on Class B units		(88,786)		(42,243)		(76,780)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51
Weighted average number of common units outstanding
Basic		66,595,273		54,112,595		40,400,907
Diluted		93,057,731		65,837,017		60,957,824

The accompanying notes are an integral part of these consolidated financial statements.

F-6

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

									Non-controlling		Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Interest in TGR		Total
Balance at January 1, 2021		38,918,689	$	257,593,307		20,779,781	$	1,038,989	$	77,002,442	$	—	$	335,634,738
Common units issued for equity offering		4,312,500		57,522,440		—		—		—		—		57,522,440
Conversion of Class B units to common units		3,168,202		40,482,756		(3,168,202)		(158,410)		(40,482,756)		—		(158,410)
Redemption of Series A preferred units		—		(10,753,930)		—		—		(4,229,854)		—		(14,983,784)
Restricted units repurchased for tax withholding		(173,185)		(2,064,693)		—		—		—		—		(2,064,693)
Unit-based compensation		936,567		10,632,725		—		—		—		—		10,632,725
Distributions to unitholders		—		(47,309,785)		—		—		(21,534,575)		—		(68,844,360)
Distribution and accretion on Series A preferred units		—		(7,956,092)		—		—		(3,293,877)		—		(11,249,969)
Distribution on Class B units		—		(76,780)		—		—		—		—		(76,780)
Net income		—		30,647,893		—		—		11,789,981		—		42,437,874
Balance at December 31, 2021		47,162,773		328,717,841		17,611,579		880,579		19,251,361		—		348,849,781
Common units issued for equity offering		6,900,000		116,119,417		—		—		—		—		116,119,417
Class B units issued for acquisition		—		—		7,272,821		363,641		120,292,459		—		120,656,100
Conversion of Class B units to common units		9,400,000		162,147,055		(9,400,000)		(470,000)		(162,147,055)		—		(470,000)
Restricted units repurchased for tax withholding		(193,604)		(3,344,828)		—		—		—		—		(3,344,828)
Forfeitures of restricted units		(1,171)		(19,813)		—		—		—		—		(19,813)
Unit-based compensation		963,835		11,107,639		—		—		—		—		11,107,639
Distributions to unitholders		—		(107,402,294)		—		—		(19,323,523)		—		(126,725,817)
Distribution on Class B units		—		(42,243)		—		—		—		—		(42,243)
Proceeds from issuance of TGR public warrants		—		—		—		—		—		11,500,000		11,500,000
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		(17,412,732)		—		—		(3,002,114)		(11,500,000)		(31,914,846)
Net income		—		111,971,734		—		—		18,822,552		—		130,794,286
Balance at December 31, 2022		64,231,833		601,841,776		15,484,400		774,220		(26,106,320)		—		576,509,676
Common units issued for equity offering		8,337,500		110,711,383		—		—		—		—		110,711,383
Units issued for acquisition		557,302		8,654,900		5,369,218		268,461		83,383,956		—		92,307,317
Conversion of Class B units to common units		6,323		101,105		(6,323)		(316)		(101,105)		—		(316)
Restricted units repurchased for tax withholding		(279,662)		(4,851,962)		—		—		—		—		(4,851,962)
Unit-based compensation		998,162		13,111,522		—		—		—		—		13,111,522
Distributions to unitholders		—		(120,372,624)		—		—		(31,551,122)		—		(151,923,746)
Distribution and accretion on Series A preferred units		—		(4,921,063)		—		—		(1,389,152)		—		(6,310,215)
Distribution on Class B units		—		(88,786)		—		—		—		—		(88,786)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		1,192,969		—		—		379,768		—		1,572,737
Net income		—		65,151,528		—		—		17,854,042		—		83,005,570
Balance at December 31, 2023		73,851,458	$	670,530,748		20,847,295	$	1,042,365	$	42,470,067	$	—	$	714,043,180

The accompanying notes are an integral part of these consolidated financial statements.

F-7

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2023		2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	83,005,570	$	130,794,286	$	42,437,874
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		96,477,003		50,086,414		36,797,881
Impairment of oil and natural gas properties		18,220,173		—		—
Amortization of right-of-use assets		336,080		319,674		298,093
Amortization of loan origination costs		1,943,025		1,872,700		1,556,769
Loss on extinguishment of debt		480,244		—		—
Equity income in affiliate		—		(2,668,844)		(1,119,819)
Cash distribution from affiliate		—		3,770,651		1,015,559
Forfeiture of restricted units		—		(19,813)		—
Unit-based compensation		13,111,522		11,107,639		10,632,725
(Gain) loss on derivative instruments, net of settlements		(26,371,058)		(14,300,570)		20,343,783
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(12,026,760)		(11,846,567)		(17,594,389)
Accounts receivable and other current assets		1,863,376		(511,319)		(2,077,637)
Accounts payable		509,400		399,318		(77,716)
Other current liabilities		1,263,804		1,590,016		(463,828)
Operating lease liabilities		(348,668)		(324,913)		(306,814)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(3,508,691)		(3,721,145)		—
Other assets and liabilities		(687,353)		88,966		—
Net cash provided by operating activities		174,267,667		166,636,493		91,442,481
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(141,297)		(163,140)		(772,688)
Purchase of oil and natural gas properties		(490,665,514)		(141,297,776)		(55,300,252)
Proceeds from trust of variable interest entity		930,850		—		—
Cash distribution from affiliate		—		3,637,015		500,389
Consolidated variable interest entities related:
Cash paid for transaction costs		31,553		—		—
Cash received from investments held in trust		243,167,434		—		—
Investment in marketable securities		—		(236,900,000)		—
Net cash used in investing activities		(246,676,974)		(374,723,901)		(55,572,551)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs		313,950,000		—		—
Proceeds from equity offering, net of issuance costs		110,711,383		116,119,417		57,522,440
Contributions from Class B unitholders		268,461		363,641		—
Redemption of Class B contributions on converted units		(316)		(470,000)		(158,410)
Redemption on Series A preferred units		—		—		(67,081,680)
Distribution to common unitholders		(120,372,624)		(107,402,294)		(47,309,785)
Distribution to OpCo unitholders		(31,551,122)		(19,323,523)		(21,534,575)
Distribution on Series A preferred units		(961,644)		—		(2,800,012)
Distribution on Class B units		(88,786)		(42,243)		(76,780)
Borrowings on long-term debt		201,084,089		199,200,000		136,565,769
Repayments on long-term debt		(139,900,000)		(183,300,000)		(91,000,000)
Payment of loan origination costs		(6,744,636)		(662,320)		(684,767)
Restricted units repurchased for tax withholding		(4,851,962)		(3,344,828)		(2,064,693)
Consolidated variable interest entities related:
Proceeds from initial public offering of Kimbell Tiger Operating Company		—		227,585,000		—
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments		—		(2,661,288)		—
Redemption of Kimbell Tiger Acquisition Corporation equity units		(243,167,434)		—		—
Net cash provided by (used in) financing activities		78,375,409		226,061,562		(38,622,493)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		5,966,102		17,974,154		(2,752,563)
CASH AND CASH EQUIVALENTS, beginning of period		25,026,568		7,052,414		9,804,977
CASH AND CASH EQUIVALENTS, end of period	$	30,992,670	$	25,026,568	$	7,052,414

F-8

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

	Year Ended December 31,
	2023		2022		2021
Supplemental cash flow information:
Cash paid for interest	$	23,727,572	$	11,207,530	$	7,538,814
Cash paid for taxes	$	2,281,000	$	3,082,245	$	—
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	92,038,856	$	120,292,459	$	—
Noncash effect of Series A preferred unit redemption	$	—	$	—	$	14,893,784
Noncash deemed distribution to Series A preferred units	$	473,571	$	—	$	9,431,794
Distribution on Series A preferred units in accounts payable	$	4,875,000	$	—	$	—
Recognition of tenant improvement asset	$	125,000	$	125,001	$	447,917
Right-of-use assets obtained in exchange for operating lease liabilities	$	—	$	—	$	19,636
Consolidated variable interest entities related:
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units	$	(8,050,000)	$	—	$	—
Deferred underwriting commissions	$	—	$	8,050,000	$	—

	Year Ended December 31,
	2023		2022		2021
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$	30,992,670	$	24,635,718	$	7,052,414
Cash held at consolidated variable interest entities		—		390,850		—
	$	30,992,670	$	25,026,568	$	7,052,414

The accompanying notes are an integral part of these consolidated financial statements.

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Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “the Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is 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. The Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

Basis of Presentation

The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Use of Estimates

Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

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 and is still active. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.

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NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of equity-based compensation.

The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Oil, Natural Gas and NGL Receivables

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2023 and 2022, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Derivative Financial Instruments

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though

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they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statements of operations within gain (loss) on commodity derivative instruments.

Interest Rate Swaps

The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps were recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Loan Origination Costs

Certain direct costs associated with the Partnership’s secured revolving credit facility are presented in the consolidated balance sheets as loan origination costs. These costs are amortized over the term of the secured revolving credit facility and included as a component of interest expense in the consolidated statements of operations.

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas 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 capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2023, 2022 or 2021.

The Partnership assesses all unevaluated properties on periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is

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able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2023, 2022 or 2021.

Other Current Liabilities

Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities.

Earnings Per Unit

Earnings per unit applicable to limited partners is computed utilizing the “if-converted” method, which is calculated by dividing limited partners’ interested in net income by the weighted average number of outstanding common units. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”).

Income Taxes

As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. The non-controlling interest, which represents OpCo common unitholders’, as defined below, are not subject to federal income taxes.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2023, 2022 and 2021.

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2023, 2022 and 2021, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

During the years ended December 31, 2023, 2022 and 2021, the Partnership’s top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of oil, natural gas and NGL sales revenue.

Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the  Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information.

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Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents OpCo common unitholders’, as defined below, ownership in the net assets of the Operating Company. When the OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 10—Unitholders’ Equity and Partnership Distributions for further discussion.

Revenue from Contracts with Customers

The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods:

	Year Ended December 31,
	2023		2022			2021
Oil revenue	$	183,150,517	$	130,811,485	$	87,151,724
Natural gas revenue		59,524,413		122,632,983		66,977,352
NGL revenue		24,909,855		28,519,658		20,958,945
Total Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021

Transaction Price Allocated to Remaining Performance Obligations

The Partnership’s right to revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts.

Contract Balances

Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP.

Prior-Period Performance Obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the revenue to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2023, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent

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actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value Measurements

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.

Consolidation

The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.

In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the

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trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represented the shares of Class A common stock of TGR par value $0.0001 per share (the “Class A common stock”) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

Recently Issued Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

2023 Activity

On September 13, 2023, the Partnership completed 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”) in a cash transaction valued at approximately $455.0 million. The Partnership funded the cash transaction with borrowings under its secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 9—Preferred Units). The adjusted purchase price of the LongPoint Acquisition includes the total cash consideration of $455.0 million, transactional costs of $7.4 million and less $16.6 million of post-effective net oil, natural gas and NGL revenues earned prior to the closing date. The LongPoint Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $198.2 million to proved properties and $247.6 million to unevaluated properties.

On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo

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Common Units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and (b) 557,302 common units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. The MB Minerals Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $60.8 million to proved properties and $74.9 million to unevaluated properties.

2022 Activity

On December 15, 2022, the Partnership completed the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”). The aggregate consideration for the Hatch Acquisition consisted of (i) approximately $150.4 million in cash and (ii) the issuance of 7,272,821 OpCo common units and an equal number of Class B units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Hatch Acquisition are located in the Permian Basin and the Partnership estimates that the assets consisted of approximately 889 net royalty acres on approximately 230,000 gross acres. The Hatch acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $56.4 million to proved properties and $204.7 million to unevaluated properties.

2021 Activity

On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 14—Related Party Transactions, for further discussion of the Partnership’s relation to each entity.

On December 7, 2021, the Partnership completed the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) for an aggregate purchase price of approximately $54.6 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Cornerstone Acquisition consisted of approximately 26,000 gross producing wells across the Permian, Mid-Continent, Haynesville and other leading U.S. basins.

Both 2021 acquisitions were accounted for as asset acquisitions and the allocation of the purchase price was $55.3 million to proved properties.

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture was 49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. On November 1, 2022, the Joint Venture was dissolved.

Special Purpose Acquisition Company

On January 29, 2021, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, Kimbell Tiger Acquisition Corporation (“TGR”), filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”).

TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which was a subsidiary of the Partnership, and was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination. TGR Sponsor and TGR were consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021.

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On February 8, 2022, TGR consummated its $230.0 million initial public offering (the “TGR IPO”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 to complete a business combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock included as part of the units issued in its initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR (along with TGR Sponsor) on June 30, 2023 in accordance with the terms of its organizational documents. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying consolidated balance sheet of as of December 31, 2023 and treated as accretion of redeemable non-controlling interest in TGR in the accompanying consolidated statements of changes in unitholders’ equity for the year ended December 31, 2023.

NOTE 4—DERIVATIVES

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

At December 31, 2023, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last scheduled trading day of the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying consolidated statements of operations.

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Interest Rate Swaps

On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. On May 17, 2022, the Partnership entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, the Partnership entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The terminations resulted in a $6.4 million gain for the year ended December 31, 2022, which is included in other income (expense) in the accompanying consolidated statements of operations. The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps were recognized as gains or losses in the current period and were presented on a net basis within other income in the accompanying consolidated statements of operations. As of December 31, 2021, the interest rate swap had a total notional amount of $150.0 million and a fair value of $1.8 million.

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in the fair value consisted of the following:

	Year Ended December 31,
	2023		2022		2021
Beginning fair value of derivative instruments	$	(12,324,076)	$	(26,624,646)	$	(6,280,863)
Gain (loss) on commodity derivative instruments, net		20,888,972		(32,240,915)		(41,240,942)
Net cash paid on settlements of derivative instruments		5,482,086		46,541,485		20,897,159
Ending fair value of derivative instruments	$	14,046,982	$	(12,324,076)	$	(26,624,646)

The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:

		December 31,		December 31,
Classification	Balance Sheet Location	2023		2022
Assets:
Current assets	Derivative assets	$	11,427,735	$	—
Long-term assets	Derivative assets		2,888,051		754,786
Liabilities:
Current liabilities	Derivative liabilities		(208,710)		(12,646,720)
Long-term liabilities	Derivative liabilities		(60,094)		(432,142)
		$	14,046,982	$	(12,324,076)

At December 31, 2023, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
January 2024 - December 2024	568,926	$	79.04	$	69.30	$	85.34
January 2025 - December 2025	563,526	$	70.36	$	64.35	$	77.01

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
January 2024 - December 2024	5,285,182	$	3.97	$	3.06	$	4.48
January 2025 - December 2025	5,153,291	$	3.81	$	3.50	$	4.37

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NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2023 and 2022 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

● Level 1—Unadjusted quoted market prices for identical assets or liabilities in active markets.

● Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability.

● Level 3— Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the years ended December 31, 2023 and 2022.

The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
December 31, 2023
Assets
Commodity derivative contracts	$	—	$	14,315,786	$	—	$	—	$	14,315,786
Liabilities
Commodity derivative contracts	$	—	$	(268,804)	$	—	$	—	$	(268,804)
December 31, 2022
Assets
Commodity derivative contracts	$	—	$	754,786	$	—	$	—	$	754,786
Assets of consolidated variable interest entities:
Investments held in trust	$	240,621,146	$	—	$	—	$	—	$	240,621,146
Liabilities
Commodity derivative contracts	$	—	$	(13,078,862)	$	—	$	—	$	(13,078,862)

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NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	December 31,		December 31,
	2023		2022
Oil and natural gas properties
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Less: accumulated depreciation, depletion and impairment		(827,033,944)		(712,716,951)
Total oil and natural gas properties	$	1,221,656,144	$	753,268,767

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 Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved developed reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheets. Short-term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2023 is 5.43 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2023.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations. The total operating lease expense recorded for the years ended December 31, 2023, 2022 and 2021 was $0.6 million, $0.5 million and $0.4 million, respectively.

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Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.

Maturities of lease liabilities as of December 31, 2023 are as follows:

	Total		2024		2025		2026		2027		2028		Thereafter
Operating leases	$	2,712,673	$	488,725	$	497,033	$	507,648	$	511,917	$	496,785	$	210,565
Less: Imputed Interest		(476,273)
Total	$	2,236,400

NOTE 8—LONG-TERM DEBT

On June 13, 2023, the Partnership entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027. In connection with the A&R Credit Agreement, the Partnership recorded a loss on extinguishment of debt of $0.5 million as a result of writing off all unamortized loan origination costs associated with the lenders to the Partnership’s existing credit agreement that did not participate in the A&R Credit Agreement.

On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amended the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit the Partnership to issue certain preferred equity interests.

On December 8, 2023, in connection with the November 1, 2023 redetermination, the Partnership entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.

The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (a) the Secured Overnight Financing Rate (as defined in the A&R Credit Agreement) plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The secured revolving credit facility is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least 75% of the PV-9 of the proved reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders, with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. The next scheduled redetermination will be on or around May 1, 2024.

Customary borrowing base reductions and mandatory prepayments are required under the A&R Credit Agreement in connection with certain sales of certain types of borrowing base properties, sales of equity interests in guarantor subsidiaries owning such properties, certain debt issuances or certain types of swap terminations. In addition, Cash Balance (as defined in the First Amendment) above $50.0 million is required to be applied weekly to prepay loans (without a commitment reduction) if not otherwise reduced to zero in a manner permitted by the A&R Credit Agreement.

The Partnership is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the secured revolving credit facility. The Partnership is also required to pay customary letter of credit and fronting fees.

F-22

The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) 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.

The A&R Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions.

Additionally, the A&R Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Partnership does not comply with the financial and other covenants in the A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the A&R Credit Agreement and any outstanding unfunded commitments may be terminated.

During the year ended December 31, 2023, the Partnership borrowed an additional $201.1 million under the secured revolving credit facility and repaid approximately $139.9 million of the outstanding borrowings. As of December 31, 2023, the Partnership’s outstanding balance was $294.2 million and there were no outstanding letters of credit under the secured revolving credit facility. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2023.

As of December 31, 2023, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.25% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.25%. For the year ended December 31, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.62%.

NOTE 9—PREFERRED UNITS

On August 2, 2023, the Partnership entered into a Series A preferred unit purchase agreement with certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) to issue and sell up to 400,000 Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”). On September 13, 2023, in connection with the closing of the LongPoint Acquisition, the Partnership completed the private placement of 325,000 Series A preferred units to the Series A Purchasers for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $325.0 million (the “Preferred Unit Transaction”). The Partnership used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company (“OpCo preferred units”). The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to the Partnership’s common units with respect to distribution rights and rights upon liquidation.

Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. The Partnership has 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 the Partnership makes such an election in consecutive quarters or if the Partnership fails to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its 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 the Partnership of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. The Partnership cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to a liquidation of the Partnership, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying

F-23

the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.

At any time on or after the second anniversary of the original issuance date, the Partnership will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) the Partnership has an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the original issuance date, a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units.

In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date.

The terms of the Series A preferred units contain covenants preventing the Partnership 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.

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of December 31, 2023, the Partnership had a total of 73,851,458 common units issued and outstanding and 20,847,295 Class B units outstanding.

On August 7, 2023, the Partnership completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). The Partnership used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes.

In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $116.1 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

F-24

In November 2021, the Partnership completed an underwritten public offering of 4,312,500 common units for net proceeds of approximately $57.7 million (the “2021 Equity Offering”). The Partnership used the net proceeds from the 2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $56.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

The following table summarizes the changes in the number of the Partnership’s common units:

	Common Units
Balance at December 31, 2022	64,231,833
Common units issued under the A&R LTIP (1)	998,162
Restricted units repurchased for tax withholding	(279,662)
Common unit issued for acquisition	557,302
Common units issued for equity offering	8,337,500
Conversion of Class B units	6,323
Balance at December 31, 2023	73,851,458

(1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “A&R LTIP”) on February 21, 2023.

The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:

	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2023	$	0.35	May 3, 2023	May 15, 2023	May 22, 2023
Q2 2023	$	0.39	August 2, 2023	August 14, 2023	August 21, 2023
Q3 2023	$	0.51	November 2, 2023	November 13, 2023	November 20, 2023
Q4 2023	$	0.43	February 21, 2024	March 13, 2024	March 20, 2024
Q1 2022	$	0.47	April 22, 2022	May 2, 2022	May 9, 2022
Q2 2022	$	0.55	August 3, 2022	August 15, 2022	August 22, 2022
Q3 2022	$	0.49	November 3, 2022	November 14, 2022	November 21, 2022
Q4 2022	$	0.48	February 23, 2023	March 9, 2023	March 16, 2023
Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021
Q3 2021	$	0.37	October 22, 2021	November 1, 2021	November 8, 2021
Q4 2021	$	0.37	January 21, 2022	January 31, 2022	February 7, 2022

The following table summarizes the changes in the number of the Partnership’s Class B units:

	Class B Units
Balance at December 31, 2022	15,484,400
Class B units issued for acquisition	5,369,218
Conversion of Class B units	(6,323)
Balance at December 31, 2023	20,847,295

For each Class B unit issued, five cents have been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units are 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 the common units and OpCo common units.

Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to

F-25

receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP.  The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

NOTE 11—EARNINGS PER COMMON UNIT

Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s A&R LTIP are nonparticipating securities.

The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per common unit:

	Year Ended December 31,
	2023		2022		2021
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		1,572,737		(17,412,732)		—
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		61,714,416		94,516,759		22,615,021
Distribution and accretion on Series A preferred units		6,310,215		—
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		16,553,676		18,864,795		8,496,104
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	84,578,307	$	113,381,554	$	31,111,125
Weighted average number of common units outstanding:
Basic		66,595,273		54,112,595		40,400,907
Effect of dilutive securities:
Series A preferred units		6,499,350		—		—
Class B units		18,851,387		10,819,266		18,839,607
Restricted units		1,111,721		905,156		1,717,310
Diluted		93,057,731		65,837,017		60,957,824
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51

The calculation of diluted net income per share for the year ended December 31, 2023 includes the conversion of Series A preferred units to common units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net income per share for the years ended December 31, 2022 and 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and unvested restricted units calculated using the treasury stock method.

NOTE 12—UNIT-BASED COMPENSATION

On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-

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Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by 3,700,000 common units for a total of 8,241,600 common units. The Partnership’s A&R LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s A&R LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors.

Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the A&R LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units.

		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2022	1,897,192	$	13.553	1.517 years
Awarded	998,162		15.020	—
Vested	(943,924)		12.602	—
Unvested at December 31, 2023	1,951,430	$	14.763	1.525 years

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate. The Partnership incurred $3.8 million and $2.7 million of income taxes for the years ended December 31, 2023 and 2022, respectively, and a de minimis amount of income taxes during the year ended December 31, 2021.

The Partnership has filed all tax returns to date that are currently due.

The Partnership’s effective income tax rate was 4.34% for the year ended December 31, 2023. The Partnership earned income before taxes, as calculated under GAAP,  for the current year and is recording a current income tax expense of $3.8 million primarily related to income that was not sheltered due to depletion and other non-cash deductions.

	Year Ended December 31,
	2023		2022		2021
Current
Federal	$	2,469,584	$	2,412,702	$	69,067
State		1,296,718		326,000		5,033
Total Current		3,766,302		2,738,702		74,100
Deferred
Federal		—		—		—
State		—		—		—
Total Deferred		—		—		—
Provision for income taxes	$	3,766,302	$	2,738,702	$	74,100

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The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pre-tax income principally due the effect of the following items:

	Year Ended December 31,
	2023			2022			2021
Net income before taxes	$	86,771,872		$	133,532,988		$	42,511,974
Statutory rate		21	%		21	%		21	%
Income tax provision computed at statutory rate		18,222,093			28,041,927			8,927,515
Reconciling items:
State income taxes		1,393,149			326,000			5,033
Non-controlling interest		(3,518,924)			(3,988,366)			(1,788,347)
Income at OpCo		(14,703,170)			(24,053,561)			(7,139,168)
Change in valuation allowance - federal		2,860,951			2,202,314			(363,132)
Change in valuation allowance - state		(96,431)			(1,307,605)			(40,626)
Other, net		(391,366)			1,517,993			472,825
Provision for income taxes	$	3,766,302		$	2,738,702		$	74,100

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below.

	Year Ended December 31,
	2023		2022		2021
Deferred tax asset
Outside basis in OpCo	$	22,624,765	$	18,494,572	$	6,641,452
Federal tax loss carryforwards		—		2,645,475		12,296,282
State tax loss carryforwards		385,926		482,356		1,789,961
Business interest deduction limitation		1,376,234		—		—
Deferred tax asset		24,386,925		21,622,403		20,727,695
Valuation allowance		(24,386,925)		(21,622,403)		(20,727,695)
Net deferred tax asset	$	—	$	—	$	—

The tax years ended December 31, 2020 through 2023 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $24.4 million on the deferred tax assets.

As of December 31, 2023, the Partnership has not recorded a reserve for any uncertain tax positions.

NOTE 14—RELATED PARTY TRANSACTIONS

The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders.

During the year ended December 31, 2023, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2023, the Partnership made payments to K3 Royalties in the amount of $120,000.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of

F-28

approximately $26,500 for the year ended December 31, 2023, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $602,600 for the year ended December 31, 2023.

The Partnership received $180,626 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the year ended December 31, 2023.

Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per quarter for office space utilities, secretarial support and administrative services provided to members of the management team. During the year ended December 31, 2023, TGR incurred $50,000 as part of this service agreement. Such fees were eliminated in consolidation. Upon TGR’s liquidation, TGR ceased paying these monthly fees.

NOTE 15—ADMINISTRATIVE SERVICES

On September 13, 2023, in connection with the LongPoint Acquisition and pursuant to the terms of the securities purchase agreement, a transition services agreement (the “Transition Services Agreement”) by and between the Operating Company and FourPoint Energy, LLC (“FourPoint”), the former manager of the acquired assets, became effective. Pursuant to the Transition Services Agreement, FourPoint provided certain administrative services and accounting assistance on a transitional basis for a monthly service fee of approximately $250,000 for the four-month period ending January 13, 2024, at which the Transition Services Agreement was terminated by the Partnership. During the year ended December 31, 2023, the Partnership paid $0.9 million in Transition Services Agreement costs.

NOTE 16—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of December 31, 2023.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to December 31, 2023 in the preparation of its consolidated financial statements.

Distributions

On February 21, 2024, the Board of Directors declared a quarterly cash distribution of $0.43 per common unit and $0.453897 per OpCo common unit for the quarter ended December 31, 2023. The Partnership intends to pay this distribution on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024.

As to the Partnership, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by the Partnership in the fourth quarter of 2023. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2023. We intend to pay the distribution subsequent to March 13, 2024 and prior to the distribution on the common units and OpCo common units.

Executive Bonus and LTIP Issuance

On February 19, 2024, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of approximately $2.5 million and the issuance of 1,087,502 restricted units to its employees and directors.

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NOTE 18—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,		December 31,
	2023		2022
Oil, natural gas and NGL interests
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Total oil, natural gas and NGL interests		2,048,690,088		1,465,985,718
Accumulated depreciation, depletion, accretion and impairment		(827,033,944)		(712,716,951)
Net oil, natural gas and NGL interests capitalized	$	1,221,656,144	$	753,268,767

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

	Year Ended December 31,
	2023		2022		2021
Acquisition costs
Proved properties	$	260,145,370	$	56,848,235	$	55,300,252
Unevaluated properties		322,559,000		204,742,000		—
Total		582,704,370		261,590,235		55,300,252
Development costs
Proved properties		—		—		—
Total		—		—		—
Total costs incurred on oil, natural gas and NGL activities	$	582,704,370	$	261,590,235	$	55,300,252

Results of Operations from Oil, Natural Gas and NGL Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

	Year Ended December 31,
	2023		2022		2021
Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021
Lease bonus and other income		5,594,855		3,073,609		3,319,104
Production and ad valorem taxes		(20,326,477)		(16,238,814)		(10,480,481)
Depreciation and depletion expense		(96,477,003)		(50,086,414)		(36,797,881)
Impairment of oil and natural gas properties		(18,220,173)		—		—
Marketing and other deductions		(12,564,619)		(13,383,074)		(12,048,643)
Results of operations from oil, natural gas and NGLs	$	125,591,368	$	205,329,433	$	119,080,120

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves. The estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2023, 2022 and 2021. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

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Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and 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. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

	Crude Oil and		Natural Gas
	Condensate	Natural Gas	Liquids	Total
	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Net proved reserves at January 1, 2021	12,294	144,233	6,085	42,418
Revisions of previous estimates (1)	251	24,079	780	5,044
Purchase of minerals in place (2)	1,310	8,537	519	3,252
Production	(1,344)	(19,085)	(715)	(5,240)
Net proved reserves at December 31, 2021	12,511	157,764	6,669	45,474
Revisions of previous estimates (1)	(58)	17,119	759	3,554
Purchase of minerals in place (3)	1,328	5,726	707	2,989
Production	(1,426)	(20,311)	(747)	(5,558)
Net proved reserves at December 31, 2022	12,355	160,298	7,388	46,459
Revisions of previous estimates (1)	3,273	26,068	814	8,432
Purchase of minerals in place (4)	6,565	41,560	4,400	17,892
Production	(2,393)	(23,384)	(1,083)	(7,374)
Net proved reserves at December 31, 2023	19,800	204,542	11,519	65,409
Net proved developed reserves
December 31, 2021	12,511	157,764	6,669	45,474
December 31, 2022	12,355	160,298	7,388	46,459
December 31, 2023	19,800	204,542	11,519	65,409

(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

(2) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins.

(3) Includes the acquisition of mineral and royalty interests for a total of $56.8 million, primarily consisting of mineral and royalty interests in the Permian Basin.

(4) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

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Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Future cash inflows	$	2,226,313	$	2,253,273	$	1,335,917
Future production costs		(164,848)		(161,676)		(100,947)
Future state margin taxes		(49,144)		(76,322)		(42,965)
Future net cash flows		2,012,321		2,015,275		1,192,005
Less 10% annual discount to reflect timing of cash flows		(1,037,192)		(1,110,980)		(665,390)
Standard measure of discounted future net cash flows	$	975,129	$	904,295	$	526,615

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2023, 2022 and 2021 were $78.22, $93.67 and $66.56 per barrel for crude oil and $2.64, $6.36 and $3.60 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Standardized measure - beginning of year	$	904,295	$	526,615	$	284,996
Sales, net of production costs		(236,953)		(252,597)		(152,751)
Net changes of prices and production costs related to future production		(302,599)		365,427		225,868
Revisions of previous quantity estimates, net of related costs		128,727		71,776		60,517
Net changes in state margin taxes		10,433		(15,266)		(8,665)
Accretion of discount		78,425		44,280		25,743
Purchases of reserves in place		435,230		77,719		40,545
Timing differences and other		(42,429)		86,341		50,362
Standardized measure - end of year	$	975,129	$	904,295	$	526,615

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EX-4.5

Exhibit 4.5

DESCRIPTION OF SECURITIES REGISTERED PURSUANT TO SECTION 12 OF THE SECURITIES
EXCHANGE ACT OF 1934, AS AMENDED

Kimbell Royalty Partners, LP (the “Partnership,” “we,” “us,” and “our”), has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended: common units representing limited partnership interests in the Partnership (“common units”). The following description of our common units is a summary and does not purport to be complete. It is subject to, and qualified in its entirety by reference to, our Fifth Amended and Restated Agreement of Limited Partnership, dated as of September 13, 2023 (the “partnership agreement”), and our Certificate of Limited Partnership, dated as of October 30, 2015 (the “certificate of limited partnership”), which we have filed or incorporated by reference to our Annual Report on Form 10-K. We encourage you to read the complete text of our partnership agreement, certificate of limited partnership and applicable provisions of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”).

Our Common Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners holding common units under our partnership agreement.

Subject to the distribution preferences of our Series A Cumulative Convertible Preferred Units (“Series A preferred units”) and Class B common units representing limited partner interests in us (“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.

Our Class B Units

The Class B units represent limited partner interests in us. The holders of Class B units are only entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners holding Class B units under our partnership agreement. 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”).

The Class B units are identical to the common units, except that the Class B units (i) are entitled to receive cash distributions from operations or upon our liquidation or winding up equal to 2.0% per quarter on their respective Class B Contribution prior to distributions on our common units, (ii) are not transferable (except to certain affiliates of holders of Class B units, so long as the transferring holder of the Class B units simultaneously transfers an equal number of common units representing limited liability company interests (“OpCo common units”) in our operating subsidiary, Kimbell Royalty Operating, LLC (the “Operating Company”), to such affiliate in accordance with the limited liability company agreement of the Operating Company), (iii) are exchangeable, together with an equal number of OpCo common units, for common units, (iv) do not have the benefit of registration rights and (v) if at any time any record holder of one or more Class B units does not hold an equal number of Class B units and OpCo common units, we will issue additional Class B units to such holder or cancel Class B units held by such holder, as applicable, such that the number of Class B units held by such holder is equal to the number of OpCo common units held by such holder.

Listing

Our common units are traded on the New York Stock Exchange under the symbol “KRP.” Our Class B units are not, and will not be, listed on any securities exchange. As of February 16, 2024, there were 73,851,458 common units outstanding and 20,847,295 Class B units outstanding.

1

Transfer of Common Units and Class B Units

By transfer of common units and Class B units in accordance with our partnership agreement, each transferee of common units and Class B units shall be admitted as a limited partner with respect to the class of units transferred when such transfer and admission are reflected in our books and records. Each transferee:

● represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

● automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

● gives the consents and approvals contained in our partnership agreement.

A transferee will become a substituted limited partner of our partnership for the transferred units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit or Class B unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units and Class B units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred units.

Until a common unit or Class B unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Series A Cumulative Convertible Preferred Units

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and with the designations, preferences, rights, powers and duties established by our general partner without the approval of any of our limited partners, except that we will need the consent of 662∕3% of the outstanding Series A preferred units to 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. In accordance with Delaware law and the provisions of our partnership agreement and subject to the rights of the holders of the Series A preferred units, we may issue additional partnership interests that have special voting rights to which our common units are not entitled. As of February 16, 2024, we had one series of preferred units outstanding, the Series A preferred units, and there were 325,000 Series A preferred units outstanding.

Distributions

The Series A preferred units rank senior to all classes or series of limited partner interests of ours with respect to distribution rights. 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 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 securities that rank junior in distribution rights to the Series A preferred units, 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.

2

Voting Rights

The Series A preferred units vote on an as-converted basis with the common units and have certain other class voting rights, including with respect to certain incurrences of debt and any amendment to our partnership agreement if the amendment is materially adverse to any of the rights, preferences and privileges of the Series A preferred units.

Conversion

Beginning with the earlier of (i) the second anniversary of the date that the Series A preferred units were issued (the “Series A Issuance Date”) and (ii) immediately prior to a liquidation of us, each holder of the Series A preferred units may, at any time (but not more often than once per quarter), elect to convert all or any portion of its Series A preferred units into a number of common units determined by multiplying the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that any conversion (a) is for an amount of common units with an aggregate value of at least $10 million or such lesser amount that covers all of such holder’s (and its affiliates’) remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Series A Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.

At any time on or after the second anniversary of the Series A Issuance Date, we have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10 million or such lesser amount that covers all of such holder’s (and its affiliates’) Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Series A Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) we have an effective registration statement on file with the Securities and Exchange Commission covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.

Redemption

At our option at any time or at the option of the holders of the Series A preferred units beginning seven years after the Series A Issuance Date or in the event of a change of control, the Series A preferred units may be redeemed for a cash amount per Series A preferred unit (the “Series A Redemption Price”) equal to the product of (A) the number of outstanding Series A preferred units multiplied by (B) the greatest of (1) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (2) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (3) $1,000 per Series A preferred unit plus accrued and unpaid distributions. For purposes of this paragraph, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the Series A Issuance Date, a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary of the Series A Issuance Date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the Series A Issuance Date, a 14.0% internal rate of return with respect to the Series A preferred units.

Board Rights

In connection with the issuance of the Series A preferred units, the holders of the Series A preferred units have the right to appoint one observer to the Board of Directors of our general partner (the “Board of Directors”) beginning five years after the Series A Issuance Date. The holders of the Series A preferred units have the right to appoint one member of the Board of Directors beginning six years after the Series A Issuance Date, and two additional members of the Board of Directors beginning seven years after the Series A Issuance Date.

Cash Distribution Policy

Our 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” is defined in the limited liability company agreement of the Operating Company and our partnership agreement.

3

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will pay cash distributions to our unitholders each quarter. Our cash distribution policy is subject to certain restrictions, including the following:

● Our sole cash-generating asset is our membership interest in the Operating Company. Therefore, our cash flow and resulting ability to make distributions is completely dependent upon the ability of the Operating Company to make distributions.

● Our credit agreement contains, and our future debt agreements or other securities we may issue in the future may contain, certain financial tests and covenants that we would have to satisfy. We may also be prohibited from paying distributions if an event of default or borrowing base deficiency exists under our secured revolving credit facility. If we are unable to satisfy any current or future debt agreements, we could be prohibited from paying a distribution to you notwithstanding our stated distribution policy.

● Our business performance may be volatile, and our cash flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

● We do not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests are subordinate in right of distribution payment to the common units.

● Our general partner has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Neither our partnership agreement nor the limited liability company agreement of the Operating Company sets a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.

● Prior to paying any distributions, we and the Operating Company will reimburse our general partner and its affiliates, including Kimbell Operating Company, LLC, a wholly owned subsidiary of our General Partner (“Kimbell Operating”), pursuant to its management services agreement discussed below, for all direct and indirect expenses they incur on our behalf. 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, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. In addition, we have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate service agreements with certain entities controlled by affiliates of certain of our founders and certain entities and individuals, including affiliates of our founders, that contributed, directly or indirectly, certain mineral and royalty interests (the “Contributing Parties”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates, including Kimbell Operating, and to such other entities providing services to us and Kimbell Operating, will reduce the amount of cash to pay distributions to our common unitholders.

● Prior to distributions on our common units, each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution.

● Prior to distributions on our common units and Class B units, each holder of Series A preferred units is entitled to receive a cumulative quarterly distribution equal to 6.0% per annum plus any accrued and unpaid distribution.

● Under Section 17-607 of the Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not pay a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

● We may lack sufficient cash to pay distributions to our common unitholders due to cash flow shortfalls attributable to a number of commercial or other factors as well as increases in general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

4

How We Pay Distributions

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 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:

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

● 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

● 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. Please read “Cash Distribution Policy.”

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” for any quarter as:

● the sum of:

● all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and

● as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter;

● less the amount of cash reserves established by the managing member of the Operating Company to:

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● provide for the proper conduct of the business of the Operating Company and its subsidiaries (including reserves for future capital expenditures and for future credit needs of the Operating Company and its subsidiaries);

● comply with applicable law or any debt instrument or other agreement or obligation to which the managing member of the Operating Company, the Operating Company or any of their subsidiaries is a party or to which its assets are subject; and

● provide funds for distributions to the Operating Company’s unitholders for any one or more of the next four quarters.

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. Please read “Cash Distribution Policy.”

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:

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

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

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

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

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the outstanding common units, Class B units and Series A preferred units (voting on an as-converted basis), voting together as a single class, except that the outstanding Series A preferred units will not vote with the outstanding common units and Class B units on any amendment to our partnership agreement requiring the approval of the outstanding common units pursuant to Section 13.3(c) of our partnership agreement.

In voting their common units, our general partner and its affiliates have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied covenant of good faith and fair dealing. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called (including units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

Issuance of additional units

No approval right by common unitholders; certain issuances require approval by 662∕3% of the holders of our Series A preferred units. Please read “Issuance of Additional Partnership Interests.”

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders, and certain other amendments that would materially adversely affect any of the rights, preferences and privileges of the Series A preferred units require the approval of holders of 662∕3% of the Series A preferred units. Certain amendments that would alter, amend or repeal the voting rights of the Class B units or adopt any provision of our partnership agreement inconsistent with the voting rights of the Class B units will require the approval of holders of a majority of the Class B units. Other amendments generally require the approval of the holders of a unit majority. Please read “Amendment of the Partnership Agreement.”

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Merger of our partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances, and if such merger or sale would materially adversely affect any of the rights, preferences and privileges of the Series A preferred units, the affirmative vote of 662∕3% of Series A preferred units. Please read “Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “Dissolution.”
Continuation of our business upon dissolution	Unit majority. Please read “Dissolution.”
Withdrawal of our general partner	Under most circumstances, the approval of unitholders holding a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2026 in a manner that would cause a dissolution of our partnership. Please read “Withdrawal or Removal of Our General Partner.”
Removal of our general partner	Not less than 662∕3 % of the outstanding units, including common units and Class B units held by our general partner and its affiliates, for cause. Any removal of our general partner is also subject to the approval of a successor general partner by the holders of a unit majority. Please read “Withdrawal or Removal of Our General Partner.”
Transfer of our general partner interest	Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read “Transfer of General Partner Interest.”
Transfer of ownership interests in our general partner	No unitholder approval required. Please read “Transfer of Ownership Interests in Our General Partner.”

If any person or group other than (a) our general partner and its affiliates, (b) the Contributing Parties and their respective affiliates, (c) a direct or subsequently approved transferee of our general partner or its affiliates, (d) purchasers specifically approved by our general partner, (e) any holder of Series A preferred units in connection with any vote, consent or approval of the Series A preferred units as a separate class, or on an as-converted basis with the holders of the common units, on any matter, or (f) any person or group who owns 20% or more of our partnership interests of a class as the result of (i) any redemption or purchase of any other person’s or persons’ partnership interests by us or other similar action by us or (ii) any conversion of Series A preferred units into common units, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group loses voting rights on all of its units.

Voting Rights of Class B Units

Each holder of Class B units is entitled to receive notice of, be included in any requisite quora for, and participate in any and all approvals, votes or other actions of our partners on a pro rata basis as, and treating such persons for all purposes as if they are, unitholders holding our common units, including any and all notices, quora, approvals, votes and other actions that may be taken pursuant to the requirements of the Delaware Act or any other applicable law, rule or regulation, except as otherwise explicitly provided in our partnership agreement. The affirmative vote of the holders of a majority of the voting power of all Class B units voting separately as a class is required to alter, amend or repeal this provision or to adopt any provision of our partnership agreement inconsistent with this provision.

Voting Rights of Series A Preferred Units

The affirmative vote of 662∕3% of the Series A preferred units, voting separately as a class, is required for us to, or to permit any of our subsidiaries to (in each case, directly or indirectly, including by way of amendment to our partnership agreement, by merger, consolidation, reclassification or otherwise), take certain actions specified in our partnership agreement, including (a) amending or amending and restating our partnership agreement, our certificate of limited partnership or the organizational documents of our subsidiaries if such amendment is materially adverse to any of the rights, preferences and privileges of the Series A preferred units and (b) issuing, authorizing or creating 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.

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Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Kimbell Royalty GP, LLC as our general partner or from otherwise changing our management. Please read “- Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than (a) our general partner and its affiliates, (b) the Contributing Parties and their respective affiliates, (c) a direct or subsequently approved transferee of our general partner or its affiliates, (d) purchasers specifically approved by our general partner, (e) any holder of Series A preferred units in connection with any vote, consent or approval of the Series A preferred units as a separate class, or on an as-converted basis with the holders of the common units, on any matter or (f) any person or group who owns 20% or more of our partnership interests of a class as the result of (i) any redemption or purchase of any other person’s or persons’ partnership interests by us or other similar action by us, or (ii) any conversion of Series A preferred units into common units, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group loses voting rights on all of its units.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under the heading “Limited Liability.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he, she or it otherwise acts in conformity with the provisions of the partnership agreement, his, her or its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he, she or it is obligated to contribute to us for his, her or its common units plus his, her or its share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

● to remove or replace our general partner for cause;

● to approve some amendments to our partnership agreement; or

● to take other action under our partnership agreement,

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to such person at the time he, she or it became a limited partner and that could not be ascertained from our partnership agreement.

Our subsidiaries conduct business in 28 states and we may have subsidiaries that conduct business in additional states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our

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general partner for cause, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders except that we will need the consent of 662∕3% of the outstanding Series A preferred units to 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.

Subject to certain limited exceptions, we will not issue any additional common units unless we contribute the net cash proceeds or other consideration received from the issuance of such additional common units to the Operating Company in exchange for an equivalent number of OpCo common units. It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, subject to the voting rights of the Series A preferred units, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which our common units and Class B units are not entitled. In addition, subject to the voting rights of the Series A preferred units, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior in right of distributions or liquidation to our common units and Class B units.

Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The common unitholders do not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner has no duty or obligation to propose any amendment and may decline to propose or approve any amendment to our partnership agreement in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by the holders of a unit majority. In addition, (i) any amendment that materially adversely affects any of the rights, preferences and privileges of the Series A preferred units must be approved by the affirmative vote of 662∕3% of the Series A preferred units, voting separately as a class, and (ii) any amendment that would alter, amend or repeal the voting rights of the Class B units or adopt any provision of our partnership agreement inconsistent with the voting rights of the Class B units must be approved by the affirmative vote of the holders of a majority of the voting power of all Class B units voting separately as a class.

Prohibited Amendments

No amendment may be made that would:

● enlarge the duties or payment obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

● enlarge the duties or payment obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

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The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates).

No Limited Partner Approval

Subject to the voting rights of the Series A preferred units and Class B units, our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

● a change in our name, the location of our principal office, our registered agent or our registered office;

● the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

● a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state;

● a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

● an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

● an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;

● any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

● an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

● any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with our conduct of activities as otherwise permitted by our partnership agreement;

● an amendment providing that any transferee of a limited partner interest (including any nominee holder or an agent or representative acquiring such limited partner interest for the account of another person) shall be deemed to certify that the transferee is not an Ineligible Holder (as defined below);

● conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

● any other amendments substantially similar to any of the matters described in the clauses above.

In addition, subject to the voting rights of the Series A preferred units, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

● do not adversely affect in any material respect the limited partners, considered as a whole, or any particular class of partnership interests as compared to other classes of partnership interests;

● are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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● are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

● are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

● are required to effect the intent expressed in the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

The affirmative vote of 662∕3% of the Series A preferred units, voting separately as a class, is necessary on any matter (including a merger, consolidation or business combination) that would materially adversely affect any of the rights, preferences and privileges of the Series A preferred units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner has no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Further, the affirmative vote of 662∕3% of the Series A preferred units, voting separately as a class, is required for certain asset sales or if any such sale, merger, consolidation or other combination is materially adverse to any of the rights, preferences and privileges of the Series A preferred units. Please read “- Voting Rights.” Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to the partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

● the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

● there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

● the entry of a decree of judicial dissolution of our partnership; or

● the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

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Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that the action would not result in the loss of limited liability under Delaware law of any limited partner.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as set forth in our partnership agreement. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Upon our liquidation, dissolution and winding up, the holders of the Series A preferred units will be entitled to receive, prior to any distribution of any of our assets to the holders of our common units or to the holders of any other class or series of our equity securities, an amount per Series A preferred unit equal to the Series A Redemption Price. After making such distribution to the holders of the Series A preferred units, and prior to making any distribution of any of our assets to the holders of our common units, the holders of the then outstanding Class B units will be entitled to receive the Class B Contribution in respect of each such Class B unit.

Withdrawal or Removal of Our General Partner

Except as provided below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2026 without obtaining the approval of the holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability. On or after December 31, 2026, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “Transfer of General Partner Interest.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “Dissolution.”

Our general partner may not be removed unless that removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 662∕3% of the outstanding units, voting together as a single class, including common units and Class B units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a unit majority. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable to the partnership or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Under this definition, “cause” generally does not include charges of poor management of the business. The ownership of more than 331∕3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal.

In the event of the removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

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In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or any third party without the approval of our unitholders.

Limited Call Right

If at any time our general partner and its affiliates (including our founders and their respective affiliates) hold more than 80% of the sum of (i) the number of common units then outstanding and (ii) the number of Class B units then outstanding equal to the number of OpCo common units, our general partner shall then have the right, which right it may assign and transfer in whole or in part to any of its affiliates or to us, exercisable at our general partner’s option, to purchase all, but not less than all, of such common units and Class B units (and treating the common units and Class B units as a single class of units) then outstanding held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

● the highest per unit price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased during the 90 day period preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

● the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his, her or its limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future.

Ineligible Holders; Redemption

Under our partnership agreement, an “Ineligible Holder” is a limited partner whose, or whose owners’, 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 at any time our general partner determines, with the advice of counsel, that one or more limited partners are Ineligible Holders, then our general partner may request any limited partner to furnish to our general partner an executed certification or other information about his, her or its nationality, citizenship or related status. If a limited partner fails to furnish such certification or other requested information within 30 days (or such other period as our general partner may determine) after a request for such certification or other information, or our general partner determines after receipt of the information that the limited partner is an Ineligible Holder, the limited partner may be treated as an Ineligible Holder. An Ineligible Holder does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of our units of any holder that our general partner concludes is an Ineligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

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Transfer Agent and Registrar

Duties

Equiniti Trust Company, LLC (f/k/a American Stock Transfer & Trust Company, LLC) serves as the registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by unitholders:

● surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

● special charges for services requested by a holder of a common unit; and

● other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

14

EX-21.1

Exhibit 21.1

Subsidiaries of Kimbell Royalty Partners, LP

Entity Name	Jurisdiction
American Assurance 2000, LP	Delaware
Cherry Creek Minerals, LLC	Delaware
Cirrus Minerals, LLC	Delaware
Cobra Petroleum Company, LP	Texas
Haymaker Greenfield, LLC	Delaware
Haymaker Holding Company, LLC	Delaware
Haymaker Properties GP, LLC	Delaware
Haymaker Properties, LP	Delaware
Hochstetter, L.P.	Texas
Kimbell Intermediate GP, LLC	Delaware
Kimbell Knight Royalties, LLC	Delaware
Kimbell Intermediate Holdings, LLC	Delaware
Kimbell MB Energy, LLC	Delaware
Kimbell Merger Sub, LLC	Delaware
Kimbell Royalty Holdings, LLC	Delaware
Kimbell Royalty Operating, LLC	Delaware
KRP Legacy Isles, LLC	Delaware
KRP Legacy NBR, LLC	Delaware
Metcalfe Minerals, LP	Texas
Mustang Minerals, LLC	Delaware
Oakwood Minerals I, L.P.	Texas
OGM Partners I	Texas
Phillips Energy Partners, LLC	Delaware
Phillips Energy Partners II, LLC	Delaware
Phillips Energy Partners III, LLC	Delaware
RCPTX, Ltd.	Texas
Rivercrest Royalties Holdings II, LLC	Delaware
Rivercrest Royalties, LLC	Delaware
Rochester Minerals, L.P.	Texas
Springbok Energy Partners, LLC	Delaware
Springbok Energy Partners II, LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 21, 2024, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Kimbell Royalty Partners, LP on Form 10-K for the year ended December 31, 2023. We consent to the incorporation by reference of said reports in the Registration Statements of Kimbell Royalty Partners, LP on Forms S-3 (File Nos. 333-226425, 333-229417, 333-230986, 333-236341, 333-238330, 333-269264, 333-272307, 333-273609 and 333-274726) and on Forms S-8 (File Nos. 333-217986, 333-228678 and 333-265288).

/s/ GRANT THORNTON LLP

Dallas, Texas

February 21, 2024

EX-23.2

Exhibit 23.2

	TBPE REGISTERED ENGINEERING FIRM F-1580
	633 SEVENTEENTH STREET SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-8 (Registration Nos. 333-217986, 333-228678 and 333-265288) and Forms S-3 (Registration Nos. 333-226425, 333-229417, 333-230986, 333-236341, 333-238330, 333-269264, , 333-272307, 333-273609 and 333-274726) of Kimbell Royalty Partners, LP of our letter dated January 25, 2024, relating to estimates of proved reserves, future production and income attributable certain royalty interests of Kimbell Royalty Partners, LP as of December 31, 2023.

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Denver, Colorado

February 21, 2024

EX-23.3

Exhibit 23.3

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statements on Forms S-3 (File Nos. 333-226425, 333-229417, 333-230986, 333-236341, 333-238330, 333-269264, 333-272307, 333-273609 and 333-274726) and Forms S-8 (File Nos. 333-217986, 333-228678 and 333-265288) of Kimbell Royalty Partners, LP of our report dated February 23, 2023, with respect to the consolidated financial statements of Kimbell Tiger Acquisition Corporation, which report appears in the Form 10-K of Kimbell Royalty Partners, LP dated February 21, 2024.

/s/ KPMG LLP

Dallas, Texas

February 21, 2024

EX-23.4

Exhibit 23.4

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of DirectorsKimbell Tiger Acquisition Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Kimbell Tiger Acquisition Corporation and subsidiary (the Company) as of December 31, 2022, the related consolidated statements of operations, changes in stockholders’ deficit, and cash flows for the year ended December 31, 2022 and period from April 9, 2021 (inception) to December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022, and the results of its operations and its cash flows for the year ended December 31, 2022 and period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company does not have sufficient cash flows to satisfy current obligations to creditors upon liquidation, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2021.

Dallas, TexasFebruary 23, 2023

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Robert D. Ravnaas, certify that:

1. I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2024	/s/ Robert D. Ravnaas
	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, R. Davis Ravnaas, certify that:

1. I have reviewed this Annual Report on Form 10-K of Kimbell Royalty Partners, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2024	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)      The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)      The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 21, 2024	/s/ Robert D. Ravnaas
	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Executive Officer)

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-K for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: February 21, 2024	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Financial Officer)

EX-97.1

Exhibit 97.1

KIMBELL ROYALTY PARTNERS, LP

POLICY FOR THE

RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

A.OVERVIEW

In accordance with the applicable rules of The New York Stock Exchange Listed Company Manual (the “NYSE Rules”), Section 10D and Rule 10D-1 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (“Rule 10D-1”), the Board of Directors (the “Board”) of Kimbell Royalty GP, LLC (the “General Partner”), the general partner of Kimbell Royalty Partners, LP (the “Company”), has adopted this Policy (the “Policy”) to provide for the recovery of erroneously awarded Incentive-based Compensation from Executive Officers. All capitalized terms used and not otherwise defined herein shall have the meanings set forth in Section H, below.

B.RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

(1)In the event of an Accounting Restatement, the Company will reasonably promptly recover the Erroneously Awarded Compensation Received in accordance with NYSE Rules and  Rule 10D-1 as follows:

(i) After an Accounting Restatement, the Conflicts and Compensation Committee (if composed entirely of independent directors, or in the absence of such a committee, a majority of independent directors serving on the Board) (the “Committee”) shall determine the amount of any Erroneously Awarded Compensation Received by each Executive Officer and shall promptly notify each Executive Officer with a written notice containing the amount of any Erroneously Awarded Compensation and a demand for repayment or return of such compensation, as applicable.

(a) For Incentive-based Compensation based on (or derived from) the Company’s unit price or total unitholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in the applicable Accounting Restatement:

i. The amount to be repaid or returned shall be determined by the Committee based on a reasonable estimate of the effect of the Accounting Restatement on the Company’s unit price or total unitholder return upon which the Incentive-based Compensation was Received; and

ii. The Company shall maintain documentation of the determination of such reasonable estimate and provide the relevant documentation as required to the NYSE.

(ii) The Committee shall have discretion to determine the appropriate means of recovering Erroneously Awarded Compensation based on the particular facts and circumstances.  Notwithstanding the foregoing, except as set forth in Section B(2) below, in no event may the Company accept an amount that is less than the amount of Erroneously Awarded Compensation in satisfaction of an Executive Officer’s obligations hereunder.

(iii) To the extent that the Executive Officer has already reimbursed the Company for any Erroneously Awarded Compensation Received under any duplicative recovery obligations established by the Company or applicable law, it shall be appropriate for any such reimbursed amount to be credited to the amount of Erroneously Awarded Compensation that is subject to recovery under this Policy.

(iv) To the extent that an Executive Officer fails to repay all Erroneously Awarded Compensation to the Company when due, the Company shall take all actions reasonable and appropriate to recover such Erroneously Awarded Compensation from the applicable Executive Officer. The applicable Executive Officer shall be required to reimburse the Company for any and all expenses reasonably incurred (including legal fees) by the Company in recovering such Erroneously Awarded Compensation in accordance with the immediately preceding sentence.

(2)Notwithstanding anything herein to the contrary, the Company shall not be required to take the actions contemplated by Section B(1) above if the Committee (which, as specified above, is composed entirely of independent directors or in the absence of such a committee, a majority of the independent directors serving on the Board) determines that recovery would be impracticable and any of the following two conditions are met:

(i) The Committee has determined that the direct expenses paid to a third party to assist in enforcing the Policy would exceed the amount to be recovered. Before making this determination, the Company must make a reasonable attempt to recover the Erroneously Awarded Compensation, documented such attempt(s) and provided such documentation to the NYSE; or

(ii) Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of Section 401(a)(13) or Section 411(a) of the Internal Revenue Code of 1986, as amended, and regulations thereunder.

C.DISCLOSURE REQUIREMENTS

The Company shall file all disclosures with respect to this Policy required by applicable U.S. Securities and Exchange Commission (“SEC”) filings and rules.

D.PROHIBITION OF INDEMNIFICATION

The Company shall not be permitted to insure or indemnify any Executive Officer against (i) the loss of any Erroneously Awarded Compensation that is repaid, returned or recovered pursuant to the terms of this Policy, or (ii) any claims relating to the Company’s enforcement of its rights under this Policy. Further, the Company shall not enter into any agreement that exempts any Incentive-based Compensation that is granted, paid or awarded to an Executive Officer from the application of this Policy or that waives the Company’s right to recovery of any Erroneously Awarded Compensation, and this Policy shall supersede any such agreement (whether entered into before, on or after the Effective Date of this Policy).

E.ADMINISTRATION AND INTERPRETATION

This Policy shall be administered by the Committee, and any determinations made by the Committee shall be final and binding on all affected individuals.

The Committee is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy and for the Company’s compliance with NYSE Rules, Section 10D, Rule 10D-1 and any other applicable law, regulation, rule or interpretation of the SEC or NYSE promulgated or issued in connection therewith.

F.AMENDMENT; TERMINATION

The Committee may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary. Notwithstanding anything in this Section F to the contrary, no amendment or termination of this Policy shall be effective if such amendment or termination would (after taking into account any actions taken by the Company contemporaneously with such amendment or termination) cause the Company to violate any federal securities laws, SEC rule or NYSE rule.

G.OTHER RECOVERY RIGHTS

This Policy shall be binding and enforceable against all Executive Officers and, to the extent required by applicable law or guidance from the SEC or NYSE, their beneficiaries, heirs, executors, administrators or other legal representatives. The Committee intends that this Policy will be applied to the fullest extent required by applicable law. Any employment agreement, equity award agreement, compensatory plan or any other agreement or arrangement with an Executive Officer shall be deemed to include, as a condition to the grant of any benefit thereunder, an agreement by the Executive Officer to abide by the terms of this Policy. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of recovery that may be available to the Company under applicable law, regulation or rule or pursuant to the terms of any policy of the Company or any provision in any employment agreement, equity award agreement, compensatory plan, agreement or other arrangement.

H.DEFINITIONS

For purposes of this Policy, the following capitalized terms shall have the meanings set forth below.

(1)“Accounting Restatement” means an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements (a “Big R” restatement), or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (a “little r” restatement).

(2)“Clawback Eligible Incentive Compensation” means all Incentive-based Compensation Received by an Executive Officer (i) on or after the effective date of the applicable NYSE rules, (ii) after beginning service as an Executive Officer, (iii) who served as an Executive Officer at any time during the applicable performance period relating to any Incentive-based Compensation (whether or not such Executive Officer is serving at the time the Erroneously Awarded Compensation is required to be repaid to the Company), (iv) while the Company has a class of securities listed on a national securities exchange or a national securities association, and (v) during the applicable Clawback Period (as defined below).

(3)“Clawback Period” means, with respect to any Accounting Restatement, the three completed fiscal years of the Company immediately preceding the Restatement Date (as defined below), and if the Company changes its fiscal year, any transition period of less than nine months within or immediately following those three completed fiscal years.

(4)“Erroneously Awarded Compensation” means, with respect to each Executive Officer in connection with an Accounting Restatement, the amount of Clawback Eligible Incentive Compensation

that exceeds the amount of Incentive-based Compensation that otherwise would have been Received had it been determined based on the restated amounts, computed without regard to any taxes paid.

(5)“Executive Officer” means each individual who is currently or was previously designated as an “officer” of the Company as defined in Rule 16a-1(f) under the Exchange Act. For the avoidance of doubt, the identification of an executive officer for purposes of this Policy shall include each executive officer who is or was identified pursuant to Item 401(b) of Regulation S-K, as well as the principal financial officer and principal accounting officer (or, if there is no principal accounting officer, the controller).

(6)“Financial Reporting Measures” means measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and all other measures that are derived wholly or in part from such measures. Unit price and total unitholder return (and any measures that are derived wholly or in part from unit price or total unitholder return) shall, for purposes of this Policy, be considered Financial Reporting Measures. For the avoidance of doubt, a Financial Reporting Measure need not be presented in the Company’s financial statements or included in a filing with the SEC.

(7)“Incentive-based Compensation” means any compensation that is granted, earned or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

(8)“NYSE” means the New York Stock Exchange.

(9)“Received” means, with respect to any Incentive-based Compensation,  actual or deemed receipt, and Incentive-based Compensation shall be deemed received in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive-based Compensation award is attained, even if the payment or grant of the Incentive-based Compensation to the Executive Officer occurs after the end of that period.

(10)“Restatement Date” means the earlier to occur of (i) the date the Board, a committee of the Board or the officers of the Company authorized to take such action if Board action is not required, concludes, or reasonably should have concluded, that the Company is required to prepare an Accounting Restatement, or (ii) the date a court, regulator or other legally authorized body directs the Company to prepare an Accounting Restatement.

Effective as of December 1, 2023.

Exhibit A

ATTESTATION AND ACKNOWLEDGEMENT OF POLICY FOR THE RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

By my signature below, I acknowledge and agree that:

· I have received and read the attached Policy for the Recovery of Erroneously Awarded Compensation (this “Policy”).

· I hereby agree to abide by all of the terms of this Policy both during and after my employment with the Company, including, without limitation, by promptly repaying or returning any Erroneously Awarded Compensation to the Company as determined in accordance with this Policy.

Signature:

Printed Name:

Date:

EX-99.1

Exhibit 99.1

KIMBELL ROYALTY PARTNERS, LP

Estimated

Future Reserves and Income

Attributable to Certain

Royalty Interests

SEC Parameters

As of

December 31, 2023

/s/Scott James Wilson

Scott J. Wilson, P.E., MBA

Colorado License No. 36112

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

January 25, 2024

Kimbell Royalty Partners, LP

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of Kimbell Royalty Partners, LP, (KRP) as of December 31, 2023.  The diverse inventory of properties is located primarily in the state of Texas, but with additional properties in 25 other states.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on January 25, 2024 and presented herein, was prepared for public disclosure by KRP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent all the total net proved producing and non - producing liquid and gas reserves of KRP as of December 31, 2023.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2023, are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary considerably from the prices required by SEC regulations.  The reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

Kimbell Royalty Partners, LP

January 25, 2024

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Royalty Interests of

Kimbell Royalty Partners, LP

As of December 31, 2023

		Proved
		Developed				Total
		Producing		Non-Producing		Proved
Net Reserves
Oil/Condensate – MBarrels			17,484		2,316		19,800
Plant Products – MBarrels			10,245		1,274		11,519
Gas – MMCF			177,691		26,851		204,542
Income Data ($M)
Future Gross Revenue		$	1,842,048	$	261,515	$	2,103,563
Deductions			37,000		5,098		42,098
Future Net Income (FNI)		$	1,805,048	$	256,417	$	2,061,465
Discounted FNI @ 10	%	$	852,032	$	146,911	$	998,943

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels).  All gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.

The future gross revenue is after the deduction of production taxes.  Since the evaluation includes only royalty interests, the only deductions included in the cash flows are ad valorem taxes, while the normal direct costs of operating the wells are used only to estimate economic lives.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 81 percent and gas reserves account for the remaining 19 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at four other discount rates which were also compounded monthly.  These results are shown in summary form as follows.

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	Discounted Future Net Income ($M)
	As of December 31, 2023
Discount Rate		Total
Percent		Proved
4		$	1,419,770
6		$	1,237,855
8		$	1,102,928
12		$	916,283

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The proved reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non - producing reserves included herein consist of the behind pipe and shut - in status categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.  The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At KRP’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The proved reserves included herein were estimated using deterministic methods.  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably

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certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

KRP’s royalty interests may be subject to various levels of governmental controls and regulations imposed upon the operators of the subject properties.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which KRP owns a royalty interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

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 set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  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 individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves.  Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator.  Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered

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from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods.  These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through October 2023.  The data utilized in this analysis were furnished to Ryder Scott by KRP and were considered sufficient for the purpose thereof. All of the proved developed non - producing reserves included herein were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically producible proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data, which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

KRP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by KRP with respect to property interests owned, production from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes,development plans, product prices based on the SEC regulations, adjustments or differentials to product prices.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by KRP.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

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Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates were held constant, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied until depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by KRP. Wells that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies

The future production rates from wells currently on production or wells that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

KRP furnished us with the above mentioned average prices in effect on December 31, 2023.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by KRP.  The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by KRP to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the

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total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices		Average Proved Realized Prices
North America
	Oil/Condensate	WTI Cushing	$	78.22/BBL	$	76.84/BBL
United States	Plant Products	WTI Cushing	$	78.22/BBL	$	23.78/BBL
	Gas	Henry Hub	$	2.637/MMBTU	$	2.11/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Estimated operating costs for the leases and wells in this report were furnished by KRP and include only those costs directly applicable to the leases or wells.  Because KRP owns only royalty interests, the operating costs were utilized only to calculate the economic life of each entity.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by KRP.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs are not shown in these cash flows since KRP does not own working interests. However, typical development costs were considered when reviewing the estimates of non - producing inventory, which includes wells in progress. Such costs were used to confirm that these are economically recoverable reserves.

The proved non - producing reserves in this report consist of permitted wells in various stages of development and completion, including wells that have commenced production in 2023 but which KRP had not received revenue by October 2023.

Current costs used by KRP were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have approximately eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned

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or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.  Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training.  Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to KRP.  Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by KRP.

KRP makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act.  Furthermore, KRP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Forms S-3 and S-8 of KRP, of the references to our name, as well as to the references to our third party report for KRP, which appears in the December 31, 2023 annual report on Form 10-K of KRP.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by KRP.

We have provided KRP with a digital version of the original signed copy retained in our files.  In the event there are any differences between the digital version included in filings made by KRP and the original signed copy in our files, the original signed file copy shall control and supersede.

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	/s/Scott James Wilson
	Scott J. Wilson, P.E., MBA
	Colorado License No. 36112
	Senior Vice President
SJW (DRO)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company.  For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at https://www.ryderscott.com/company/employees/denver-employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors.  He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming.  He is also an active  member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology.  He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers.  Mr. Wilson has published several technical papers, one chapter in Marine and Petroleum Geology and two in SPEE monograph 4, which was published in 2016.  He is the primary inventor on four US patents and won the 2017 Reservoir Description and Dynamics award for the SPE Rocky Mountain Region.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states.  As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register.  Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 36 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

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Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.  Reserves are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

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Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not  yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Document Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity Registrant Name	Kimbell Royalty Partners, LP
Entity File Number	001-38005
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-5505475
Entity Address, Address Line One	777 Taylor Street, Suite 810
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	945-9700
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	KRP
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 898.8
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Central Index Key	0001657788
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Name	GRANT THORNTON LLP
Auditor Firm ID	248
Auditor Location	Dallas, Texas
Common Units
Document Information
Entity Common Stock, Shares Outstanding		73,851,458
Class B
Document Information
Entity Common Stock, Shares Outstanding		20,847,295

XML

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 30,992,670	$ 24,635,718
Oil, natural gas and NGL receivables	59,020,471	46,993,711
Derivative assets	11,427,735
Accounts receivable and other current assets	1,699,536	3,562,912
Total current assets	103,140,412	75,192,341
Property and equipment, net	589,895	953,781
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($222,712,844 and $207,695,343 excluded from depletion at December 31, 2023 and 2022, respectively)	2,048,690,088	1,465,985,718
Less: accumulated depreciation, depletion and impairment	(827,033,944)	(712,716,951)
Total oil and natural gas properties	1,221,656,144	753,268,767
Right-of-use assets, net	2,189,243	2,525,323
Derivative assets	2,888,051	754,786
Loan origination costs, net	7,325,471	3,004,104
Total assets	1,337,789,216	1,076,746,299
Current liabilities
Accounts payable	6,594,736	1,210,337
Other current liabilities	6,173,314	4,909,510
Derivative liabilities	208,710	12,646,720
Total current liabilities	12,976,760	18,766,567
Operating lease liabilities, excluding current portion	1,887,693	2,236,361
Derivative liabilities	60,094	432,142
Long-term debt	294,200,000	233,015,911
Other liabilities	197,917	322,917
Total liabilities	309,322,464	263,336,623
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units and zero units issued and outstanding as of December 31, 2023 and 2022, respectively)	314,423,572
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		236,900,000
Kimbell Royalty Partners, LP unitholders' equity:
Common units (73,851,458 units and 64,231,833 units issued and outstanding as of December 31, 2023 and 2022, respectively)	670,530,748	601,841,776
Class B units (20,847,295 and 15,484,400 units issued and outstanding as of December 31, 2023 and 2022, respectively)	1,042,365	774,220
Total Kimbell Royalty Partners, LP unitholders' equity	671,573,113	602,615,996
Non-controlling interest (deficit) in OpCo	42,470,067	(26,106,320)
Total unitholders' equity	714,043,180	576,509,676
Total liabilities, mezzanine equity and unitholders' equity	$ 1,337,789,216	1,076,746,299
Consolidated variable interest entities
Current assets
Investment held in trust		240,621,146
Prepaid expenses		35,201
Oil and natural gas properties
Cash		390,850
Current liabilities
Other current liabilities		512,725
Deferred underwriting commissions		$ 8,050,000

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
CONSOLIDATED BALANCE SHEETS
Oil and natural gas properties excluded from depletion	$ 222,712,844	$ 207,695,343
Temporary equity, issued (in units)	325,000	0
Temporary equity, outstanding (in units)	325,000	0
Common units, issued (in units)	73,851,458	64,231,833
Common units, outstanding (in units)	73,851,458	64,231,833
Class B units, issued (in units)	20,847,295	15,484,400
Class B units, outstanding (in units)	20,847,295	15,484,400

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues	$ 267,584,785	$ 281,964,126	$ 175,088,021
Lease bonus and other income	5,594,855	3,073,609	3,319,104
Gain (loss) on commodity derivative instruments, net	20,888,972	(36,978,550)	(42,791,909)
Total revenues	294,068,612	248,059,185	135,615,216
Costs and expenses
Production and ad valorem taxes	20,326,477	16,238,814	10,480,481
Depreciation and depletion expense	96,477,003	50,086,414	36,797,881
Impairment of oil and natural gas properties	18,220,173	0	0
Marketing and other deductions	12,564,619	13,383,074	12,048,643
General and administrative expense	35,677,851	29,128,659	26,977,519
General and administrative expense consolidated variable interest entities	927,699	2,304,445
Total costs and expenses	184,193,822	111,141,406	86,304,524
Operating income	109,874,790	136,917,779	49,310,692
Other income (expense)
Equity income in affiliate		2,668,844	1,119,819
Interest expense	(25,950,600)	(13,818,310)	(9,182,103)
Loss on extinguishment of debt	(480,244)
Other (expense) income	(180,765)	4,043,530	1,263,566
Net income before income taxes	86,771,872	133,532,988	42,511,974
Income tax expense	3,766,302	2,738,702	74,100
Net income	83,005,570	130,794,286	42,437,874
Distribution and accretion on Series A preferred units	(6,310,215)		(11,249,969)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests	(16,464,890)	(18,822,552)	(8,496,104)
Distribution on Class B units	(88,786)	(42,243)	(76,780)
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 60,141,679	$ 111,929,491	$ 22,615,021
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Net income per unit attributable to common units (basic) (in dollar per share)	$ 0.93	$ 1.75	$ 0.56
Net income per unit attributable to common units (diluted) (in dollar per share)	$ 0.91	$ 1.72	$ 0.51
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)	66,595,273	54,112,595	40,400,907
Weighted average number of common units outstanding Diluted (in units)	93,057,731	65,837,017	60,957,824
Consolidated variable interest entities
Other income (expense)
Interest earned on marketable securities in trust account	$ 3,508,691	$ 3,721,145
Oil, natural gas and NGL revenues
Revenues	267,584,785	281,964,126	$ 175,088,021
Lease bonus and other income
Revenues	$ 5,594,855	$ 3,073,609	$ 3,319,104

XML

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($)	Common Units	Class B Common Units	Non-controlling Interest in Opco	Non-controlling Interest in TGR	Total
Unitholders' capital, beginning balance at Dec. 31, 2020	$ 257,593,307	$ 1,038,989	$ 77,002,442		$ 335,634,738
Unitholders' capital, beginning balance (in units) at Dec. 31, 2020	38,918,689	20,779,781
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 57,522,440				57,522,440
Common units issued for equity offering (in units)	4,312,500
Conversion of Class B units to common units	$ 40,482,756	$ (158,410)	(40,482,756)		(158,410)
Conversion of Class B units to common units (in units)	3,168,202	(3,168,202)
Redemption of Series A preferred units	$ (10,753,930)		(4,229,854)		(14,983,784)
Restricted units repurchased for tax withholding	$ (2,064,693)				(2,064,693)
Restricted units repurchased for tax withholding (in units)	(173,185)
Unit-based compensation	$ 10,632,725				10,632,725
Unit-based compensation (in units)	936,567
Distributions to unitholders	$ (47,309,785)		(21,534,575)		(68,844,360)
Distribution and accretion on Series A preferred units	(7,956,092)		(3,293,877)		(11,249,969)
Distribution on Class B units	(76,780)				(76,780)
Net income	30,647,893		11,789,981		42,437,874
Unitholders' capital, ending balance at Dec. 31, 2021	$ 328,717,841	$ 880,579	19,251,361		348,849,781
Unitholders' capital, ending balance (in units) at Dec. 31, 2021	47,162,773	17,611,579
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 116,119,417				116,119,417
Common units issued for equity offering (in units)	6,900,000
Conversion of Class B units to common units	$ 162,147,055	$ (470,000)	(162,147,055)		(470,000)
Conversion of Class B units to common units (in units)	9,400,000	(9,400,000)
Restricted units repurchased for tax withholding	$ (3,344,828)				(3,344,828)
Restricted units repurchased for tax withholding (in units)	(193,604)
Forfeiture of restricted units	$ (19,813)				(19,813)
Forfeiture of restricted units (in units)	(1,171)
Units issued for acquisition		$ 363,641	120,292,459		120,656,100
Units issued for acquisition (in units)		7,272,821
Unit-based compensation	$ 11,107,639				11,107,639
Unit-based compensation (in units)	963,835
Distributions to unitholders	$ (107,402,294)		(19,323,523)		(126,725,817)
Distribution on Class B units	(42,243)				(42,243)
Proceeds from issuance of TGR public warrants				$ 11,500,000	11,500,000
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation	(17,412,732)		(3,002,114)	$ (11,500,000)	(31,914,846)
Net income	111,971,734		18,822,552		130,794,286
Unitholders' capital, ending balance at Dec. 31, 2022					602,615,996
Unitholders' capital, ending balance at Dec. 31, 2022	$ 601,841,776	$ 774,220	(26,106,320)		$ 576,509,676
Unitholders' capital, ending balance (in units) at Dec. 31, 2022	64,231,833	15,484,400			64,231,833
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 110,711,383				$ 110,711,383
Common units issued for equity offering (in units)	8,337,500
Conversion of Class B units to common units	$ 101,105	$ (316)	(101,105)		(316)
Conversion of Class B units to common units (in units)	6,323	(6,323)
Restricted units repurchased for tax withholding	$ (4,851,962)				(4,851,962)
Restricted units repurchased for tax withholding (in units)	(279,662)
Units issued for acquisition	$ 8,654,900	$ 268,461	83,383,956		92,307,317
Units issued for acquisition (in units)	557,302	5,369,218
Unit-based compensation	$ 13,111,522				13,111,522
Unit-based compensation (in units)	998,162
Distributions to unitholders	$ (120,372,624)		(31,551,122)		(151,923,746)
Distribution and accretion on Series A preferred units	(4,921,063)		(1,389,152)		(6,310,215)
Distribution on Class B units	(88,786)				(88,786)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation	1,192,969		379,768		1,572,737
Net income	65,151,528		17,854,042		83,005,570
Unitholders' capital, ending balance at Dec. 31, 2023					671,573,113
Unitholders' capital, ending balance at Dec. 31, 2023	$ 670,530,748	$ 1,042,365	$ 42,470,067		$ 714,043,180
Unitholders' capital, ending balance (in units) at Dec. 31, 2023	73,851,458	20,847,295			73,851,458

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 83,005,570	$ 130,794,286	$ 42,437,874
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense	96,477,003	50,086,414	36,797,881
Impairment of oil and natural gas properties	18,220,173	0	0
Amortization of right-of-use assets	336,080	319,674	298,093
Amortization of loan origination costs	1,943,025	1,872,700	1,556,769
Loss on extinguishment of debt	480,244
Equity income in affiliate		(2,668,844)	(1,119,819)
Cash distribution from affiliate		3,770,651	1,015,559
Forfeiture of restricted units		(19,813)
Unit-based compensation	13,111,522	11,107,639	10,632,725
(Gain) loss on derivative instruments, net of settlements	(26,371,058)	(14,300,570)	20,343,783
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	(12,026,760)	(11,846,567)	(17,594,389)
Accounts receivable and other current assets	1,863,376	(511,319)	(2,077,637)
Accounts payable	509,400	399,318	(77,716)
Other current liabilities	1,263,804	1,590,016	(463,828)
Operating lease liabilities	(348,668)	(324,913)	(306,814)
Net cash provided by operating activities	174,267,667	166,636,493	91,442,481
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment	(141,297)	(163,140)	(772,688)
Purchase of oil and natural gas properties	(490,665,514)	(141,297,776)	(55,300,252)
Proceeds from trust of variable interest entity	930,850
Cash distribution from affiliate		3,637,015	500,389
Net cash used in investing activities	(246,676,974)	(374,723,901)	(55,572,551)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of Series A preferred units, net of issuance costs	313,950,000
Proceeds from equity offering, net of issuance costs	110,711,383	116,119,417	57,522,440
Contributions from Class B unitholders	268,461	363,641
Redemption of Class B contributions on converted units	(316)	(470,000)	(158,410)
Redemption on Series A preferred units			(67,081,680)
Distribution to common unitholders	(120,372,624)	(107,402,294)	(47,309,785)
Distribution to OpCo unitholders	(31,551,122)	(19,323,523)	(21,534,575)
Distribution on Series A preferred units	(961,644)		(2,800,012)
Distribution on Class B units	(88,786)	(42,243)	(76,780)
Borrowings on long-term debt	201,084,089	199,200,000	136,565,769
Repayments on long-term debt	(139,900,000)	(183,300,000)	(91,000,000)
Payment of loan origination costs	(6,744,636)	(662,320)	(684,767)
Restricted units repurchased for tax withholding	(4,851,962)	(3,344,828)	(2,064,693)
Net cash provided by (used in) financing activities	78,375,409	226,061,562	(38,622,493)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,966,102	17,974,154	(2,752,563)
CASH AND CASH EQUIVALENTS, beginning of period	25,026,568	7,052,414	9,804,977
CASH AND CASH EQUIVALENTS, end of period	30,992,670	25,026,568	7,052,414
Supplemental cash flow information:
Cash paid for interest	23,727,572	11,207,530	7,538,814
Cash paid for taxes	2,281,000	3,082,245
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	92,038,856	120,292,459
Noncash effect of Series A preferred unit redemption			14,893,784
Noncash deemed distribution to Series A preferred units	473,571		9,431,794
Distribution on Series A preferred units in accounts payable	4,875,000
Recognition of tenant improvement asset	125,000	125,001	447,917
Right-of-use assets obtained in exchange for operating lease liabilities			$ 19,636
Consolidated variable interest entities
Changes in operating assets and liabilities:
Interest earned on marketable securities in trust account	(3,508,691)	(3,721,145)
Other assets and liabilities	(687,353)	88,966
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for transaction costs	31,553
Cash received from investments held in trust	243,167,434
Investment in marketable securities		(236,900,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of underwriting commissions with equity offering of Kimbell Tiger Operating Company, net of adjustments		(2,661,288)
Proceeds from initial public offering of Kimbell Tiger Operating Company		227,585,000
Redemption of Kimbell Tiger Acquisition Corporation equity units	(243,167,434)
CASH AND CASH EQUIVALENTS, beginning of period	390,850
CASH AND CASH EQUIVALENTS, end of period		390,850
Non-cash investing and financing activities:
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units	$ (8,050,000)
Deferred underwriting commissions		$ 8,050,000

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$ 30,992,670	$ 25,026,568	$ 7,052,414
Consolidated variable interest entities
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents		390,850
Non-Consolidated Variable Interest Entity Primary Beneficiary
Reconciliation of Cash and Cash Equivalents and Cash Held at Consolidated Variable Interest Entities to the Consolidated Statements of Cash Flows
Cash and cash equivalents	$ 30,992,670	$ 24,635,718	$ 7,052,414

XML

ORGANIZATION AND BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2023

ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION AND BASIS OF PRESENTATION

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “the Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to “the Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is 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. The Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

Basis of Presentation

The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Use of Estimates

Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

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 and is still active. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2023

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of equity-based compensation.

The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Oil, Natural Gas and NGL Receivables

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2023 and 2022, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Derivative Financial Instruments

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though

they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statements of operations within gain (loss) on commodity derivative instruments.

Interest Rate Swaps

The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps were recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Loan Origination Costs

Certain direct costs associated with the Partnership’s secured revolving credit facility are presented in the consolidated balance sheets as loan origination costs. These costs are amortized over the term of the secured revolving credit facility and included as a component of interest expense in the consolidated statements of operations.

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas 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 capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2023, 2022 or 2021.

The Partnership assesses all unevaluated properties on periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is

able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2023, 2022 or 2021.

Other Current Liabilities

Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities.

Earnings Per Unit

Earnings per unit applicable to limited partners is computed utilizing the “if-converted” method, which is calculated by dividing limited partners’ interested in net income by the weighted average number of outstanding common units. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”).

Income Taxes

As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. The non-controlling interest, which represents OpCo common unitholders’, as defined below, are not subject to federal income taxes.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2023, 2022 and 2021.

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2023, 2022 and 2021, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

During the years ended December 31, 2023, 2022 and 2021, the Partnership’s top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of oil, natural gas and NGL sales revenue.

Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the  Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information.

Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents OpCo common unitholders’, as defined below, ownership in the net assets of the Operating Company. When the OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 10—Unitholders’ Equity and Partnership Distributions for further discussion.

Revenue from Contracts with Customers

The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods:

	Year Ended December 31,
	2023		2022			2021
Oil revenue	$	183,150,517	$	130,811,485	$	87,151,724
Natural gas revenue		59,524,413		122,632,983		66,977,352
NGL revenue		24,909,855		28,519,658		20,958,945
Total Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021

Transaction Price Allocated to Remaining Performance Obligations

The Partnership’s right to revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts.

Contract Balances

Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP.

Prior-Period Performance Obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the revenue to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2023, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent

actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value Measurements

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.

Consolidation

The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.

In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the

trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represented the shares of Class A common stock of TGR par value $0.0001 per share (the “Class A common stock”) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

Recently Issued Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

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ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY

12 Months Ended

Dec. 31, 2023

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY

ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY

NOTE 3—ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

2023 Activity

On September 13, 2023, the Partnership completed 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”) in a cash transaction valued at approximately $455.0 million. The Partnership funded the cash transaction with borrowings under its secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 9—Preferred Units). The adjusted purchase price of the LongPoint Acquisition includes the total cash consideration of $455.0 million, transactional costs of $7.4 million and less $16.6 million of post-effective net oil, natural gas and NGL revenues earned prior to the closing date. The LongPoint Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $198.2 million to proved properties and $247.6 million to unevaluated properties.

On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo

Common Units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and (b) 557,302 common units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. The MB Minerals Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $60.8 million to proved properties and $74.9 million to unevaluated properties.

2022 Activity

On December 15, 2022, the Partnership completed the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”). The aggregate consideration for the Hatch Acquisition consisted of (i) approximately $150.4 million in cash and (ii) the issuance of 7,272,821 OpCo common units and an equal number of Class B units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Hatch Acquisition are located in the Permian Basin and the Partnership estimates that the assets consisted of approximately 889 net royalty acres on approximately 230,000 gross acres. The Hatch acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $56.4 million to proved properties and $204.7 million to unevaluated properties.

2021 Activity

On March 10, 2021, the Partnership completed the acquisition of certain mineral and royalty assets held by Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Oil Nut Bay Royalties, LP for a total purchase price of $0.5 million. The assets acquired were managed by Nail Bay Royalties and Duncan Management, LLC (“Duncan Management”). See Note 14—Related Party Transactions, for further discussion of the Partnership’s relation to each entity.

On December 7, 2021, the Partnership completed the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) for an aggregate purchase price of approximately $54.6 million. The Partnership funded the payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the Cornerstone Acquisition consisted of approximately 26,000 gross producing wells across the Permian, Mid-Continent, Haynesville and other leading U.S. basins.

Both 2021 acquisitions were accounted for as asset acquisitions and the allocation of the purchase price was $55.3 million to proved properties.

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture was 49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. On November 1, 2022, the Joint Venture was dissolved.

Special Purpose Acquisition Company

On January 29, 2021, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, Kimbell Tiger Acquisition Corporation (“TGR”), filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”).

TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which was a subsidiary of the Partnership, and was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination. TGR Sponsor and TGR were consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021.

On February 8, 2022, TGR consummated its $230.0 million initial public offering (the “TGR IPO”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 to complete a business combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock included as part of the units issued in its initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR (along with TGR Sponsor) on June 30, 2023 in accordance with the terms of its organizational documents. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying consolidated balance sheet of as of December 31, 2023 and treated as accretion of redeemable non-controlling interest in TGR in the accompanying consolidated statements of changes in unitholders’ equity for the year ended December 31, 2023.

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DERIVATIVES

12 Months Ended

Dec. 31, 2023

DERIVATIVES

DERIVATIVES

NOTE 4—DERIVATIVES

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty.

At December 31, 2023, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last scheduled trading day of the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying consolidated statements of operations.

Interest Rate Swaps

On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. On May 17, 2022, the Partnership entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, the Partnership entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The terminations resulted in a $6.4 million gain for the year ended December 31, 2022, which is included in other income (expense) in the accompanying consolidated statements of operations. The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps were recognized as gains or losses in the current period and were presented on a net basis within other income in the accompanying consolidated statements of operations. As of December 31, 2021, the interest rate swap had a total notional amount of $150.0 million and a fair value of $1.8 million.

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. Changes in the fair value consisted of the following:

	Year Ended December 31,
	2023		2022		2021
Beginning fair value of derivative instruments	$	(12,324,076)	$	(26,624,646)	$	(6,280,863)
Gain (loss) on commodity derivative instruments, net		20,888,972		(32,240,915)		(41,240,942)
Net cash paid on settlements of derivative instruments		5,482,086		46,541,485		20,897,159
Ending fair value of derivative instruments	$	14,046,982	$	(12,324,076)	$	(26,624,646)

The following table presents the fair value of the Partnership’s derivative contracts for the periods indicated:

		December 31,		December 31,
Classification	Balance Sheet Location	2023		2022
Assets:
Current assets	Derivative assets	$	11,427,735	$	—
Long-term assets	Derivative assets		2,888,051		754,786
Liabilities:
Current liabilities	Derivative liabilities		(208,710)		(12,646,720)
Long-term liabilities	Derivative liabilities		(60,094)		(432,142)
		$	14,046,982	$	(12,324,076)

At December 31, 2023, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
January 2024 - December 2024	568,926	$	79.04	$	69.30	$	85.34
January 2025 - December 2025	563,526	$	70.36	$	64.35	$	77.01

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
January 2024 - December 2024	5,285,182	$	3.97	$	3.06	$	4.48
January 2025 - December 2025	5,153,291	$	3.81	$	3.50	$	4.37

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2023

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 5—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2023 and 2022 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

● Level 1—Unadjusted quoted market prices for identical assets or liabilities in active markets.

● Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability.

● Level 3— Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the years ended December 31, 2023 and 2022.

The estimated fair values of investments held in the trust account are determined using quoted prices in an active market and therefore are classified in Level 1 of the fair value hierarchy. The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
December 31, 2023
Assets
Commodity derivative contracts	$	—	$	14,315,786	$	—	$	—	$	14,315,786
Liabilities
Commodity derivative contracts	$	—	$	(268,804)	$	—	$	—	$	(268,804)
December 31, 2022
Assets
Commodity derivative contracts	$	—	$	754,786	$	—	$	—	$	754,786
Assets of consolidated variable interest entities:
Investments held in trust	$	240,621,146	$	—	$	—	$	—	$	240,621,146
Liabilities
Commodity derivative contracts	$	—	$	(13,078,862)	$	—	$	—	$	(13,078,862)

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OIL AND NATURAL GAS PROPERTIES

12 Months Ended

Dec. 31, 2023

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	December 31,		December 31,
	2023		2022
Oil and natural gas properties
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Less: accumulated depreciation, depletion and impairment		(827,033,944)		(712,716,951)
Total oil and natural gas properties	$	1,221,656,144	$	753,268,767

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 Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved developed reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $18.2 million during the year ended December 31, 2023. The impairment is primarily attributed to the decline in the 12-month average price of oil and natural gas. As of December 31, 2023, the 12-month average prices of oil and natural gas were $78.22 per Bbl of oil and $2.64 per Mcf of natural gas. These prices represent a 16.5% and 58.5% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2022, which were $93.67 per Bbl of oil and $6.36 per Mcf of natural gas. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

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LEASES

12 Months Ended

Dec. 31, 2023

LEASES

LEASES

NOTE 7—LEASES

Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in June 2029. The Partnership’s right-of-use (“ROU”) operating lease assets represent its right to use an underlying asset for the lease term, and its operating lease liabilities represent its obligation to make lease payments. ROU operating lease assets and operating lease liabilities are included in the accompanying consolidated balance sheets. Short-term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2023 is 5.43 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating lease was 6.75% for the year ended December 31, 2023.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations. The total operating lease expense recorded for the years ended December 31, 2023, 2022 and 2021 was $0.6 million, $0.5 million and $0.4 million, respectively.

Currently, the most substantial contractual arrangements that the Partnership has classified as operating leases are the main office spaces used for operations.

Maturities of lease liabilities as of December 31, 2023 are as follows:

	Total		2024		2025		2026		2027		2028		Thereafter
Operating leases	$	2,712,673	$	488,725	$	497,033	$	507,648	$	511,917	$	496,785	$	210,565
Less: Imputed Interest		(476,273)
Total	$	2,236,400

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2023

LONG-TERM DEBT.

LONG-TERM DEBT

NOTE 8—LONG-TERM DEBT

On June 13, 2023, the Partnership entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022). The A&R Credit Agreement provides for, among other things, (i) a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027. In connection with the A&R Credit Agreement, the Partnership recorded a loss on extinguishment of debt of $0.5 million as a result of writing off all unamortized loan origination costs associated with the lenders to the Partnership’s existing credit agreement that did not participate in the A&R Credit Agreement.

On July 24, 2023, the Partnership entered into Amendment No. 1 (the “First Amendment”) to the A&R Credit Agreement. The amendment amended the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit the Partnership to issue certain preferred equity interests.

On December 8, 2023, in connection with the November 1, 2023 redetermination, the Partnership entered into Amendment No. 2 (the “Second Amendment”) to the A&R Credit Agreement. The amendment amends the A&R Credit Agreement to, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million.

The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (a) the Secured Overnight Financing Rate (as defined in the A&R Credit Agreement) plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The secured revolving credit facility is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least 75% of the PV-9 of the proved reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders, with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. The next scheduled redetermination will be on or around May 1, 2024.

Customary borrowing base reductions and mandatory prepayments are required under the A&R Credit Agreement in connection with certain sales of certain types of borrowing base properties, sales of equity interests in guarantor subsidiaries owning such properties, certain debt issuances or certain types of swap terminations. In addition, Cash Balance (as defined in the First Amendment) above $50.0 million is required to be applied weekly to prepay loans (without a commitment reduction) if not otherwise reduced to zero in a manner permitted by the A&R Credit Agreement.

The Partnership is required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the secured revolving credit facility. The Partnership is also required to pay customary letter of credit and fronting fees.

The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) 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.

The A&R Credit Agreement also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements and borrowing base certificates, conduct of business, maintenance of property, maintenance of insurance, entry into certain derivatives contracts, restrictions on the incurrence of liens, indebtedness, asset dispositions, restricted payments, and other customary covenants. These covenants are subject to a number of limitations and exceptions.

Additionally, the A&R Credit Agreement contains customary events of default and remedies for credit facilities of this nature. If the Partnership does not comply with the financial and other covenants in the A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the A&R Credit Agreement and any outstanding unfunded commitments may be terminated.

During the year ended December 31, 2023, the Partnership borrowed an additional $201.1 million under the secured revolving credit facility and repaid approximately $139.9 million of the outstanding borrowings. As of December 31, 2023, the Partnership’s outstanding balance was $294.2 million and there were no outstanding letters of credit under the secured revolving credit facility. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2023.

As of December 31, 2023, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.25% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.25%. For the year ended December 31, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.62%.

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PREFERRED UNITS

12 Months Ended

Dec. 31, 2023

PREFERRED UNITS

PREFERRED UNITS

NOTE 9—PREFERRED UNITS

On August 2, 2023, the Partnership entered into a Series A preferred unit purchase agreement with certain funds managed by affiliates of Apollo (NYSE: APO) (collectively, the “Series A Purchasers”) to issue and sell up to 400,000 Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”). On September 13, 2023, in connection with the closing of the LongPoint Acquisition, the Partnership completed the private placement of 325,000 Series A preferred units to the Series A Purchasers for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $325.0 million (the “Preferred Unit Transaction”). The Partnership used the net proceeds from the Preferred Unit Transaction to purchase 325,000 preferred units of the Operating Company (“OpCo preferred units”). The Operating Company in turn used the net proceeds to fund a portion of the LongPoint Acquisition. The Series A preferred units rank senior to the Partnership’s common units with respect to distribution rights and rights upon liquidation.

Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. The Partnership has 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 the Partnership makes such an election in consecutive quarters or if the Partnership fails to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its 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 the Partnership of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. The Partnership cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

Beginning with the earlier of (i) the second anniversary of the original issuance date and (ii) immediately prior to a liquidation of the Partnership, the Series A Purchasers may, at any time (but not more often than once per quarter), elect to convert all or any portion of their Series A preferred units into a number of common units determined by multiplying

the number of Series A preferred units to be converted by the then-applicable conversion rate, provided that (a) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ remaining Series A preferred units and (b) the closing price of the common units is at least 130% of the conversion price of $15.07, subject to certain anti-dilution adjustments (the “Conversion Price”) for 20 trading days during the 30-trading day period immediately preceding the conversion notice.

At any time on or after the second anniversary of the original issuance date, the Partnership will have the option to convert all or any portion of the Series A preferred units into a number of common units determined by the then-applicable conversion rate, provided that (i) any conversion is for an amount of common units with an aggregate value of at least $10.0 million or such lesser amount that covers all of the holders’ Series A preferred units, (ii) the common units are listed for, or admitted to, trading on a national securities exchange, (iii) the closing price of the common units is at least 160% of the Conversion Price for 20 trading days during the 30-trading day period immediately preceding the conversion notice and (iv) the Partnership has an effective registration statement on file with the SEC covering resales of the underlying common units to be received by the holders of Series A preferred units upon such conversion.

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

For purposes of the Series A preferred units, “Minimum IRR” means as of any measurement date: (a) prior to the fifth anniversary of the original issuance date, a 12.0% internal rate of return with respect to the Series A preferred units; (b) on or after the fifth anniversary of the original issuance date and prior to the sixth anniversary of the original issuance date, a 13.0% internal rate of return with respect to the Series A preferred units; and (c) on or after the sixth anniversary of the original issuance date, a 14.0% internal rate of return with respect to the Series A preferred units.

In connection with the issuance of the Series A preferred units, the Partnership granted holders of the Series A preferred units board observer rights beginning on the fifth anniversary of the original issuance date, board appointment rights beginning on the sixth anniversary of the original issuance date, and in the case of events of default with respect to the Series A preferred units, the right to appoint two members of the board beginning on the seventh anniversary of the original issuance date.

The terms of the Series A preferred units contain covenants preventing the Partnership 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.

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UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

12 Months Ended

Dec. 31, 2023

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of December 31, 2023, the Partnership had a total of 73,851,458 common units issued and outstanding and 20,847,295 Class B units outstanding.

On August 7, 2023, the Partnership completed an underwritten public offering of 8,337,500 common units for net proceeds of approximately $110.7 million (the “2023 Equity Offering”). The Partnership used the net proceeds from the 2023 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $90.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. The Operating Company used the remainder of the net proceeds of the 2023 Equity Offering for general corporate purposes.

In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $116.1 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

In November 2021, the Partnership completed an underwritten public offering of 4,312,500 common units for net proceeds of approximately $57.7 million (the “2021 Equity Offering”). The Partnership used the net proceeds from the 2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $56.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility.

The following table summarizes the changes in the number of the Partnership’s common units:

	Common Units
Balance at December 31, 2022	64,231,833
Common units issued under the A&R LTIP (1)	998,162
Restricted units repurchased for tax withholding	(279,662)
Common unit issued for acquisition	557,302
Common units issued for equity offering	8,337,500
Conversion of Class B units	6,323
Balance at December 31, 2023	73,851,458

(1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “A&R LTIP”) on February 21, 2023.

The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:

	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2023	$	0.35	May 3, 2023	May 15, 2023	May 22, 2023
Q2 2023	$	0.39	August 2, 2023	August 14, 2023	August 21, 2023
Q3 2023	$	0.51	November 2, 2023	November 13, 2023	November 20, 2023
Q4 2023	$	0.43	February 21, 2024	March 13, 2024	March 20, 2024
Q1 2022	$	0.47	April 22, 2022	May 2, 2022	May 9, 2022
Q2 2022	$	0.55	August 3, 2022	August 15, 2022	August 22, 2022
Q3 2022	$	0.49	November 3, 2022	November 14, 2022	November 21, 2022
Q4 2022	$	0.48	February 23, 2023	March 9, 2023	March 16, 2023
Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021
Q3 2021	$	0.37	October 22, 2021	November 1, 2021	November 8, 2021
Q4 2021	$	0.37	January 21, 2022	January 31, 2022	February 7, 2022

The following table summarizes the changes in the number of the Partnership’s Class B units:

	Class B Units
Balance at December 31, 2022	15,484,400
Class B units issued for acquisition	5,369,218
Conversion of Class B units	(6,323)
Balance at December 31, 2023	20,847,295

For each Class B unit issued, five cents have been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units are 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 the common units and OpCo common units.

Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to

receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP.  The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

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EARNINGS PER COMMON UNIT

12 Months Ended

Dec. 31, 2023

EARNINGS PER COMMON UNIT

EARNINGS PER COMMON UNIT

NOTE 11—EARNINGS PER COMMON UNIT

Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s A&R LTIP are nonparticipating securities.

The following table summarizes the calculation of weighted average common units outstanding used in the computation of diluted earnings (loss) per common unit:

	Year Ended December 31,
	2023		2022		2021
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		1,572,737		(17,412,732)		—
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		61,714,416		94,516,759		22,615,021
Distribution and accretion on Series A preferred units		6,310,215		—
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		16,553,676		18,864,795		8,496,104
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	84,578,307	$	113,381,554	$	31,111,125
Weighted average number of common units outstanding:
Basic		66,595,273		54,112,595		40,400,907
Effect of dilutive securities:
Series A preferred units		6,499,350		—		—
Class B units		18,851,387		10,819,266		18,839,607
Restricted units		1,111,721		905,156		1,717,310
Diluted		93,057,731		65,837,017		60,957,824
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51

The calculation of diluted net income per share for the year ended December 31, 2023 includes the conversion of Series A preferred units to common units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net income per share for the years ended December 31, 2022 and 2021 includes the conversion of all Class B units to common units calculated using the “if-converted” method and unvested restricted units calculated using the treasury stock method.

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UNIT-BASED COMPENSATION

12 Months Ended

Dec. 31, 2023

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION

NOTE 12—UNIT-BASED COMPENSATION

On May 18, 2022, the Partnership held a special meeting of unitholders of the Partnership (the “Special Meeting”), at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-

Term Incentive Plan (the “A&R LTIP”), which increased the number of common units eligible for issuance under the A&R LTIP by 3,700,000 common units for a total of 8,241,600 common units. The Partnership’s A&R LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s A&R LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants is treated in the same manner as that of the employees and directors.

Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the A&R LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. The following table presents a summary of the Partnership’s unvested restricted units.

		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2022	1,897,192	$	13.553	1.517 years
Awarded	998,162		15.020	—
Vested	(943,924)		12.602	—
Unvested at December 31, 2023	1,951,430	$	14.763	1.525 years

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INCOME TAXES

12 Months Ended

Dec. 31, 2023

INCOME TAXES

INCOME TAXES

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate. The Partnership incurred $3.8 million and $2.7 million of income taxes for the years ended December 31, 2023 and 2022, respectively, and a de minimis amount of income taxes during the year ended December 31, 2021.

The Partnership has filed all tax returns to date that are currently due.

The Partnership’s effective income tax rate was 4.34% for the year ended December 31, 2023. The Partnership earned income before taxes, as calculated under GAAP,  for the current year and is recording a current income tax expense of $3.8 million primarily related to income that was not sheltered due to depletion and other non-cash deductions.

	Year Ended December 31,
	2023		2022		2021
Current
Federal	$	2,469,584	$	2,412,702	$	69,067
State		1,296,718		326,000		5,033
Total Current		3,766,302		2,738,702		74,100
Deferred
Federal		—		—		—
State		—		—		—
Total Deferred		—		—		—
Provision for income taxes	$	3,766,302	$	2,738,702	$	74,100

The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pre-tax income principally due the effect of the following items:

	Year Ended December 31,
	2023			2022			2021
Net income before taxes	$	86,771,872		$	133,532,988		$	42,511,974
Statutory rate		21	%		21	%		21	%
Income tax provision computed at statutory rate		18,222,093			28,041,927			8,927,515
Reconciling items:
State income taxes		1,393,149			326,000			5,033
Non-controlling interest		(3,518,924)			(3,988,366)			(1,788,347)
Income at OpCo		(14,703,170)			(24,053,561)			(7,139,168)
Change in valuation allowance - federal		2,860,951			2,202,314			(363,132)
Change in valuation allowance - state		(96,431)			(1,307,605)			(40,626)
Other, net		(391,366)			1,517,993			472,825
Provision for income taxes	$	3,766,302		$	2,738,702		$	74,100

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below.

	Year Ended December 31,
	2023		2022		2021
Deferred tax asset
Outside basis in OpCo	$	22,624,765	$	18,494,572	$	6,641,452
Federal tax loss carryforwards		—		2,645,475		12,296,282
State tax loss carryforwards		385,926		482,356		1,789,961
Business interest deduction limitation		1,376,234		—		—
Deferred tax asset		24,386,925		21,622,403		20,727,695
Valuation allowance		(24,386,925)		(21,622,403)		(20,727,695)
Net deferred tax asset	$	—	$	—	$	—

The tax years ended December 31, 2020 through 2023 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $24.4 million on the deferred tax assets.

As of December 31, 2023, the Partnership has not recorded a reserve for any uncertain tax positions.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2023

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 14—RELATED PARTY TRANSACTIONS

The Partnership currently has a management services agreement with Kimbell Operating, which has separate services agreements with each of BJF Royalties, LLC (“BJF Royalties”), K3 Royalties, LLC (“K3 Royalties”), pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders.

During the year ended December 31, 2023, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2023, the Partnership made payments to K3 Royalties in the amount of $120,000.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of

approximately $26,500 for the year ended December 31, 2023, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $602,600 for the year ended December 31, 2023.

The Partnership received $180,626 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the year ended December 31, 2023.

Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per quarter for office space utilities, secretarial support and administrative services provided to members of the management team. During the year ended December 31, 2023, TGR incurred $50,000 as part of this service agreement. Such fees were eliminated in consolidation. Upon TGR’s liquidation, TGR ceased paying these monthly fees.

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ADMINISTRATIVE SERVICES

12 Months Ended

Dec. 31, 2023

ADMINISTRATIVE SERVICES

ADMINISTRATIVE SERVICES

NOTE 15—ADMINISTRATIVE SERVICES

On September 13, 2023, in connection with the LongPoint Acquisition and pursuant to the terms of the securities purchase agreement, a transition services agreement (the “Transition Services Agreement”) by and between the Operating Company and FourPoint Energy, LLC (“FourPoint”), the former manager of the acquired assets, became effective. Pursuant to the Transition Services Agreement, FourPoint provided certain administrative services and accounting assistance on a transitional basis for a monthly service fee of approximately $250,000 for the four-month period ending January 13, 2024, at which the Transition Services Agreement was terminated by the Partnership. During the year ended December 31, 2023, the Partnership paid $0.9 million in Transition Services Agreement costs.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2023

COMMITMENTS AND CONTINGENCIES.

COMMITMENTS AND CONTINGENCIES

NOTE 16—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of December 31, 2023.

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2023

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to December 31, 2023 in the preparation of its consolidated financial statements.

Distributions

On February 21, 2024, the Board of Directors declared a quarterly cash distribution of $0.43 per common unit and $0.453897 per OpCo common unit for the quarter ended December 31, 2023. The Partnership intends to pay this distribution on March 20, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on March 13, 2024.

As to the Partnership, $0.023897 of the OpCo common unit distribution corresponds to a tax payment made by the Partnership in the fourth quarter of 2023. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.9 million for the quarter ended December 31, 2023. We intend to pay the distribution subsequent to March 13, 2024 and prior to the distribution on the common units and OpCo common units.

Executive Bonus and LTIP Issuance

On February 19, 2024, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of approximately $2.5 million and the issuance of 1,087,502 restricted units to its employees and directors.

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2023

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

NOTE 18—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

	December 31,		December 31,
	2023		2022
Oil, natural gas and NGL interests
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Total oil, natural gas and NGL interests		2,048,690,088		1,465,985,718
Accumulated depreciation, depletion, accretion and impairment		(827,033,944)		(712,716,951)
Net oil, natural gas and NGL interests capitalized	$	1,221,656,144	$	753,268,767

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

	Year Ended December 31,
	2023		2022		2021
Acquisition costs
Proved properties	$	260,145,370	$	56,848,235	$	55,300,252
Unevaluated properties		322,559,000		204,742,000		—
Total		582,704,370		261,590,235		55,300,252
Development costs
Proved properties		—		—		—
Total		—		—		—
Total costs incurred on oil, natural gas and NGL activities	$	582,704,370	$	261,590,235	$	55,300,252

Results of Operations from Oil, Natural Gas and NGL Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

	Year Ended December 31,
	2023		2022		2021
Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021
Lease bonus and other income		5,594,855		3,073,609		3,319,104
Production and ad valorem taxes		(20,326,477)		(16,238,814)		(10,480,481)
Depreciation and depletion expense		(96,477,003)		(50,086,414)		(36,797,881)
Impairment of oil and natural gas properties		(18,220,173)		—		—
Marketing and other deductions		(12,564,619)		(13,383,074)		(12,048,643)
Results of operations from oil, natural gas and NGLs	$	125,591,368	$	205,329,433	$	119,080,120

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves. The estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2023, 2022 and 2021. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and 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. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

	Crude Oil and		Natural Gas
	Condensate	Natural Gas	Liquids	Total
	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Net proved reserves at January 1, 2021	12,294	144,233	6,085	42,418
Revisions of previous estimates (1)	251	24,079	780	5,044
Purchase of minerals in place (2)	1,310	8,537	519	3,252
Production	(1,344)	(19,085)	(715)	(5,240)
Net proved reserves at December 31, 2021	12,511	157,764	6,669	45,474
Revisions of previous estimates (1)	(58)	17,119	759	3,554
Purchase of minerals in place (3)	1,328	5,726	707	2,989
Production	(1,426)	(20,311)	(747)	(5,558)
Net proved reserves at December 31, 2022	12,355	160,298	7,388	46,459
Revisions of previous estimates (1)	3,273	26,068	814	8,432
Purchase of minerals in place (4)	6,565	41,560	4,400	17,892
Production	(2,393)	(23,384)	(1,083)	(7,374)
Net proved reserves at December 31, 2023	19,800	204,542	11,519	65,409
Net proved developed reserves
December 31, 2021	12,511	157,764	6,669	45,474
December 31, 2022	12,355	160,298	7,388	46,459
December 31, 2023	19,800	204,542	11,519	65,409

(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

(2) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins.

(3) Includes the acquisition of mineral and royalty interests for a total of $56.8 million, primarily consisting of mineral and royalty interests in the Permian Basin.

(4) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Future cash inflows	$	2,226,313	$	2,253,273	$	1,335,917
Future production costs		(164,848)		(161,676)		(100,947)
Future state margin taxes		(49,144)		(76,322)		(42,965)
Future net cash flows		2,012,321		2,015,275		1,192,005
Less 10% annual discount to reflect timing of cash flows		(1,037,192)		(1,110,980)		(665,390)
Standard measure of discounted future net cash flows	$	975,129	$	904,295	$	526,615

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2023, 2022 and 2021 were $78.22, $93.67 and $66.56 per barrel for crude oil and $2.64, $6.36 and $3.60 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Standardized measure - beginning of year	$	904,295	$	526,615	$	284,996
Sales, net of production costs		(236,953)		(252,597)		(152,751)
Net changes of prices and production costs related to future production		(302,599)		365,427		225,868
Revisions of previous quantity estimates, net of related costs		128,727		71,776		60,517
Net changes in state margin taxes		10,433		(15,266)		(8,665)
Accretion of discount		78,425		44,280		25,743
Purchases of reserves in place		435,230		77,719		40,545
Timing differences and other		(42,429)		86,341		50,362
Standardized measure - end of year	$	975,129	$	904,295	$	526,615

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2023

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Basis of Presentation

The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Use of Estimates

Use of Estimates

Preparation of the Partnership’s financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and notes. Actual results could differ from those estimates.

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, recoverability of costs of unevaluated properties, valuation of commodity and interest rate derivative financial instruments and the fair value of equity-based compensation.

The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Segment Reporting

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.

Cash and Cash Equivalents

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Oil, Natural Gas and NGL Receivables

Oil, Natural Gas and NGL Receivables

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2023 and 2022, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Derivative Financial Instruments

Derivative Financial Instruments

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though

they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statements of operations within gain (loss) on commodity derivative instruments.

Interest Rate Swaps

The Partnership used an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converted a portion of the Partnership’s secured revolving credit facility from a floating to a fixed rate. Changes in the fair values of the Partnership’s interest rate swaps were recognized as gains or losses in the current period and are presented on a net basis within other income in the consolidated statements of operations.

Property and Equipment

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Loan Origination Costs

Loan Origination Costs

Certain direct costs associated with the Partnership’s secured revolving credit facility are presented in the consolidated balance sheets as loan origination costs. These costs are amortized over the term of the secured revolving credit facility and included as a component of interest expense in the consolidated statements of operations.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas 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 capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2023, 2022 or 2021.

The Partnership assesses all unevaluated properties on periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is

able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

Due to the nature of the Partnership’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2023, 2022 or 2021.

Other Current Liabilities

Other Current Liabilities

Other current liabilities consist primarily of Series A preferred unit and Class B unit distributions, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities.

Earnings Per Unit

Earnings Per Unit

Earnings per unit applicable to limited partners is computed utilizing the “if-converted” method, which is calculated by dividing limited partners’ interested in net income by the weighted average number of outstanding common units. The treasury-stock method is utilized to determine the dilutive effect, if any, of unvested common units granted under the Partnership’s long-term incentive plan (“LTIP”).

Income Taxes

Income Taxes

As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. The non-controlling interest, which represents OpCo common unitholders’, as defined below, are not subject to federal income taxes.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership had no uncertain tax positions at December 31, 2023, 2022 and 2021.

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2023, 2022 and 2021, the Partnership did not recognize any interest or penalty expense related to uncertain tax positions.

Concentration of Credit Risk

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

During the years ended December 31, 2023, 2022 and 2021, the Partnership’s top purchaser accounted for approximately 6.7%, 11.3% and 6.0%, respectively, of oil, natural gas and NGL sales revenue.

Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the  Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information.

Non-controlling Interest

Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents OpCo common unitholders’, as defined below, ownership in the net assets of the Operating Company. When the OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.” This guidance requires that any differences between the carrying value of the Partnership’s basis in the Operating Company and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 10—Unitholders’ Equity and Partnership Distributions for further discussion.

Revenue from Contracts with Customers

Revenue from Contracts with Customers

The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods:

	Year Ended December 31,
	2023		2022			2021
Oil revenue	$	183,150,517	$	130,811,485	$	87,151,724
Natural gas revenue		59,524,413		122,632,983		66,977,352
NGL revenue		24,909,855		28,519,658		20,958,945
Total Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021

Transaction Price Allocated to Remaining Performance Obligations

The Partnership’s right to revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts.

Contract Balances

Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP.

Prior-Period Performance Obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the revenue to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2023, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent

actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value Measurements

Fair Value Measurements

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.

Consolidation

Consolidation

The Partnership analyzes whether it has a variable interest in an entity and whether that entity is a variable interest entity (“VIE”) to determine whether it is required to consolidate those entities. The Partnership performs the variable interest analysis for all entities in which it has a potential variable interest, which primarily consist of all entities with respect to which the Partnership serves as the sponsor, general partner or managing member, and general partner entities not wholly owned by the Partnership. If the Partnership has a variable interest in the entity and the entity is a VIE, it will also analyze whether the Partnership is the primary beneficiary of this entity and whether consolidation is required.

In evaluating whether it has a variable interest in the entity, the Partnership reviews the equity ownership and the extent to which it absorbs risk created and distributed by the entity, as well as whether the fees charged to the entity are customary and commensurate with the level of effort required to provide services. Fees received by the Partnership are not variable interests if (i) the fees are compensation for services provided and are commensurate with the level of effort required to provide those services, (ii) the service arrangement includes only terms, conditions, or amounts that are customarily present in arrangements for similar services negotiated at arm’s length and (iii) the Partnership’s other economic interests in the VIE held directly and indirectly through its related parties, as well as economic interests held by related parties under common control, where applicable, would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. Evaluation of these criteria requires judgment.

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

VIEs of which the Partnership is the primary beneficiary have been included in the Partnership’s consolidated financial statements. The portion of the consolidated subsidiaries owned by third parties and any related activity is eliminated through non-controlling interests in the consolidated balance sheets and income (loss) attributable to non-controlling interests in the consolidated statements of operations.

Investments Held in Trust by Consolidated Variable Interest Entities

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the

trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represented the shares of Class A common stock of TGR par value $0.0001 per share (the “Class A common stock”) sold in the TGR IPO that were redeemable for cash by the public TGR shareholders that would have been concurrent with TGR’s initial business combination or in the event of TGR’s failure to complete a business combination or a tender offer. The redeemable non-controlling interests were initially recorded at their original issue price, net of issuance costs and the initial fair value of separately traded warrants. As of June 30, 2023, the shares had been redeemed in full.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

In March 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-01, “Leases (Topic 842): Common Control Arrangements.” This update requires that (i) entities determine whether a related party arrangement between entities under common control is a lease and (ii) that leasehold improvements have an amortization period consistent with the shorter of the remaining lease term and the useful life of the improvements, which is an approach that is largely consistent with legacy guidance. This update is effective for financial statements issued for fiscal years beginning after December 15, 2023, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 820): Improvements to Reportable Segment Disclosures.” The amendments in this update apply to all public entities that are required to report segment information in accordance with Topic 280, Segment Reporting. The amendments in this update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025. The Partnership is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2023

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Schedule of disaggregation of revenues

	Year Ended December 31,
	2023		2022			2021
Oil revenue	$	183,150,517	$	130,811,485	$	87,151,724
Natural gas revenue		59,524,413		122,632,983		66,977,352
NGL revenue		24,909,855		28,519,658		20,958,945
Total Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2023

DERIVATIVES

Schedule of changes in fair value of derivative instruments

	Year Ended December 31,
	2023		2022		2021
Beginning fair value of derivative instruments	$	(12,324,076)	$	(26,624,646)	$	(6,280,863)
Gain (loss) on commodity derivative instruments, net		20,888,972		(32,240,915)		(41,240,942)
Net cash paid on settlements of derivative instruments		5,482,086		46,541,485		20,897,159
Ending fair value of derivative instruments	$	14,046,982	$	(12,324,076)	$	(26,624,646)

Schedule of derivative contracts

		December 31,		December 31,
Classification	Balance Sheet Location	2023		2022
Assets:
Current assets	Derivative assets	$	11,427,735	$	—
Long-term assets	Derivative assets		2,888,051		754,786
Liabilities:
Current liabilities	Derivative liabilities		(208,710)		(12,646,720)
Long-term liabilities	Derivative liabilities		(60,094)		(432,142)
		$	14,046,982	$	(12,324,076)

Schedule of commodity derivative contracts

Oil Price Swaps

	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)		Low		High
January 2024 - December 2024	568,926	$	79.04	$	69.30	$	85.34
January 2025 - December 2025	563,526	$	70.36	$	64.35	$	77.01

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
January 2024 - December 2024	5,285,182	$	3.97	$	3.06	$	4.48
January 2025 - December 2025	5,153,291	$	3.81	$	3.50	$	4.37

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2023

FAIR VALUE MEASUREMENTS

Schedule of assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
December 31, 2023
Assets
Commodity derivative contracts	$	—	$	14,315,786	$	—	$	—	$	14,315,786
Liabilities
Commodity derivative contracts	$	—	$	(268,804)	$	—	$	—	$	(268,804)
December 31, 2022
Assets
Commodity derivative contracts	$	—	$	754,786	$	—	$	—	$	754,786
Assets of consolidated variable interest entities:
Investments held in trust	$	240,621,146	$	—	$	—	$	—	$	240,621,146
Liabilities
Commodity derivative contracts	$	—	$	(13,078,862)	$	—	$	—	$	(13,078,862)

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OIL AND NATURAL GAS PROPERTIES (Tables)

12 Months Ended

Dec. 31, 2023

OIL AND NATURAL GAS PROPERTIES

Schedule of oil and natural gas properties

	December 31,		December 31,
	2023		2022
Oil and natural gas properties
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Less: accumulated depreciation, depletion and impairment		(827,033,944)		(712,716,951)
Total oil and natural gas properties	$	1,221,656,144	$	753,268,767

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LEASES (Tables)

12 Months Ended

Dec. 31, 2023

LEASES

Schedule of future minimum lease commitments

	Total		2024		2025		2026		2027		2028		Thereafter
Operating leases	$	2,712,673	$	488,725	$	497,033	$	507,648	$	511,917	$	496,785	$	210,565
Less: Imputed Interest		(476,273)
Total	$	2,236,400

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UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2023

Common units

Schedule of distributions approved by the Board of Directors

	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2023	$	0.35	May 3, 2023	May 15, 2023	May 22, 2023
Q2 2023	$	0.39	August 2, 2023	August 14, 2023	August 21, 2023
Q3 2023	$	0.51	November 2, 2023	November 13, 2023	November 20, 2023
Q4 2023	$	0.43	February 21, 2024	March 13, 2024	March 20, 2024
Q1 2022	$	0.47	April 22, 2022	May 2, 2022	May 9, 2022
Q2 2022	$	0.55	August 3, 2022	August 15, 2022	August 22, 2022
Q3 2022	$	0.49	November 3, 2022	November 14, 2022	November 21, 2022
Q4 2022	$	0.48	February 23, 2023	March 9, 2023	March 16, 2023
Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021
Q3 2021	$	0.37	October 22, 2021	November 1, 2021	November 8, 2021
Q4 2021	$	0.37	January 21, 2022	January 31, 2022	February 7, 2022

Common Units

Common units

Schedule of changes in Partnership's units

	Common Units
Balance at December 31, 2022	64,231,833
Common units issued under the A&R LTIP (1)	998,162
Restricted units repurchased for tax withholding	(279,662)
Common unit issued for acquisition	557,302
Common units issued for equity offering	8,337,500
Conversion of Class B units	6,323
Balance at December 31, 2023	73,851,458

(1) Includes restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “A&R LTIP”) on February 21, 2023.

Class B

Common units

Schedule of changes in Partnership's units

	Class B Units
Balance at December 31, 2022	15,484,400
Class B units issued for acquisition	5,369,218
Conversion of Class B units	(6,323)
Balance at December 31, 2023	20,847,295

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EARNINGS PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2023

EARNINGS PER COMMON UNIT

Schedule of earnings per common unit

	Year Ended December 31,
	2023		2022		2021
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		1,572,737		(17,412,732)		—
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		61,714,416		94,516,759		22,615,021
Distribution and accretion on Series A preferred units		6,310,215		—
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		16,553,676		18,864,795		8,496,104
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	84,578,307	$	113,381,554	$	31,111,125
Weighted average number of common units outstanding:
Basic		66,595,273		54,112,595		40,400,907
Effect of dilutive securities:
Series A preferred units		6,499,350		—		—
Class B units		18,851,387		10,819,266		18,839,607
Restricted units		1,111,721		905,156		1,717,310
Diluted		93,057,731		65,837,017		60,957,824
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51

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UNIT-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2023

UNIT-BASED COMPENSATION

Schedule of unvested restricted stock activity

		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 2022	1,897,192	$	13.553	1.517 years
Awarded	998,162		15.020	—
Vested	(943,924)		12.602	—
Unvested at December 31, 2023	1,951,430	$	14.763	1.525 years

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2023

INCOME TAXES

Schedule of income tax expense

	Year Ended December 31,
	2023		2022		2021
Current
Federal	$	2,469,584	$	2,412,702	$	69,067
State		1,296,718		326,000		5,033
Total Current		3,766,302		2,738,702		74,100
Deferred
Federal		—		—		—
State		—		—		—
Total Deferred		—		—		—
Provision for income taxes	$	3,766,302	$	2,738,702	$	74,100

Schedule of effective income expense

	Year Ended December 31,
	2023			2022			2021
Net income before taxes	$	86,771,872		$	133,532,988		$	42,511,974
Statutory rate		21	%		21	%		21	%
Income tax provision computed at statutory rate		18,222,093			28,041,927			8,927,515
Reconciling items:
State income taxes		1,393,149			326,000			5,033
Non-controlling interest		(3,518,924)			(3,988,366)			(1,788,347)
Income at OpCo		(14,703,170)			(24,053,561)			(7,139,168)
Change in valuation allowance - federal		2,860,951			2,202,314			(363,132)
Change in valuation allowance - state		(96,431)			(1,307,605)			(40,626)
Other, net		(391,366)			1,517,993			472,825
Provision for income taxes	$	3,766,302		$	2,738,702		$	74,100

Schedule of components of deferred tax assets and liabilities

	Year Ended December 31,
	2023		2022		2021
Deferred tax asset
Outside basis in OpCo	$	22,624,765	$	18,494,572	$	6,641,452
Federal tax loss carryforwards		—		2,645,475		12,296,282
State tax loss carryforwards		385,926		482,356		1,789,961
Business interest deduction limitation		1,376,234		—		—
Deferred tax asset		24,386,925		21,622,403		20,727,695
Valuation allowance		(24,386,925)		(21,622,403)		(20,727,695)
Net deferred tax asset	$	—	$	—	$	—

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2023

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Schedule of oil and natural gas aggregate capitalized costs and applicable accumulated depreciation, depletion and amortization

	December 31,		December 31,
	2023		2022
Oil, natural gas and NGL interests
Proved properties	$	1,825,977,244	$	1,258,290,375
Unevaluated properties		222,712,844		207,695,343
Total oil, natural gas and NGL interests		2,048,690,088		1,465,985,718
Accumulated depreciation, depletion, accretion and impairment		(827,033,944)		(712,716,951)
Net oil, natural gas and NGL interests capitalized	$	1,221,656,144	$	753,268,767

Schedule of costs incurred in oil and natural gas activities

	Year Ended December 31,
	2023		2022		2021
Acquisition costs
Proved properties	$	260,145,370	$	56,848,235	$	55,300,252
Unevaluated properties		322,559,000		204,742,000		—
Total		582,704,370		261,590,235		55,300,252
Development costs
Proved properties		—		—		—
Total		—		—		—
Total costs incurred on oil, natural gas and NGL activities	$	582,704,370	$	261,590,235	$	55,300,252

Results of operations from oil, natural gas and natural gas liquids

	Year Ended December 31,
	2023		2022		2021
Oil, natural gas and NGL revenues	$	267,584,785	$	281,964,126	$	175,088,021
Lease bonus and other income		5,594,855		3,073,609		3,319,104
Production and ad valorem taxes		(20,326,477)		(16,238,814)		(10,480,481)
Depreciation and depletion expense		(96,477,003)		(50,086,414)		(36,797,881)
Impairment of oil and natural gas properties		(18,220,173)		—		—
Marketing and other deductions		(12,564,619)		(13,383,074)		(12,048,643)
Results of operations from oil, natural gas and NGLs	$	125,591,368	$	205,329,433	$	119,080,120

Schedule of net proved oil, natural gas and natural gas liquids reserves and changes

	Crude Oil and		Natural Gas
	Condensate	Natural Gas	Liquids	Total
	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Net proved reserves at January 1, 2021	12,294	144,233	6,085	42,418
Revisions of previous estimates (1)	251	24,079	780	5,044
Purchase of minerals in place (2)	1,310	8,537	519	3,252
Production	(1,344)	(19,085)	(715)	(5,240)
Net proved reserves at December 31, 2021	12,511	157,764	6,669	45,474
Revisions of previous estimates (1)	(58)	17,119	759	3,554
Purchase of minerals in place (3)	1,328	5,726	707	2,989
Production	(1,426)	(20,311)	(747)	(5,558)
Net proved reserves at December 31, 2022	12,355	160,298	7,388	46,459
Revisions of previous estimates (1)	3,273	26,068	814	8,432
Purchase of minerals in place (4)	6,565	41,560	4,400	17,892
Production	(2,393)	(23,384)	(1,083)	(7,374)
Net proved reserves at December 31, 2023	19,800	204,542	11,519	65,409
Net proved developed reserves
December 31, 2021	12,511	157,764	6,669	45,474
December 31, 2022	12,355	160,298	7,388	46,459
December 31, 2023	19,800	204,542	11,519	65,409

(1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

(2) Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in the Permian Basin, Mid-Continent, Haynesville and other leading U.S. basins.

(3) Includes the acquisition of mineral and royalty interests for a total of $56.8 million, primarily consisting of mineral and royalty interests in the Permian Basin.

(4) Includes the acquisition of mineral and royalty interests, primarily consisting of mineral and royalty interests in the Permian Basin and Mid-Continent.

Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Future cash inflows	$	2,226,313	$	2,253,273	$	1,335,917
Future production costs		(164,848)		(161,676)		(100,947)
Future state margin taxes		(49,144)		(76,322)		(42,965)
Future net cash flows		2,012,321		2,015,275		1,192,005
Less 10% annual discount to reflect timing of cash flows		(1,037,192)		(1,110,980)		(665,390)
Standard measure of discounted future net cash flows	$	975,129	$	904,295	$	526,615

Schedule of changes in standardized measure related to proved oil, natural gas and natural gas liquids reserves

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Standardized measure - beginning of year	$	904,295	$	526,615	$	284,996
Sales, net of production costs		(236,953)		(252,597)		(152,751)
Net changes of prices and production costs related to future production		(302,599)		365,427		225,868
Revisions of previous quantity estimates, net of related costs		128,727		71,776		60,517
Net changes in state margin taxes		10,433		(15,266)		(8,665)
Accretion of discount		78,425		44,280		25,743
Purchases of reserves in place		435,230		77,719		40,545
Timing differences and other		(42,429)		86,341		50,362
Standardized measure - end of year	$	975,129	$	904,295	$	526,615

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ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting
Number of operating units	1
Number of reporting units	1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details)	Dec. 31, 2023
Minimum
Oil and natural gas properties
Useful life	3 years
Maximum
Oil and natural gas properties
Useful life	7 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Oil and Natural Gas Properties
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties	$ 0	$ 0	$ 0
Number of exploratory activities pending determination	0	0	0
Exploratory costs charged	$ 0	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes
Uncertain tax positions	$ 0	$ 0	$ 0
Interest and penalties	$ 0	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Concentration of Credit Risk
Number of significant purchasers	1
Operator 1
Concentration of Credit Risk
Purchaser percentage	6.70%	11.30%	6.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue
Total revenue	$ 267,584,785	$ 281,964,126	$ 175,088,021
Oil revenue
Revenue
Total revenue	183,150,517	130,811,485	87,151,724
Natural gas revenue
Revenue
Total revenue	59,524,413	122,632,983	66,977,352
NGL revenue
Revenue
Total revenue	$ 24,909,855	$ 28,519,658	$ 20,958,945

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details)	12 Months Ended
	Dec. 31, 2023
Minimum
Settlement period for certain natural gas and natural gas liquids sales	1 month
Maximum
Settlement period for certain natural gas and natural gas liquids sales	4 months

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Feb. 08, 2022
Accounts Receivable
Allowance for doubtful accounts receivable	$ 0	$ 0
Kimbell Tiger Acquisition Corporation | Class A
Accounts Receivable
Common Stock par value (in dollars per share)			$ 0.0001

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ACQUISITIONS, JOINT VENTURES AND SPECIAL PURPOSE ACQUISITION COMPANY - Acquisitions (Details)									12 Months Ended
	Sep. 13, 2023 USD ($)	May 22, 2023 USD ($)	May 17, 2023 USD ($) shares	May 08, 2023 item	Feb. 08, 2023 USD ($)	Dec. 15, 2022 USD ($) a shares	Dec. 07, 2021 USD ($) item	Mar. 10, 2021 USD ($)	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Feb. 08, 2022 $ / shares	Jun. 19, 2019
Acquisitions
Common units sold to public									$ 110,711,383	$ 116,119,417	$ 57,522,440
Assets									1,337,789,216	1,076,746,299
Liabilities									$ 309,322,464	263,336,623
Purchase and sale agreement | Royalty, mineral and overriding interests
Acquisitions
Total purchase price										15,000,000.0
Net proceeds realized										$ 6,500,000
Kimbell Tiger Acquisition Corporation | IPO
Acquisitions
Common units sold to public					$ 230,000,000.0
Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.
Acquisitions
Ownership interest (as a percent)													49.30%
Kimbell Tiger Acquisition Corporation
Acquisitions
Redemption of equity in variable interest entity		$ 1,600,000
Period for each business combination extension				3 months
Number of business combination extensions | item				2
Common Units
Acquisitions
Common units issued for equity offering (in units) | shares									8,337,500
Class A | Kimbell Tiger Acquisition Corporation
Acquisitions
Common Stock par value (in dollars per share) | $ / shares												$ 0.0001
LongPoint Minerals II, LLC
Acquisitions
Purchase price cash, gross	$ 455,000,000.0
Transactional costs	7,400,000
Post-effective net oil, natural gas and NGL revenues earned prior to the closing date	16,600,000
Acquisition asset allocation
Proved properties	198,200,000
Unevaluated properties	$ 247,600,000
Nail Bay Royalties
Acquisitions
Purchase price cash, gross								$ 500,000
2021 Acquisitions
Acquisition asset allocation
Proved properties											$ 55,300,000
Caritas Royalty Fund, LLC
Acquisitions
Transaction value of acquisition							$ 54,600,000
Number of gross producing wells being operated. | item							26,000
Hatch Royalties, LLC
Acquisitions
Cash paid to acquire businesses, net of cash acquired and transaction costs						$ 150,400,000
Gross acres acquired (in acres) | a						230,000
Net royalty acres acquired (in acres) | a						889
Acquisition asset allocation
Proved properties						$ 56,400,000
Unevaluated properties						$ 204,700,000
Hatch Royalties, LLC | Capital Unit Class B
Acquisitions
Business Acquisition issuance of common units | shares						7,272,821
Hatch Royalties, LLC | OpCo Units
Acquisitions
Business Acquisition issuance of common units | shares						7,272,821
MB Minerals, L.P.
Acquisitions
Purchase price cash, gross			$ 48,800,000
Acquisition asset allocation
Proved properties			60,800,000
Unevaluated properties			$ 74,900,000
MB Minerals, L.P. | OpCo Units
Acquisitions
Business Acquisition issuance of common units | shares			5,369,218
MB Minerals, L.P. | Class B Common Units
Acquisitions
Business Acquisition issuance of common units | shares			557,302

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DERIVATIVES (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl bbl MMBbls	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	May 17, 2022	Jan. 27, 2021 USD ($)
Change in fair values of derivative instruments
Beginning fair value of commodity derivative instruments | $	$ (12,324,076)	$ (26,624,646)	$ (6,280,863)
Gain (loss) on commodity derivative instruments, net | $	20,888,972	(32,240,915)	(41,240,942)
Net cash paid on settlements of derivative instruments | $	5,482,086	46,541,485	20,897,159
Ending fair value of commodity derivative instruments | $	14,046,982	(12,324,076)	(26,624,646)
Assets:
Current assets | $	11,427,735
Long-term assets | $	2,888,051	754,786
Liabilities:
Current liability | $	(208,710)	(12,646,720)
Long-term liability | $	(60,094)	(432,142)
Derivative assets (liabilities) | $	$ 14,046,982	(12,324,076)	(26,624,646)
Interest Rate Swap
Derivatives
Derivative, Notional Amount | $			150,000,000.0		$ 150,000,000.0
Unwind notional amount (as a percent)				50.00%
Change in fair values of derivative instruments
Gain on interest rate swap | $		$ 6,400,000
Liabilities:
Derivative Asset | $			$ 1,800,000
Oil Price Swaps - January 2024 - December 2024
Derivatives
Notional Volumes | bbl	568,926
Weighted Average Fixed Price | $ / bbl	79.04
Oil Price Swaps - January 2025 - December 2025
Derivatives
Notional Volumes | bbl	563,526
Weighted Average Fixed Price | $ / bbl	70.36
Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Notional Volumes | MMBbls	5,285,182
Weighted Average Fixed Price | $ / bbl	3.97
Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Notional Volumes | MMBbls	5,153,291
Weighted Average Fixed Price | $ / bbl	3.81
Minimum | Oil Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	69.30
Minimum | Oil Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	64.35
Minimum | Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	3.06
Minimum | Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	3.50
Maximum | Oil Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	85.34
Maximum | Oil Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	77.01
Maximum | Natural Gas Price Swaps - January 2024 - December 2024
Derivatives
Weighted Average Fixed Price | $ / bbl	4.48
Maximum | Natural Gas Price Swaps - January 2025 - December 2025
Derivatives
Weighted Average Fixed Price | $ / bbl	4.37

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FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Commodity Derivative contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets	$ 14,315,786	$ 754,786
Derivative contracts liabilities	(268,804)	(13,078,862)
Commodity Derivative contract | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets	14,315,786	754,786
Derivative contracts liabilities	$ (268,804)	(13,078,862)
Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets			$ 1,800,000
Assets Held In Trust | Consolidated variable interest entities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets		240,621,146
Assets Held In Trust | Level 1 | Consolidated variable interest entities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contracts assets		$ 240,621,146

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OIL AND NATURAL GAS PROPERTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
OIL AND NATURAL GAS PROPERTIES
Proved properties	$ 1,825,977,244	$ 1,258,290,375
Unevaluated properties	222,712,844	207,695,343
Less: accumulated depreciation, depletion, and impairment	(827,033,944)	(712,716,951)
Total oil and natural gas properties	1,221,656,144	753,268,767
Impairment of oil and natural gas properties	$ 18,220,173	$ 0	$ 0

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OIL AND NATURAL GAS PROPERTIES - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2023 $ / bbl	Dec. 31, 2023 $ / Mcf	Dec. 31, 2023	Dec. 31, 2022 USD ($)	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2021 USD ($) $ / bbl
Oil and natural gas properties
Impairment of oil and natural gas properties | $	$ 18,220,173				$ 0			$ 0
Crude Oil
Oil and natural gas properties
Average sales prices | $ / bbl		78.22				93.67		66.56
Percentage of average prices of oil and natural gas				16.50%
Natural Gas
Oil and natural gas properties
Average sales prices		2.64	2.64			6.36	6.36	3.60
Percentage of average prices of oil and natural gas				58.50%

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LEASES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
LEASES
Operating lease weighted average remaining lease term	5 years 5 months 4 days
Operating lease weighted average discount rate (as a percent)	6.75%
Operating lease expense	$ 600,000	$ 500,000	$ 400,000
2024	488,725
2025	497,033
2026	507,648
2027	511,917
2028	496,785
Thereafter	210,565
Total operating leases	2,712,673
Less Imputed Interest	(476,273)
Total	$ 2,236,400

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LONG-TERM DEBT (Details) - USD ($)		12 Months Ended
	Jun. 13, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 08, 2023	Dec. 07, 2023	Jul. 24, 2023	Jul. 23, 2023
Long-term debt
Minimum percentage of proved reserves constituting borrowings based properties (as a percent)		75.00%
Amortization of Debt Issuance Costs		$ 1,943,025	$ 1,872,700	$ 1,556,769
Debt extinguishment		500,000
Borrowings of debt		201,084,089	199,200,000	136,565,769
Repayment of debt		139,900,000	$ 183,300,000	$ 91,000,000
Revolving credit facility
Long-term debt
Borrowing base					$ 550,000,000.0	$ 400,000,000.0
Revolving credit facility outstanding		$ 294,200,000
Excess cash determinations							$ 50,000,000.0	$ 30,000,000.0
Interest rate on outstanding borrowings (as a percent)		8.62%
Borrowings of debt		$ 201,100,000
Repayment of debt		$ 139,900,000
Revolving credit facility | Prime
Long-term debt
Margin (as a percent)		2.25%
Revolving credit facility | SOFR
Long-term debt
Margin (as a percent)		3.25%
Variable rate		SOFR
Revolving credit facility | Maximum
Long-term debt
Debt to EBITDAX ratio		3.50%
Revolving credit facility | Minimum
Long-term debt
Current assets to current liabilities ratio		1.00%
Standby and/or commercial letters of credit
Long-term debt
Revolving credit facility maximum borrowings	$ 10,000,000.0
Revolving credit facility outstanding		$ 0
Senior Secured Reserve Based Revolving Credit Facility
Long-term debt
Revolving credit facility maximum borrowings	750,000,000.0
Borrowing base	400,000,000.0
Initial aggregate elected commitments amount	400,000,000.0
Minimum cash balance required to be applied weekly to prepay loans	50,000,000.0
Reduced cash balance as permitted by agreement	$ 0
Commitment fees (as a percent)	0.50%
Senior Secured Reserve Based Revolving Credit Facility | Maximum | SOFR
Long-term debt
Margin (as a percent)	3.75%
Senior Secured Reserve Based Revolving Credit Facility | Maximum | Base Rate
Long-term debt
Margin (as a percent)	2.75%
Senior Secured Reserve Based Revolving Credit Facility | Minimum | SOFR
Long-term debt
Margin (as a percent)	2.75%
Senior Secured Reserve Based Revolving Credit Facility | Minimum | Base Rate
Long-term debt
Margin (as a percent)	1.75%

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PREFERRED UNITS - Other (Details)			12 Months Ended
	Sep. 13, 2023 USD ($) D item $ / shares shares	Aug. 02, 2023 shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2021 USD ($)	Dec. 31, 2022 shares
Preferred units
Temporary equity, issued (in units)			325,000		0
Liquidation preference rate (in percentage)	10.00%
Increased distribution rate	20.00%
Series A preferred units deemed distributions | $			$ 6,310,215	$ 11,249,969
Temporary equity, outstanding (in units)			325,000		0
Series A Preferred Units
Preferred units
The period after issuance securities become convertible	7 years
Percentage of cash distributions per annum	6.00%
Number of members of board | item	2
Ownership required to grant the approval	66.67%
Ratio of return on investment to preferred units	1.2
Series A Preferred Units | Series A Issuance Date
Preferred units
Minimum internal rate of return (as percent)	12.00%
Series A Preferred Units | On or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	13.00%
Series A Preferred Units | On or after the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	14.00%
Series A Preferred Units | Minimum | The Partnership
Preferred units
Aggregate value of common units to be issued for preferred units | $	$ 10,000,000.0
Percentage of closing price to the conversion price	160.00%
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30
Affiliates of Apollo Capital Management, L.P. | LongPoint Minerals II, LLC
Preferred units
Series A preferred units issued	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | Kimbell Royalty Operating, LLC
Preferred units
Temporary equity, issued (in units)	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | LongPoint Minerals II, LLC
Preferred units
Share price (in dollars per unit) | $ / shares	$ 1,000
Proceeds from the issuance of preferred units | $	$ 325,000,000.0
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Stock
Preferred units
Series A preferred units issued		400,000
Series A Purchasers | Minimum
Preferred units
Percentage of closing price to the conversion price	130.00%
Conversion price of units | $ / shares	$ 15.07
Series A Purchasers | Series A Preferred Units | Minimum
Preferred units
Aggregate value of common units to be issued for preferred units | $	$ 10,000,000.0
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30

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UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($)		1 Months Ended		3 Months Ended												12 Months Ended
	Aug. 07, 2023	Nov. 30, 2022	Nov. 30, 2021	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Common units
Units issued (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Units outstanding (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Repayment of debt																$ 139,900,000	$ 183,300,000	$ 91,000,000
Capital rollforward
Unitholders' capital, beginning balance (in units)							64,231,833									64,231,833
Unitholders' capital, ending balance (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Cash distributions declared and paid (in dollars per unit)				$ 0.43	$ 0.51	$ 0.39	$ 0.35	$ 0.48	$ 0.49	$ 0.55	$ 0.47	$ 0.37	$ 0.37	$ 0.31	$ 0.27
Common Units
Common units
Units issued (in units)				73,851,458												73,851,458
Units outstanding (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Capital rollforward
Unitholders' capital, beginning balance (in units)							64,231,833									64,231,833
Common units issued under the A&R LTIP (in units)																998,162
Restricted units repurchased for tax withholding (in units)																(279,662)
Common unit issued for acquisition (in units)																557,302
Common units issued for equity offering (in units)																8,337,500
Conversion of Class B Units (in units)																6,323
Unitholders' capital, ending balance (in units)				73,851,458				64,231,833								73,851,458	64,231,833
Class B
Common units
Units outstanding (in units)				20,847,295				15,484,400								20,847,295	15,484,400
Capital rollforward
Unitholders' capital, beginning balance (in units)							15,484,400									15,484,400
Class B units issued for Drop Down acquisition																5,369,218
Conversion of Class B Units (in units)							(6,323)
Unitholders' capital, ending balance (in units)				20,847,295				15,484,400								20,847,295	15,484,400
Cash distributions (as a percent)																2.00%
Additional consideration paid per unit (in dollars per unit)																$ 0.05
Public Offering
Common units
Units issued (in units)	8,337,500	6,900,000	4,312,500
Proceeds from equity offering	$ 110,700,000	$ 116,100,000	$ 57,700,000
Repayment of debt	$ 90,000,000.0	$ 116,000,000.0	$ 56,000,000.0

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EARNINGS PER COMMON UNIT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings per unit
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 60,141,679	$ 111,929,491	$ 22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions	(1,572,737)	17,412,732
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions	61,714,416	94,516,759	22,615,021
Distribution and accretion on Series A preferred units	6,310,215		11,249,969
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$ 84,578,307	$ 113,381,554	$ 31,111,125
Weighted average number of common units outstanding Basic (in units)	66,595,273	54,112,595	40,400,907
Weighted average number of common units outstanding Diluted (in units)	93,057,731	65,837,017	60,957,824
Net income per unit attributable to common units (basic) (in dollar per share)	$ 0.93	$ 1.75	$ 0.56
Net income per unit attributable to common units (diluted) (in dollar per share)	$ 0.91	$ 1.72	$ 0.51
Series A Preferred Units
Earnings per unit
Net income attributable to non-controlling interests in OpCo and distribution on Class B units	$ 16,553,676	$ 18,864,795	$ 8,496,104
Weighted average number of common units outstanding (in units)	6,499,350
Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)	1,111,721	905,156	1,717,310
Class B
Earnings per unit
Weighted average number of common units outstanding (in units)	18,851,387	10,819,266	18,839,607

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UNIT-BASED COMPENSATION (Details) - Long-Term Incentive Plan - $ / shares		12 Months Ended
	May 18, 2022	Dec. 31, 2023	Dec. 31, 2022
Unit-based compensation
Additional common units authorized for issuance	3,700,000
Vesting period		3 years
Authorized issuance of units	8,241,600
First Anniversary
Unit-based compensation
Vesting percent		33.30%
Second Anniversary
Unit-based compensation
Vesting percent		33.30%
Third Anniversary
Unit-based compensation
Vesting percent		33.30%
Restricted Units
Unvested Units
Unvested at beginning of period (in units)		1,897,192
Awarded (in units)		998,162
Vesting (in units)		(943,924)
Unvested at end of period (in units)		1,951,430	1,897,192
Unvested Weighted Average Grant-Date Fair Value
Unvested at beginning of period (in dollars per unit)		$ 13.553
Awarded (in dollars per unit)		15.020
Vesting (in dollars per unit)		12.602
Unvested at end of period (in dollars per unit)		$ 14.763	$ 13.553
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period		1 year 6 months 9 days	1 year 6 months 6 days

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INCOME TAXES - (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
INCOME TAXES
Effective income tax rate (as a percent)	4.34%
Income tax expense	$ 3,766,302	$ 2,738,702	$ 74,100

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INCOME TAXES - Provision (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current
Federal	$ 2,469,584	$ 2,412,702	$ 69,067
State	1,296,718	326,000	5,033
Total Current	3,766,302	2,738,702	74,100
Deferred
Provision for income taxes	$ 3,766,302	$ 2,738,702	$ 74,100

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INCOME TAXES - Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate
Net income before taxes	$ 86,771,872	$ 133,532,988	$ 42,511,974
Statutory rate (as a percent)	21.00%	21.00%	21.00%
Income tax provision computed at statutory rate	$ 18,222,093	$ 28,041,927	$ 8,927,515
State income taxes	1,393,149	326,000	5,033
Non-controlling interest	(3,518,924)	(3,988,366)	(1,788,347)
Income at OpCo	(14,703,170)	(24,053,561)	(7,139,168)
Change in valuation allowance - federal	2,860,951	2,202,314	(363,132)
Change in valuation allowance - state	(96,431)	(1,307,605)	(40,626)
Other, net	(391,366)	1,517,993	472,825
Provision for income taxes	$ 3,766,302	$ 2,738,702	$ 74,100

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INCOME TAXES - Deferred Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred tax asset
Outside basis in OpCo	$ 22,624,765	$ 18,494,572	$ 6,641,452
Federal tax loss carryforwards		2,645,475	12,296,282
State tax loss carryforwards	385,926	482,356	1,789,961
Business interest deduction limitation	1,376,234
Deferred tax assets	24,386,925	21,622,403	20,727,695
Valuation allowance	(24,386,925)	(21,622,403)	(20,727,695)
Deferred tax liability
Outside basis investment in operating company valuation allowance	24,400,000
Uncertain tax positions	$ 0	$ 0	$ 0

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RELATED PARTY TRANSACTIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions
Total revenue	$ 294,068,612	$ 248,059,185	$ 135,615,216
Related Party
Related Party Transactions
Due from related parties	25,000
Total revenue	50,000
Related Party | BJF Royalties
Related Party Transactions
Payments made to related parties	0
Related Party | K3 Royalties
Related Party Transactions
Payments made to related parties	120,000
Related Party | Director And Officer Insurance To Partnership At Higginbotham Insurance Financial Services
Related Party Transactions
Related Party Transaction, Amounts of Transaction	26,500
Related Party Transactions, Annual Insurance Premium Expense	602,600
Related Party | Rivercrest Capital Management, LLC
Related Party Transactions
Related party expense reimbursement received	$ 180,626

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ADMINISTRATIVE SERVICES (Details) - LongPoint Acquisition	12 Months Ended
	Dec. 31, 2023 USD ($)
Transition Service Agreement amount of administrative services to be received	$ 250,000
Transition service fees incurred	$ 900,000

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SUBSEQUENT EVENTS (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions	Mar. 13, 2024	Feb. 21, 2024	Feb. 20, 2024	Feb. 19, 2024
OpCo Units
Subsequent events
Tax payment made from cash reserves per unit			$ 0.023897
Cash distributions declared (in dollars per unit)		$ 0.453897
Series A Preferred Stock
Subsequent events
Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Declared	$ 4.9
Common Units
Subsequent events
Cash distributions declared (in dollars per unit)		$ 0.43
Executive Officers
Subsequent events
Cash bonuses awarded				$ 2.5
Units issued for bonus compensation				1,087,502

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Number of reporting segments | segment	1
Oil, natural gas and NGL interests
Proved properties	$ 1,825,977,244	$ 1,258,290,375
Unevaluated properties	222,712,844	207,695,343
Total oil, natural gas and NGL interest	2,048,690,088	1,465,985,718
Accumulated depreciation, depletion and impairment	(827,033,944)	(712,716,951)
Net oil, natural gas and NGL interests capitalized	1,221,656,144	753,268,767
Acquisition costs
Proved properties	260,145,370	56,848,235	$ 55,300,252
Unevaluated properties	322,559,000	204,742,000
Total	582,704,370	261,590,235	55,300,252
Developed costs
Total costs incurred on oil, natural gas and NGL activities	582,704,370	261,590,235	55,300,252
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue	267,584,785	281,964,126	175,088,021
Lease bonus and other income	5,594,855	3,073,609	3,319,104
Production and ad valorem taxes	(20,326,477)	(16,238,814)	(10,480,481)
Depreciation and depletion expense	(96,477,003)	(50,086,414)	(36,797,881)
Impairment of oil and natural properties	(18,220,173)
Marketing and other deductions	(12,564,619)	(13,383,074)	(12,048,643)
Results of operations form oil, natural gas and NGLs	$ 125,591,368	$ 205,329,433	$ 119,080,120

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Proved Oil, Natural Gas and Natural Liquids Reserve Quantities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 MBbls MMcf	Dec. 31, 2022 USD ($) MBbls MMcf	Dec. 31, 2021 USD ($) MBbls MMcf
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	46,459	45,474	42,418
Revisions of previous estimates	8,432	3,554	5,044
Purchase of minerals in place	17,892	2,989	3,252
Production	(7,374)	(5,558)	(5,240)
Net proved reserves at end of period	65,409	46,459	45,474
Net Proved Developed Reserves	65,409	46,459	45,474
Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	12,355	12,511	12,294
Revisions of previous estimates	3,273	(58)	251
Purchase of minerals in place	6,565	1,328	1,310
Production	(2,393)	(1,426)	(1,344)
Net proved reserves at end of period	19,800	12,355	12,511
Net Proved Developed Reserves	19,800	12,355	12,511
Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period | MMcf	160,298	157,764	144,233
Revisions of previous estimates | MMcf	26,068	17,119	24,079
Purchase of minerals in place | MMcf	41,560	5,726	8,537
Production | MMcf	(23,384)	(20,311)	(19,085)
Net proved reserves at end of period | MMcf	204,542	160,298	157,764
Net Proved Developed Reserves | MMcf	204,542	160,298	157,764
Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	7,388	6,669	6,085
Revisions of previous estimates	814	759	780
Purchase of minerals in place	4,400	707	519
Production	(1,083)	(747)	(715)
Net proved reserves at end of period	11,519	7,388	6,669
Net Proved Developed Reserves	11,519	7,388	6,669
Permian Basin Mid-Continent Region [Member]
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Purchase of mineral and royalty interests | $		$ 56.8	$ 55.3

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Standardized Measure
Future cash inflows	$ 2,226,313	$ 2,253,273	$ 1,335,917
Future production costs	(164,848)	(161,676)	(100,947)
Future state margin taxes	(49,144)	(76,322)	(42,965)
Future net cash flows	2,012,321	2,015,275	1,192,005
Less 10% annual discount to reflect timing of cash flows	(1,037,192)	(1,110,980)	(665,390)
Standard measure of discounted future net cash flows	$ 975,129	$ 904,295	$ 526,615	$ 284,996

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl	Dec. 31, 2023 $ / Mcf	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2021 $ / bbl
Crude Oil and Condensate
Average Sales Prices
Average sales prices	78.22		93.67		66.56
Natural Gas
Average Sales Prices
Average sales prices	2.64	2.64	6.36	6.36	3.60

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in Standardized Measure
Standardized measure - beginning of year	$ 904,295	$ 526,615	$ 284,996
Sales, net of production costs	(236,953)	(252,597)	(152,751)
Net changes of prices and production costs related to future production	(302,599)	365,427	225,868
Revisions of previous quantity estimates, net of related costs	128,727	71,776	60,517
Net changes in state margin taxes	10,433	(15,266)	(8,665)
Accretion of discount	78,425	44,280	25,743
Purchases of reserves in place	435,230	77,719	40,545
Timing differences and other	(42,429)	86,341	50,362
Standardized measure - end of year	$ 975,129	$ 904,295	$ 526,615

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Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023 shares
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	true
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false
Brett G. Taylor
Trading Arrangements, by Individual
Material Terms of Trading Arrangement	On November 29, 2023, Brett G. Taylor, Executive Vice Chairman of the Board of Directors, adopted a trading plan intended to satisfy Rule 10b5-1(c) to sell up to 125,833 common units between March 1, 2024, and December 31, 2024, subject to certain conditions
Name	Brett G. Taylor
Title	Executive Vice Chairman of the Board of Directors
Rule 10b5-1 Arrangement Adopted	true
Adoption Date	Nov. 29, 2023
Termination Date	Dec. 31, 2024
Aggregate Available	125,833