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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑K10-K

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

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For the fiscal year ended: December 31, 20172022

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

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For the transition period from to

Commission file number: 001‑38005001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)

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Delaware
(State or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

47‑550547547-5505475
(I.R.S. Employer
Identification No.)

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777 Taylor Street, Suite 810

Fort Worth, Texas76102

(817) 945‑9700(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:

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Title of class

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Trading Symbol

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Name of each exchange on which registered

Common Units Representing Limited Partner Interests

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KRP

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New York Stock Exchange

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

Indicate by check mark if the registrant is a well‑knownwell-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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑TS-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒  No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S‑K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑acceleratednon-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‑212b-2 of the Exchange Act.

Large accelerated filer

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Accelerated filer

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Non-accelerated filer

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Smaller reporting company

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Emerging growth company

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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.  ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑212b-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, 2017,2022, was $212.2$837.5 million, based on the closing price of such common units of $16.83$15.68 as reported on the New York Stock Exchange on such date. TheJune 30, 2022. As of February 17, 2023, the registrant had 16,836,453outstanding 64,231,833 common units outstanding as of March 2, 2018.representing limited partner interests and 15,484,400 Class B units representing limited partner units.

Documents Incorporated by Reference: None

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Table of Contents

Kimbell Royalty Partners, LP

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TABLE OF CONTENTS

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PART 1I

Item 1. Business

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Item 1A. Risk Factors

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Item 1B. Unresolved Staff Comments

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Item 2. Properties

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Item 3. Legal Proceedings

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Item 4. Mine Safety Disclosures

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PART II67

PART II

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

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Item 6. Selected Financial Data[Reserved]

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

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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Item 8. Financial Statements and Supplementary Data

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90

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

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Item 9A. Controls and Procedures

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Item 9B. Other Information

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PART III93

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

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Item 11. Executive Compensation and Other Information

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

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106

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

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109

Item 14. Principal Accounting Fees and Services

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PART IV114

PART IV

Item 15. Exhibits, Financial Statement Schedules

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115

Item 16. Form 10-K Summary

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118

Signatures

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119

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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”).

Available cash. For any quarter ending prior to liquidation:

(a)          the sum of:

(1)          all cash and cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand at the end of that quarter; and

(2)          as determined by the general partner of Kimbell Royalty Partners, LP, all cash or cash equivalents of Kimbell Royalty Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b)          less the amount of cash reserves established by the general partner of Kimbell Royalty Partners, LP to:

(1)          provide for the proper conduct of the business of Kimbell Royalty Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Kimbell Royalty Partners, LP and its subsidiaries) after that quarter;

(2)          comply with applicable law or any debt instrument or other agreement or obligation to which Kimbell Royalty Partners, LP or any of its subsidiaries is a party or its assets are subject; and

(3)          provide funds for distributions for any one or more of the next four quarters; provided, however, that disbursements made by Kimbell Royalty Partners, LP or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the general partner of Kimbell Royalty Partners, LP so determines.

Notwithstanding the foregoing, “available cash” with respect to the quarter in which the liquidation date occurs and any subsequent quarter shall equal zero.

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.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.

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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.

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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 NGL. 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.

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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.

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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‑acre40-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. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. 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‑LookingForward-Looking Statements

Certain statements and information in this Annual Report may constitute forward‑lookingforward-looking statements. Forward‑lookingForward-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‑lookingforward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward‑lookingforward-looking statements can be guaranteed. When considering these forward‑lookingforward-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‑lookingforward-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‑lookingforward-looking statements include:

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our ability to replace our reserves;

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

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the volatility of realized prices for oil, natural gas and NGLs;

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

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the level of production on our properties;

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

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

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

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our ability to replace our reserves;

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our ability to identify and complete acquisitions of assets or businesses;

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generalindustry, economic, business or industry conditions;

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

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weakness in the capital markets or the ongoing and potential impact to financial markets and worldwide economic activity resulting from the coronavirus and its variants (“COVID-19”) and related governmental actions;

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the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine;
●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;

industry generally and the mineral and royalty industry in particular;

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

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title defects in the properties in which we invest;

acquire an interest;

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uncertainties with respect to identified drilling locations and estimates of reserves;

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

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

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the availability of transportation facilities;

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

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federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry;

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

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future operating results;

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

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operating hazards faced by the operators of our properties;

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

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

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the ability of Kimbell Tiger Acquisition Corporation (“TGR”) to select an appropriate target business or businesses, enter into a binding agreement with a target and complete its initial business combination, as well as its ability to obtain necessary financing to complete its initial business combination;
●the overall performance and success of any target business or businesses selected by TGR for its initial business combination; and
●certain factors discussed elsewhere in this report.

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‑lookingforward-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.
●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 without unitholder approval.
●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.
●We are no longer an “emerging growth company,” and must comply with increased reporting and disclosure requirements, which may increase our costs.
●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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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.
●We will be required to take write-downs of the carrying values of our properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Tax Risks to Common Unitholders

●We may incur substantial income tax liabilities.

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

Risks Related to Our Investment in TGR

●TGR may not be able to complete its initial business combination within the prescribed time frame and we could lose our entire investment in TGR.
●Resources could be wasted in researching acquisitions that are not completed.
●We and TGR have overlapping directors and management, which may lead to conflicting interests.

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PART I

PART 1

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. References to “our Predecessor” refer to Rivercrest Royalties, LLC,us at the closing of our predecessor for accounting and financial reporting purposes.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 certain entities controlled by affiliates of certain of our Sponsors and Benny D. Duncancertain Contributing Parties as described herein.

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Item 1. Business

Overview

We are a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership elected to be taxed as a corporation for United States of America (“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 third 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 17, 2023:

Graphic

(1)The Sponsors are affiliates of our founders, Messrs. Fortson, R. Ravnaas, Taylor and Wynne.
(2)Includes common units beneficially owned by the Sponsors other than those reflected as held by Kimbell GP Holdings, LLC. Also includes common units beneficially owned by our directors and officers and other of our affiliates.
(3)Includes the Kimbell Art Foundation, Cupola Royalty Direct LLC, Rivercrest Capital Partners LP and certain affiliates of Hatch Royalty LLC.
(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 February 8, 2017,April 17, 2020, we completed our initial public offering (“IPO”the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”) from the owners of 5,750,000such entities (collectively, the “Springbok Sellers”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units representing limited partner interests which included 750,000in the Partnership (“common units”) and (iii) the issuance of 2,497,134 common units of the Operating Company (“OpCo common units”) and an equal number of newly issued Class B common units representing limited partner interests in the Partnership (“Class B units”). At the time of the Springbok Acquisition, the acreage acquired had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other U.S. leading basins.

On December 7, 2021, we 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 in cash. 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.

On December 15, 2022, we 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 we estimate that the assets consisted of approximately 889 net royalty acres on approximately 230,000 gross acres.

Kimbell Tiger Acquisition Corporation

In April 2021, we formed TGR as a special purpose acquisition company, or SPAC, for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. The sponsor of TGR is Kimbell Tiger Acquisition Sponsor, LLC (the “TGR Sponsor”), which is a wholly owned subsidiary of the Operating Company. The Sponsor owns a combination of equity securities in TGR and TGR’s operating company, Kimbell Tiger Operating Company, LLC (“TGR Opco”), that represent 20% of the total outstanding shares of common stock of TGR. TGR intends to focus its search for a target business in the energy and natural resources industry in North America.

On February 8, 2022, TGR completed its initial public offering (the “TGR IPO”) of 23,000,000 units, including 3,000,000 units that were issued pursuant to the underwriters’ optionunderwriter’s exercise in full of its over-allotment option. Each unit had an offering price of $10.00 and consists of one share of Class A common stock of the TGR, par value $0.0001 per share (the “Class A Common Stock”), and one-half of one redeemable warrant of TGR (each such whole warrant, a “Public Warrant”). Each Public Warrant entitles the holder thereof to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Partiesone share of Class A Common Stock at a price of $11.50 per share.

On February 8, 2022, simultaneously with the closing of the IPO. AsTGR IPO and pursuant to a result, asseparate private placement warrants purchase agreement dated February 3, 2022, TGR completed the private sale of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers14,100,000 warrants (the “Private Placement Warrants”) to the Partnership asTGR Sponsor at a whole. The financial information presentedpurchase price of $1.00 per Private Placement Warrant, generating gross proceeds of $14,100,000. Each Private Placement Warrant is exercisable to purchase for $11.50 one share of Class A Common Stock.

Of the periods on or prior to February 7, 2017, is solely thatnet proceeds of the Predecessor, Rivercrest Royalties, LLC,TGR’s IPO and does not include the results of the Partnership as a whole. However, unless otherwise indicated, the reserve data presented in this report is with the respect to all the assets that were contributed to us by the Contributing Parties in connection with our IPO. The mineral and royalty interests underlying the oil, natural gas and NGL production revenues of the Predecessor represented approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

As of December 31, 2017, we owned mineral and royalty interests in approximately 3.7 million gross acres and overriding royalty interests in approximately 2 million gross acres, with approximately 35% of our aggregate acres located in the Permian Basin. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2017, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 20 states and in nearly every major onshore basin across the continental United States and include ownership in over 50,000 gross producing wells, including over 30,000 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.

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As of December 31, 2017, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 20,954 MBoe (49.2% liquids, consisting of 72.4% oil and 27.6% NGLs) based on the reserve report prepared by Ryder Scott. Of these reserves, 73.1% were classified as PDP reserves, 0.4% were classified as PDNP reserves and 26.5% were classified as PUD 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 8.8% during the initial five-years. PUD reserves included in this estimate are from 750 gross proved undeveloped locations.

As of December 31, 2016, the estimated proved oil, natural gas and NGL reserves attributable solely to our Predecessor’s interests in its underlying acreage were 2,311 MBoe (48.5% liquids, consisting of 79.0% oil and 21.0% NGLs) based on the reserve report prepared by Ryder Scott. Of these reserves, 58.9% were classified as PDP reserves, 1.5% were classified as PDNP reserves and 39.6% were classified as PUD reserves. The properties underlying our Predecessor’s mineral and royalty interests typically had low estimated decline rates. Our Predecessor’s PDP reserves had an average estimated yearly decline rate of 9.6% during the initial five-years. PUD reserves included in this estimate were from 355 gross proved undeveloped locations.

Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oilthe Private Placement Warrants, $236,900,000, including $8,050,000 of deferred underwriting discounts and natural gas production,commissions, has been deposited into a U.S. based trust account at J.P. Morgan Chase Bank, N.A., with Continental Stock Transfer & Trust Company acting as well astrustee.

Under the saleterms of NGLs that are extractedTGR’s governing documents, TGR has until May 8, 2023 (15 months from natural gas during processing. Asthe closing of December 31, 2017, there were over 700 operators actively producing on our acreage, with our top ten operators (Occidental Permian Ltd., XTO Energy, Inc., Aera Energy LLC (a joint venturethe TGR IPO) to complete its initial business combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

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Our Oil and ExxonMobil Corporation), Devon Energy Production Company, LP, Hess Corporation, Chesapeake Operating, Inc., Protégé Energy III LLC, Jonah Energy LLC, Energen Resources Corporation and SEM Operating) together accounting for approximately 45.03% of our combined net income. As of December 31, 2017, there were 19 rigs operating on our acreage compared to 15 rigs on our acreage as of December 29, 2016. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

For the period from February 8, 2017 to December 31, 2017, our revenues were generated 58% from oil sales, 28% from natural gas sales, 11% from NGL sales and 3% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined year ended December 31, 2017, the revenues were generated 58% from oil sales, 28% from natural gas sales, 11% from NGL sales and 3% from other sales. For the year ended December 31, 2016, our Predecessor’s revenues were derived 60% from oil sales, 30% from natural gas sales and 10% from NGL sales.

OurGas 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‑yearthree-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‑freecost-free percentage (usually ranging from 20‑25%20-25%) of production or revenue from production. The lease can be extended beyond the initial term with continuous drilling, production or other operating activities. When production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to the mineral owner who can then lease the exploration and development rights to another party. We also own royalty interests that have been carved out of mineral interests and are known as nonparticipating royalty interests. Nonparticipating royalty interests are typically perpetual and have rights similar to mineral interests, including the right to a cost‑freecost-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. As of December 31, 2017, over 98% of the acreage subject to our mineral and nonparticipating royalty interests

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was leased. 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‑freecost-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, 2022, we owned mineral and royalty interests in approximately 11.5 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of December 31, 2022, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners (including approximately 100% of our overriding royalty interests), and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 124,000 gross wells, including over 48,000 wells in the Permian Basin. The geographic breadth of our assets gives us exposure to potential production and reserves from new and existing plays. 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, 2022, the estimated proved oil, natural gas and NGL reserves attributable to our interests in our underlying acreage were 46,459 MBoe (42.5% liquids, consisting of 62.6% oil and 37.4% NGLs) based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”). All of our reserves were classified as PDP reserves. 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 12.4% during the initial five-years.

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Our revenues are derived from royalty payments we receive from the operators of our properties based on the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. As of December 31, 2022, there were approximately 1,500 operators actively producing on our acreage, with our top ten operators (SWN Production Company LLC, Chesapeake Operating, Inc., EOG Resources, Inc., Continental Resources, Inc., Pioneer Natural Resources Company, Chevron USA, Inc., Hess Bakken Corporation, XTO Energy, Inc., Aethon Energy Operating, and Occidental Petroleum Corporation) together accounting for approximately 40.3% of our revenues.

During the years ended December 31, 2022, 2021 and 2020, payments we received from our top purchaser accounted for approximately 11.3%, 6.0% and 7.1%, respectively, of our revenues. We do not believe that the loss of any individual purchaser would have a material adverse effect on us due to the high number of purchasers actively producing on our acreage. As of December 31, 2022, there were 92 rigs (representing 12.1% market share of all rigs drilling in the continental United States as of such time) operating on our acreage compared to 61 rigs operating on our acreage as of December 31, 2021. The overall increase in rig count is primarily attributable to improvements in the oil and natural gas market as a result of improved oil and natural gas prices and overall supply and demand imbalances caused by Russia’s invasion of Ukraine, OPEC supply restraint and supply chain disruptions that limited U.S. production growth. 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, 2022, our oil, natural gas and NGL revenues were generated 46% from oil sales, 44% from natural gas sales and 10% 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 third parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest. We will also seek to utilize TGR to further our primary business objective. We intend to accomplish this objective by executing the following strategies:

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●		Acquire additional mineral and royalty interests from third parties and leverage our relationships with our Sponsors, the Contributing Parties and TGR 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, on December 15, 2022, we completed the Hatch Acquisition, further enhancing our asset base.

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

We may also seek to pursue an acquisition opportunity jointly with TGR. We may co-invest with TGR in the target business at the time of its initial business combination, or we may seek to acquire assets from the target business or other equity or equity-linked securities from the business or TGR. In addition, we may seek to acquire a royalty interest in the underlying assets of the target business at the time of its initial business combination. We may elect to take these or other actions to, among other reasons, (i) increase the amount of committed capital available to consummate TGR’s initial business combination, including in the event that the market for issuing securities to unaffiliated investors in a private investment in public equity, or PIPE, is

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challenging or difficult to consummate at the desired issue price, (ii) reduce dilution in connection with raising equity capital for TGR’s initial business combination, and (iii) demonstrate synergies among KRP and the target business, especially in light of our knowledge and expertise in the oil and gas sector, our royalty interest ownership and the industry network of our management team and board of directors. However, we have no obligation to make any such investment or acquisition.

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Acquire additional mineral and royalty interests from our Sponsors and the Contributing Parties. The Contributing Parties, including affiliates of our Sponsors, continue to own significant mineral and royalty interests in oil and gas properties. We believe our Sponsors and the Contributing Parties view our partnership as part of their growth strategy. In addition, we believe their direct or indirect ownership in us will incentivize them to offer us additional mineral and royalty interests from their existing asset portfolios in the future. In connection with our IPO, certain of theThe Contributing Parties granted us a right of first offer for a period of three years with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale. These mineral and royalty interests include ownership in over 4,000 gross producing wells in 10 states. Such Contributing Parties, however, have no obligation to sell any additional assets to us or to accept any offer that we may make for suchany additional assets, and we may decide not to acquire such additional assets even if such Contributing Parties offer them to us. Please read “Item 13. Certain Relationships and Related Party Transactions,, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

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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.

Our Sponsors and their affiliates have extensive experience in identifying, evaluating and completing strategic acquisitions of mineral and royalty interests. In connection with the closing of our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with certain entities controlled by affiliates of our Sponsors, pursuant to which they will identify, evaluate and recommend to us acquisition opportunities and negotiate the terms of such acquisitions. We believe that these individuals’ knowledge of the oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions will provide us opportunities to grow through strategic and accretive acquisitions that complement or expand our asset portfolio.

We also may have opportunities to acquire mineral or royalty interests from third parties jointly with our Sponsors and the Contributing Parties. In connection with our IPO and pursuant to the contribution agreement that we entered into 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

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to third‑party acquisition opportunities we might not otherwise be in a position to pursue. Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Agreements and Transactions with Affiliates in Connection with our Initial Public Offering—Contribution Agreement.”

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Benefit from reserve, production and cash flow growth through organic production growth and development of our mineral and royalty interests to grow distributions.interests. Our assets consist of diversified mineral and royalty interests. The majorityAs of our assets, 73.5%December 31, 2022, 54% and 52% of our well count and 46.5% of our gross aggregate acreage, respectively, are fromlocated in the Permian Basin Eagle Ford, Terryville/Cotton Valley/Haynesville and the Bakken/Williston Basin,Mid-Continent, which are some ofamong the most active areas in the country. Over the long term, we expect working interest owners will continue to develop our acreage through infill drilling, horizontal drilling, hydraulic fracturing, recompletions and secondary and tertiary recovery methods. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post-production expenses and taxes. We are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. As such, we benefit from the continued development of the properties we own a mineral or royalty interest in without the need for investment of additional capital by us, which we expect to increase our distributions over time.

us.

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Maintain a conservative capital structure and prudently manage our business for the long term. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. The limited liability company agreement of our General Partner contains provisions that prohibit certain actions without a supermajority vote of at least 662/3% of the members of the General Partner’s Board of Directors (the “Board of Directors”). Among the actions requiring a supermajority vote are the incurrence of borrowings in excess of 2.5 times our Debt to EBITDAX Ratio (as defined in our General Partner’s limited liability company agreement) for the preceding four quarters and the issuance of any partnership interests that rank senior in right of distributions or liquidation to our common units. Please read “The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner.” In connection with our IPO, we entered into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). We believe that this liquidity, along with internally generated cash from operations and access to the public 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.

We have a $350.0 million secured revolving credit facility with an elected commitment amount feature permitting aggregate commitments under the secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base, which is currently $350.0 million, and the satisfaction of certain conditions, including the election of existing lenders to increase commitments or the procurement of additional commitments from new lenders. During the year ended December 31, 2022, the Board of Directors approved the repayment of $46.6 million in outstanding borrowings under our secured revolving credit facility, which reduced our cash available for distribution on common units. Of the $46.6 million, $13.1 million was approved in connection with the fourth quarter distribution and will be repaid in the first quarter of 2023. With respect to future quarters, the Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility. 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.

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Competitive Strengths

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

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Significant diversified portfolio of mineral and royalty interests in mature producing basins and exposure to undeveloped opportunities. We have a diversified, low decline asset base with exposure to high-quality conventional and unconventional plays. As of December 31, 2017,2022, we owned mineral and royalty interests in approximately 3.711.5 million gross acres and overriding royalty interests in approximately 24.7 million gross acres, with approximately 35%52% of our aggregate acres located in the Permian Basin and Mid-Continent, and as of December 31, 2022, over 98%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 20,95446,459 MBoe (49.2%(42.5% liquids, consisting of 72.4%26.6% oil and 27.6%15.9% NGLs) based on the reserve report prepared by Ryder Scott. Of theseAll of our reserves 73.1% were classified as PDP reserves, 0.4% were classified as PDNP reserves and 26.5% were classified as PUD reserves. PUD reserves included in this estimate are from 750 gross proved undeveloped locations. As of December 31, 2016, the estimated proved oil, natural gas and NGL reserves attributable to our Predecessor’s interests in our underlying acreage were 2,311 MBoe (48.5% liquids, consisting of 79.0% oil and 21.0% NGLs) based on the reserve report prepared by Ryder Scott. Of these reserves, 58.9% were classified as PDP reserves, 1.5% were classified as PDNP reserves and 39.6% were classified as PUD reserves. PUD reserves included in this estimate are from 355 gross proved

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undeveloped locations. 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 interestinterests in multiple resource plays. Our mineral and royalty interests are located in 2028 states and in nearly every major onshore basin across the continental United States and include ownership in over 50,000124,000 gross producing wells, including over 30,00048,000 wells in the Permian Basin.

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Financial flexibility to fund expansion. We believe that our conservative capital structure will permit us to maintain financial flexibility tothat 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. In connection with our IPO, we entered into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). As of December 31, 2017, we had $30.8 million outstanding under the facility.Partner as discussed above. Please read “Management’s“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—New Revolving Credit Agreement”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 the public 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 30 years of oil and gas experience. Our management team and Board of Directors, which includes our founders, have a long history of buying mineral and royalty interests in high‑qualityhigh-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‑qualityhigh-quality producing acreage.

Our Properties

Material Basins and Producing Regions

The following is an overview of the U.S.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 westWest 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

18

Table of Contents

consists of mature legacy onshore oil and liquids‑richliquids-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‑richliquids-rich reserves make the Permian Basin one of the most prolific oil‑producingoil-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. Mid-Continent. The Mid‑ContinentMid-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

13

Table of Contents

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‑WoodfordCana-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 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.

·

●

Barnett Shale/Fort Worth Basin. The Fort Worth Basin is a major petroleum producing geological system that is primarily located in north central Texas and southwestern Oklahoma. This area is best known for the Barnett Shale, which was one of the first shale plays to utilize horizontal drilling and hydraulic fracturing and is one of the most productive sources of shale gas along with the Marcellus and Haynesville Shales. In addition to the Barnett Shale, this area is also known for the Marble Falls, Mississippi Lime, Bend Conglomerate and Caddo plays.

·

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.

·

●

San Juan Basin. The San Juan Basin is located in the Four Corners region of the southwestern United States, stretching over 4,600 square miles and encompassing much of northwestern New Mexico, southwestern Colorado and parts of Arizona and Utah. Most gas production in the basin comes from the Fruitland Coalbed Methane Play, with the remainder derived from the Mesaverde and Dakota tight gas plays. The San Juan Basin is the most productive coalbed methane basin in North America.

·

Onshore California. The majority of our mineral and royalty interests in California are in the Ventura Basin. The Ventura Basin has been active since the early 1900s and is one of the largest oil fields in California. The Ventura Basin contains multiple stacked formations throughout its depths, and a considerable inventory of existing re‑development opportunities, as well as new play discovery potential.

·

DJ Basin/Rockies/Niobrara. The Denver‑JulesburgDenver-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.

·

Illinois Basin. The Illinois Basin extends across most of Illinois, Indiana, Kentucky and parts of Tennessee. The Illinois Basin is a mature area dominated by conventional oil production with some coalbed methane production. The Bridgeport, Cypress, Aux Vasses, Ste. Genevieve, Ullin, Fort Payne and New Albany are some of the formations with a current commercial focus in the Illinois Basin.

·

Other. Our other assets are primarily located in the Western Gulf (onshore) Basin and the Louisiana‑Mississippi Salt Basins. The Western Gulf region ranges from South Texas through southeastern

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Table of Contents

Louisiana and includes a variety of conventional and unconventional plays. The Louisiana‑Mississippi Salt Basins range from northern Louisiana and southern Arkansas through south central Mississippi, southern Alabama and the Florida Panhandle.

The following tables present information about our and our Predecessor’s mineral and royalty interest acreage, production, and well count and production by basin.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, 2022

​

​

Gross

​

Net

 

Percent

Basin or Producing Region

​

Acres

​

Acres

​

Leased

Permian Basin (1)

​

2,820,453

​

20,488

​

99.1

%  

Mid‑Continent

 

3,174,297

​

26,495

 

99.7

%  

Terryville/Cotton Valley/Haynesville

 

1,301,662

​

6,725

 

99.6

%  

Appalachian Basin (2)

​

434,116

​

16,968

​

99.8

%  

Eagle Ford

 

476,193

​

5,059

 

96.8

%  

Barnett Shale/Fort Worth Basin

 

316,408

​

3,548

 

99.1

%  

Bakken/Williston Basin (3)

 

1,214,446

​

3,132

 

99.9

%  

San Juan Basin

 

85,604

​

159

 

99.2

%  

Onshore California

 

67,139

​

286

 

95.7

%  

DJ Basin/Rockies/Niobrara

 

46,398

​

680

 

96.1

%  

Illinois Basin

 

11,163

​

97

 

100.0

%  

Other Western (onshore) Gulf Basin

 

614,310

​

4,247

 

98.0

%  

Other TX/LA/MS Salt Basin

 

308,850

​

3,841

 

95.3

%  

Other

 

677,084

​

3,305

 

99.1

%  

Total (4)

 

11,548,123

 

95,030

 

99.1

%

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

Gross

 

Net

 

Percent

Basin or Producing Region

 

Acres

 

Acres

 

Leased

Permian Basin (1)

 

1,764,954

 

15,741

 

99

%  

Mid‑Continent

 

408,084

 

9,438

 

98

%  

Terryville/Cotton Valley/Haynesville

 

261,762

 

2,347

 

98

%  

Eagle Ford

 

182,102

 

1,968

 

97

%  

Barnett Shale/Fort Worth Basin (2)

 

216,367

 

2,335

 

99

%  

Bakken/Williston Basin (3)

 

86,544

 

1,485

 

99

%  

San Juan Basin

 

28,852

 

141

 

98

%  

Onshore California

 

8,626

 

35

 

68

%  

DJ Basin/Rockies/Niobrara

 

3,967

 

97

 

59

%  

Illinois Basin

 

6,351

 

83

 

100

%  

Other Western (onshore) Gulf Basin

 

539,625

 

3,754

 

98

%  

Other TX/LA/MS Salt Basin

 

144,186

 

1,476

 

91

%  

Other

 

93,857

 

671

 

92

%  

Total (4)

 

3,745,277

 

39,571

 

98

%

(1)

(1)

Includes mineral interests in approximately 740,2441,375,238 gross (6,723(8,872 net) acres in the Wolfcamp/Bone Spring.

(2)

(2)

Includes mineral interests in approximately 198,229209,340 gross (1,762(5,637 net) acres in the Barnett Shale.

Marcellus/Utica.

(3)

(3)

Includes mineral interests in approximately 78,3441,103,904 gross (1,423(3,013 net) acres in the Bakken/Three Forks.

(4)

(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, 2022

​

​

Gross

​

Net

​

Percent

Basin or Producing Region

​

Acres

​

Acres

​

Producing

Permian Basin (1)

​

309,938

​

3,960

​

100.0

%

Mid‑Continent

 

2,195,061

​

17,815

 

99.1

%

Terryville/Cotton Valley/Haynesville

 

127,245

​

1,194

 

99.6

%

Appalachian Basin (2)

​

307,238

​

6,235

​

100.0

%  

Eagle Ford

 

147,955

​

1,671

 

100.0

%

Barnett Shale/Fort Worth Basin

 

76,755

​

593

 

100.0

%

Bakken/Williston Basin (3)

 

425,631

​

3,006

 

100.0

%

San Juan Basin

 

98,633

​

1,313

 

99.0

%

Onshore California

 

10,668

​

22

 

100.0

%

DJ Basin/Rockies/Niobrara

 

27,754

​

356

 

100.0

%

Illinois Basin

 

16,848

​

1,080

 

100.0

%

Other Western (onshore) Gulf Basin

 

89,209

​

1,215

 

100.0

%

Other TX/LA/MS Salt Basin

 

45,502

​

1,443

 

99.9

%

Other

 

814,387

​

15,544

 

100.0

%

Total (4)

 

4,692,824

 

55,447

 

99.6

%

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

Gross

 

Net

 

Percent

Basin or Producing Region

 

Acres

 

Acres

 

Producing

Permian Basin (1)

 

232,723

    

2,814

  

100

%

Mid‑Continent

 

1,256,382

 

8,942

 

98

%

Terryville/Cotton Valley/Haynesville

 

41,812

 

779

 

99

%

Eagle Ford

 

72,970

 

597

 

100

%

Barnett Shale/Fort Worth Basin (2)

 

54,888

 

445

 

100

%

Bakken/Williston Basin (3)

 

31,554

 

1,879

 

100

%

San Juan Basin

 

47,233

 

908

 

98

%

Onshore California

 

9,626

 

13

 

100

%

DJ Basin/Rockies/Niobrara

 

3,182

 

102

 

54

%

Illinois Basin

 

13,304

 

1,032

 

100

%

Other Western (onshore) Gulf Basin

 

72,870

 

1,087

 

100

%

Other TX/LA/MS Salt Basin

 

22,616

 

1,140

 

100

%

Other

 

147,623

 

12,027

 

100

%

Total (4)

 

2,006,783

 

31,765

 

99

%

(1)

(1)

Includes overriding royalty interests in approximately 149,173199,721 gross (1,614(2,004 net) acres in the Wolfcamp/Bone Spring.

(2)

(2)

Includes overriding royalty interests in approximately 50,217254,348 gross (389(4,852 net) acres in the Barnett Shale.

Marcellus/Utica.

(3)

(3)

Includes overriding royalty interests in approximately 29,813411,439 gross (1,792(2,909 net) acres in the Bakken/Three Forks.

(4)

(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 the we had mineral or royalty interest:

​

​

​

Basin or Producing Region

​

December 31, 20172022

Permian Basin

​

30,20948,407

Mid‑Continent

 

3,62619,205

Terryville/Cotton Valley/Haynesville

 

5,13816,175

Appalachian Basin

3,871

Eagle Ford

 

1,2674,088

Barnett Shale/Fort Worth Basin

 

2,2985,911

Bakken/Williston Basin

 

4995,278

San Juan Basin

 

5811,875

Onshore California

 

757975

DJ Basin/Rockies/Niobrara

 

3,318

Illinois Basin

18412,540

Other

 

2,5876,652

Total

 

50,464124,977

​

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Table of Contents

Production

We designate wells as either conventional or unconventional by reviewing the basin, field, and hole direction of each well, as well as the start date of the wells. In estimating the percentage of conventional wells that are subject to enhanced oil recovery (“EOR”), we compare forecasted production decline against historical production decline, as well as publicly available information related to injection volumes, operator information, unit size, well count and location. We estimate that approximately 18% of our total production as of December 31, 2022 is attributable to conventional assets including certain EOR projects. We believe this conventional production provides a base level of production stability that helps facilitate overall organic production growth as new unconventional wells come online.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Estimated Proved Reserves

Our and our Predecessor’s historical reserve estimates as of December 31, 20172022, 2021 and 20162020 were prepared by Ryder Scott, an independent third-party petroleum engineering firm. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Within Ryder Scott, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve report incorporated herein is Mr. Scott Wilson, who has been practicing petroleum-engineering consulting at Ryder Scott since 2000. Mr. Wilson is a registered Professional Engineer in the States of Alaska, Colorado, Texas and Wyoming.

16

Table of Contents

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 U.S.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, 20172022 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 3033 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 changeschanges; and all new proved undeveloped reserves additions;

·

●

verification of property ownership by our land department; and

department.

22

·

no employee’s compensation is tied to the amount of reserves booked.

Table of Contents

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. 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, 20172022, 2021 and 20162020 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‑basedperformance-based methods, (2) volumetric‑basedvolumetric-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‑producingnon-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

17

Table of Contents

engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and production cost data.

Summary of Estimated Proved Reserves

Estimates of reserves as of December 31, 20172022, 2021 and 20162020 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, 20172022, 2021 and 2016,2020, 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 $51.34$93.67, $66.56 and $42.75$39.57 per Bbl for oil and $2.98$6.36, $3.60 and $2.49$1.99 per MMBtu for natural gas at December 31, 20172022, 2021 and 2016,2020, 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 and our Predecessor’s estimated proved developed oil and natural gas reserves:

​

​

​

​

​

​

​

​

​

​

​

​

December 31, 

​

​

​

2022

​

​

2021

​

​

2020

​

Estimated proved developed reserves:

​

​

​

​

​

​

​

​

​

Oil (MBbls)

​

12,355

​

 

12,511

​

 

12,294

​

Natural gas (MMcf)

​

160,298

​

 

157,764

​

 

144,233

​

Natural gas liquids (MBbls)

​

7,388

​

 

6,669

​

 

6,085

​

Total (MBoe)(6:1) (1)

​

46,459

​

 

45,474

​

 

42,418

​

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

 

December 31, 

 

 

December 31, 

 

 

December 31, 

 

 

 

2017

 

 

2016

 

 

2016

 

Estimated proved developed reserves:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

5,284

 

 

4,879

 

 

482

 

Natural gas (MMcf)

 

47,500

 

 

35,172

 

 

4,586

 

Natural gas liquids (MBbls)

 

2,202

 

 

1,416

 

 

150

 

Total (MBoe)(6:1) (1)

 

15,403

 

 

12,157

 

 

1,396

 

Estimated proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

2,179

 

 

2,331

 

 

404

 

Natural gas (MMcf)

 

16,416

 

 

15,219

 

 

2,554

 

Natural gas liquids (MBbls)

 

636

 

 

566

 

 

85

 

Total (MBoe)(6:1) (1)

 

5,551

 

 

5,434

 

 

915

 

Estimated proved reserves:

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

7,463

 

 

7,210

 

 

886

 

Natural gas (MMcf)

 

63,916

 

 

50,391

 

 

7,140

 

Natural gas liquids (MBbls)

 

2,838

 

 

1,982

 

 

235

 

Total (MBoe)(6:1) (1)

 

20,954

 

 

17,591

 

 

2,311

 

Percent proved developed

 

74

%

 

69

%

 

60

%

(1)

(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, 20172022, 2021 and 20162020 was used, the conversion factor would be approximately 17.214.7 Mcf per Bbl of oil. In this Annual Report, we supplementally provide “value-equivalent” production information or volumes presented on an oil-equivalent basis using a conversion factor of 20oil, 18.5 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. We are providing this measure supplementally because we believe this conversion factor represents an estimation of value equivalence over time and better correlates with the respective contributionBbl of oil and natural gas to our revenues. We use the 20-to-1 conversion factor as we assess our business, including analysis of our financial and production performance, strategic decisions to purchase additional properties and budgeting. We do not adjust the 20-to-1 ratio to reflect current pricing, because the significant volatility in the conversion ratio makes it difficult for us to compare results across periods. By reviewing our aggregate production on a constant 20-to-1 basis, which removes the variability of price fluctuations but generally approximates price equivalence over recent periods, we are able to compare production data from period to period as well as the relative contribution19.9 Mcf per Bbl of oil, and natural gas to our revenues. The 20-to-1 conversion factor approximates the mean ratio of the price of WTI oil to the price of Henry

respectively.

1823

Table of Contents

Hub natural gas from January 3, 2006 to December 31, 2017, as reported by the U.S. Energy Information Administration (“EIA”). During this period, the ratio of the price of oil to the price of natural gas ranged from 5.64 to 56.91. The mean ratios of the price of oil to the price of natural gas were 17.10 and 17.72 for the years ended December 31, 2017 and 2016, respectively. Due to the variability of the prices of oil and natural gas, there is no standard conversion ratio for value equivalence, and the 20-to-1 ratio presented here may not accurately reflect the ratio of oil prices to natural gas prices for a given period.

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 “Risk“Item 1A. Risk Factors.”

Additional information regarding our estimated proved reserves can be found in the reserve report as of December 31, 2017,2022, which is included as an exhibit to this report.Annual Report.

Estimated Proved Undeveloped Reserves

As of DecemberPrior to March 31, 2017,2020, we included our PUD reserves totaled 2,179 MBbls of oil, 16,416 MMcf of natural gas and 636 MBbls of NGLs, for ain our total of 5,552 MBoe. As of December 31, 2016, our PUD reserves totaled 2,331 MBbls of oil, 15,219 MMcf of natural gas and 566 MBbls of NGLs, for a total of 5,434 MBoe. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

As of December 31, 2016, our Predecessor’s PUD reserves totaled 404 MBbls of oil, 2,554 MMcf of natural gas and 85 MBbls of NGLs, for a total of 915 MBoe. PUD reserves were converted from undeveloped to developed as the applicable wells began production.

The following tables summarize our changes in PUD reserves (in MBoe):

 

 

 

 

 

 

 

 

 

Partnership

 

Predecessor

 

 

December 31, 2017

 

December 31, 2016

 

December 31, 2016

Beginning balance

 

5,434

 

5,224

 

892

Acquisitions of reserves

 

606

 

 4

 

 —

Extensions and discoveries

 

973

 

1,227

 

282

Revisions of previous estimates

 

(240)

 

84

 

(55)

Transfers to estimated proved developed

 

(1,222)

 

(1,105)

 

(204)

Ending balance

 

5,551

 

5,434

 

915

Our PUDestimated proved reserves as of December 31, 2017 were from 402 vertical wellseach year-end. After that time, we determined that we did not have reasonable certainty as to the timing of the development of PUD reserves and, 348 horizontal wells. Astherefore, as of December 31, 2017, all of our PUD drilling locations are scheduledyear-end 2020, we transitioned to be drilled prior to December 31, 2022. As of December 31, 2017, approximately 0.4% of our total proved reserves were classified as100% proved developed non-producing.reserves. Historically, our net organic growth has held PDP rates relatively flat to increasing over time, which we believe supports our inventory of drilling locations.

Changes in PUDs that occurred from December 31, 2016 through December 31, 2017 were primarily due to:

·

the acquisition of an additional 606 MBoe through five diverse acquisition for approximately $29.3 million of royalty interests across ten states including Texas, Oklahoma, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas.

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·

additions of approximately 973 MBoe, as well locations were converted from probable to proved undeveloped, as offset drilling proved our acreage and projected drilling dates fell within five years of the effective date of the report.

·

the conversion of approximately 1,222 MBoe PUD reserves into proved developed reserves as 349 locations (143 horizontal and 206 vertical) were drilled; and

·

positive revisions of approximately 204 MBoe in PUDs primarily due to modifying PUD drill schedule timing to match current drilling rates and operator projections.

Of the 349 locations that were drilled in 2017, 109 locations were specifically identified by management in its 2016 reserve estimates. The remaining 240 locations were not specifically identified in managements proved undeveloped forecast, but were included in its reserve estimates as being scheduled to be drilled in 2017. These locations include infill drilling in multi‑well units and in some cases, waterflood response, CO2 response, well stimulations, flood conformance improvements and pump upgrades. Management’s forecasts for its multi‑well units are based on a multi‑factor analysis that includes reviewing information from state regulatory agencies and other third‑party sources, including publicly disclosed data by the operators, as well as management’s experience with the units.

Oil, Natural Gas and NGL Production and Pricing

Production and Price History

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

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Production Data:

​

​

​

​

​

​

​

​

​

Oil and condensate (Bbls)

​

​

1,425,842

​

​

1,343,771

​

​

1,409,163

Natural gas (Mcf)

​

​

20,310,991

​

​

19,085,400

​

​

17,891,384

Natural gas liquids (Bbls)

​

​

746,865

​

​

714,494

​

​

681,575

Total (Boe)(6:1) (1)

​

​

5,557,872

​

​

5,239,165

​

​

5,072,635

Average daily production (Boe/d)(6:1)

​

​

15,025

​

​

14,354

​

​

13,860

Average Realized Prices:

​

​

​

​

​

​

​

​

​

Oil and condensate (per Bbl)

​

$

91.74

​

$

64.86

​

$

36.98

Natural gas (per Mcf)

​

$

6.04

​

$

3.51

​

$

1.79

Natural gas liquids (per Bbl)

​

$

38.19

​

$

29.33

​

$

12.39

Average Unit Cost per Boe (6:1)

​

​

​

​

​

​

​

​

​

Production and ad valorem taxes

​

$

2.92

​

$

2.00

​

$

1.26

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

Predecessor

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31,

 

 

2017

 

2017

 

2016

 

2015

Production Data:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (Bbls)

 

 

379,182

 

 

3,696

 

 

55,587

 

 

59,321

Natural gas (Mcf)

 

 

3,184,861

 

 

32,961

 

 

496,778

 

 

548,386

Natural gas liquids (Bbls)

 

 

157,177

 

 

1,220

 

 

22,360

 

 

22,351

Total (Boe)(6:1) (1)

 

 

1,067,169

 

 

10,410

 

 

160,743

 

 

173,070

Average daily production (Boe/d)(6:1)

 

 

3,264

 

 

274

 

 

440

 

 

474

Total (Boe)(20:1) (2)

 

 

695,602

 

 

6,564

 

 

102,786

 

 

109,091

Average daily production (Boe/d)(20:1)

 

 

2,127

 

 

173

 

 

282

 

 

299

Average Realized Prices:

 

 

 

 

 

 

 

 

 

 

 

 

Oil and condensate (per Bbl)

 

$

47.08

 

$

47.04

 

$

38.69

 

$

49.79

Natural gas (per Mcf)

 

$

2.74

 

$

3.47

 

$

2.21

 

$

2.44

Natural gas liquids (per Bbl)

 

$

21.50

 

$

24.61

 

$

15.99

 

$

17.56

Average Unit Cost per Boe (6:1)

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

$

2.30

 

$

1.89

 

$

1.74

 

$

2.47

(1)

(1)

“Btu‑equivalent”Btu-equivalent” production volumes are presented on an oil‑equivalentoil-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.

(2)

“Value‑equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business. For a discussion of the 20-to-1 conversion factor, please read footnote 1 to the Summary of Estimated Proved Reserves table under “Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves.”

​

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, 2017, the Partnership owned mineral or royalty interests in

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over 50,000 productive wells, which consisted of over 40,000 oil wells and over 10,000 natural gas wells. As of December 31, 2016, the Contributing Parties2022, we owned mineral or royalty interests in over 48,000124,000 gross productive wells, which consisted of over 39,00090,000 oil wells and over 8,00034,000 natural gas wells. As

24

Table of December 31, 2016, our Predecessor owned mineral or royalty interests in over 13,000 productive wells which consisted of over 10,000 oil wells and over 2,000 natural gas wells.Contents

Acreage

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, 2017:2022:

​

​

​

​

​

​

​

​

​

Developed

​

Undeveloped

​

Total

State

 

Acreage

​

Acreage

​

Acreage

Texas

  

5,053,702

​

60,733

​

5,114,435

Oklahoma

 

2,002,221

 

7,374

 

2,009,595

North Dakota

 

1,097,983

 

1,000

 

1,098,983

Wyoming

 

301,330

 

771

 

302,101

Kansas

 

608,320

 

2,001

 

610,321

Louisiana

 

618,711

 

1,045

 

619,756

Arkansas

 

407,848

 

1,218

 

409,066

Montana

 

165,955

 

5,059

 

171,014

New Mexico

 

211,391

 

3,146

 

214,537

Utah

​

144,053

​

—

​

144,053

Other

 

836,591

​

17,671

 

854,262

Total

 

11,448,105

(1)

100,018

(2)

11,548,123

 

 

 

 

 

 

 

 

 

Developed

 

Undeveloped

 

Total

State

 

Acreage

 

Acreage

 

Acreage

Texas

  

2,985,247

 

41,363

 

3,026,610

Oklahoma

 

101,081

 

6,129

 

107,210

Louisiana

 

45,679

 

589

 

46,268

New Mexico

 

77,443

 

1,005

 

78,448

North Dakota

 

84,547

 

720

 

85,267

Colorado

 

27,640

 

1,449

 

29,089

Wyoming

 

2,562

 

640

 

3,202

Kansas

 

83,428

 

1,880

 

85,308

Montana

 

2,640

 

4,681

 

7,321

Other

 

261,684

 

14,870

 

276,554

Total

 

3,671,951

(1)

73,326

(2)

3,745,277

(1)

(1)

Reflects mineral interests in approximately 3,671,95111,448,105 total gross (36,932(85,571 net) developed acres.

(2)

(2)

Reflects mineral interests in approximately 73,326100,018 total gross (2,639(9,459 net) undeveloped acres.

ORRIs

The following table sets forth information relating to our acreage for our ORRIs at December 31, 2017:2022:

​

​

​

​

​

​

​

​

​

Developed

​

Undeveloped

​

Total

State

​

Acreage

​

Acreage

​

Acreage

Texas

    

1,395,641

    

680

    

1,396,321

Oklahoma

 

1,336,042

 

19,000

 

1,355,042

North Dakota

 

419,177

 

—

 

419,177

Wyoming

 

350,846

 

—

 

350,846

Utah

​

235,432

​

—

​

235,432

Colorado

 

192,402

 

—

 

192,402

Pennsylvania

 

124,298

 

—

 

124,298

West Virginia

 

116,938

 

—

 

116,938

Louisiana

 

119,062

 

450

 

119,512

New Mexico

 

110,796

 

960

 

111,756

Other

 

271,100

 

—

 

271,100

Total

 

4,671,734

(1)

21,090

(2)

4,692,824

 

 

 

 

 

 

 

 

 

Developed

 

Undeveloped

 

Total

State

 

Acreage

 

Acreage

 

Acreage

Texas

    

1,155,795

    

680

    

1,156,475

Oklahoma

 

491,199

 

19,000

 

510,199

Louisiana

 

34,948

 

511

 

35,459

New Mexico

 

45,610

 

960

 

46,570

North Dakota

 

31,554

 

 —

 

31,554

Colorado

 

20,577

 

1,454

 

22,031

Wyoming

 

72,411

 

 —

 

72,411

Kansas

 

11,430

 

 —

 

11,430

Montana

 

 —

 

 —

 

 —

Other

 

119,927

 

727

 

120,654

Total

 

1,983,451

(1)

23,332

(2)

2,006,783

(1)

(1)

Reflects ORRIs in approximately 1,983,4504,671,709 total gross (31,562(55,335 net) developed acres.

(2)

(2)

Reflects ORRIs in approximately 23,33221,115 total gross (202(111 net) undeveloped acres.

Drilling Results

As of December 31, 2017 and 2016, the operators of our properties had over 50,000 and 48,000 gross productive development wells, respectively, on the acreage underlying our mineral and royalty interests. As of December 31, 2016, our Predecessor owned mineral or royalty interests in over 13,000 productive wells. 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.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.

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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

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competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These companies may also have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months, while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for the operators of our properties in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties.

Oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases the cost of doing business.

Environmental Matters

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the Environmental Protection Agency (“EPA”) and Department of the Interior (“DOI”), issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non‑compliance.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 suchcertain 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.

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Non‑HazardousNon-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‑hazardousnon-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.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 crude oil and natural gas wastes. 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. Pursuant to a Consent Decree with a coalition of environmental group that filed suit in May2016, EPA must review regulations governing the disposal of certain oil and natural gas drilling wastes under RCRA by March 2019 and either determine revisions to the exemption are not necessary or undertake rulemaking to be completed by July 2021. 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 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 has issued a final rule outlining its position on the federal jurisdictional reach over waters of the United States, in September 2015, but this rule has been stayed nationwidewas promptly challenged in courts and was enjoined by the U.S. Sixth Circuit Court of Appeals until ongoing litigation regarding the rule is settled. judicial action in some states.

In January 2018, the U.S. Supreme Court issued a decision determining that only U.S. district courts have jurisdiction to hear challenges to that rule. As a result of that ruling, the Sixth Circuit stay is expected to be withdrawn, although stays issued by district courts in several states will remain in effect. Additionally, on February 28, 2017, President Trump issued an executive order directingOctober 2019, the EPA and the U.S.United States Army Corps of Engineers to reviewissued a final rule that repealed the 2015 regulations and consistent with applicable law, to initiate rulemaking to rescind or revisereinstated the rule. The

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Tableagencies’ narrower pre-2015 scope of Contents

federal Clean Water Act jurisdiction. In April 2020, the EPA and the U.S.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

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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 noticestandard comment period, the EPA and Army Corp of intent to review and rescind or revise the rule on March 6, 2017. In February 2018, the agencies also publishedEngineers announced a final rule addingestablishing a February 6, 2020 applicability date torevised and “durable” WOTUS definition on December 30, 2022, which restored many of the elements of the 2015 rule. TheMultiple legal challenges to the 2022 final rule adding this applicability dateare currently pending. Additionally, in October 2022, the Supreme Court of the United States heard oral argument in a case, Sackett v. EPA, that could further impact the ultimate rule. If the final rule announced in December 2022 is currently subject to litigation.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, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.discharges.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

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

Air Emissions

The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, 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,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 is discussedremoves them from the scope of the regulations. However, these 2020 rules are being challenged in more detail below in “—Regulation of Hydraulic Fracturing.” Thesethe 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. More stringent laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non‑compliancenon-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.

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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. 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. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, 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

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GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department informed the United Nations of the United States’ withdrawal in August 2017. Under the terms of the Paris Agreement, the earliest possible effective withdrawal date is November 2020.

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 addition,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. 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.

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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. However, on May 9, 2014,Legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtureschemicals used in oil and natural gas explorationthe fracturing process. If enacted, these or production. Further,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. In addition, legislationThis rescission was upheld in March 2020 by the United States District Court for the Northern District of California, but the decision 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.appealed. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictionswent into effect, they could result in delays in operations at well sites and increased costs to make wells productive.

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‑fracturedhydraulically-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, founddid 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. However, theThe report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic‑fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the

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SEC to investigate the natural‑gas industryThis study and any possible misleading of investorsother ongoing or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the EIA to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Theseproposed 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. For example, the Texas Legislature adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. Further, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. LocalIn 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. For example, following earthquakes in and around Cushing, Oklahoma, the Oklahoma Corporation Commission announced plans on November 7, 2016, to shut down or reduce the volume of disposal at certain injection wells that discharge into the Arbuckle formation. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Arkansas, Colorado, Kansas, New Mexico, Oklahoma and Texas, where many of our properties are located. In March 2017, the United States Geological Survey produced an updated seismic hazard survey that forecasted lower earthquake rates in regions of induced activity, but still showed significantly elevated hazards in the central and eastern United States. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the

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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 level.levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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·

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

·

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the rates of production or “allowables”;

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

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the plugging and abandoning of wells; and

·

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

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

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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 U.S.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 U.S.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‑pricenon-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‑jurisdictionalnon-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point‑of‑salepoint-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the operators of our properties produce.

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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‑discriminatorynon-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that our access to oil pipeline transportation services will not materially differ from our competitors’ access to oil pipeline transportation services.

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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.

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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. In connection with the closing of our IPO, weWe 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 and Mr. Duncan,certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services for us, including the operation of our properties.properties, and we may refer to individuals providing these services as our employees for ease of reference. The compensation for all our employees is indirectly paid by us pursuant to the management services agreement with Kimbell Operating. Please read “Item 10. Directors, Executive Officers and Corporate Governance” and “Item 13. Certain Relationships and Related Party Transactions, and Director Independence” 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, 2017,2022, Kimbell Operating hashad approximately 1427 employees performing services for our operations and activities. Women represent approximately 33% of our workforce, and men represent approximately 67%. We believe that our employees are one of our greatest assets and that we are made up of talented and dedicated employees working together to achieve common and rewarding goals. We value integrity, hard work, dedication and teamwork. Our goal is to promote an environment where employees are encouraged to do their best work with high professional standards.

Additional InformationFacilities

We were formed on October 30, 2015 as a Delaware limited partnership. 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,10-K, quarterly reports on Form 10‑Q,10-Q, current reports on Form 8‑K8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1‑800‑SEC‑0330. The SEC also 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 report.Annual Report.

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Item 1A. Risk Factors

There are many factors that could have a material adverse effect on the Partnership’sour operating results, financial condition and cash flows. New risks may emerge at any time and the Partnershipwe 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 the Partnership’sour common units.

Risks Related to Our BusinessOrganization 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. 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

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other contractual obligations, tax obligations, general and administrative expenses and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine are appropriate.

In addition, 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 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.non-cash items such as impairment expense or unit-based compensation expense. For example, we may have significant capital expenditures in the future. While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution to holders of our common units with respect to such quarter. As a result, we may pay cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods in which we record net income.

Our business is difficult to evaluate because we have a limited financial history.

Kimbell Royalty Partners, LP was formed in October 2015 and we completed our IPO in February 2017. Our Predecessor, Rivercrest Royalties, LLC, was formed in October 2013. We do not have historical financial statements with respect to our mineral and royalty interests for periods prior to their acquisition by the Contributing Parties. As a result, with respect to some of our assets, there is only limited historical financial information available upon which to base an evaluation of our performance.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will beis directly dependent on the performance of our business. We willdo 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.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. 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.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 “Market“Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy and Restrictions on Distributions.”

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TableFurthermore, 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 Contents

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 willmay rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, toTo the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

To In addition, 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. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior in right of distributions or liquidation to our common units. 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.

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We have funded a significant portion of the consideration paid in connection with many of our acquisitions with the issuance of equity securities, including common units and securities that are convertible or exchangeable into common units. There are no limitations in our partnership agreement on our ability to issue additional common units and, as a limited partnership, we are not required to seek unitholder approval for issuances of common units (including issuances in excess of 20% of our outstanding equity securities or issuances of equity to certain affiliates). To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.

The limited liability company agreement of our General Partner contains restrictive covenants, governance and other provisions that may restrict our ability to pursue our business strategies.

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

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

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

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

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

Please read “The Partnership Agreement—Certain Provisions of the Agreement Governing our General Partner.”

The Board of Directors is made up of nineeight members. Therefore, the vote of fourthree 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.distribution on common units.

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.

Our revenues, operating results, cash available for distribution 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;

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

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

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

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the price and quantity of foreign imports;

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the level of U.S. domestic production;

·

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

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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

·

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

·

the level of consumer product demand;

·

weather conditions and other natural disasters;

·

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;

·

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 West Texas Intermediate light sweet crude oil, which we refer to as West Texas Intermediate (“WTI”), has ranged from a low of $26.19 per Bbl in February 2016 to a high of $110.62 per Bbl in September 2013, and the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. The reduction in prices has been 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 Organization of Petroleum Exporting Countries to maintain or raise production levels. The International Energy Agency forecasts continued low global demand growth in 2017. 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. 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 scenario may result in our having to make substantial downward adjustments to our

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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, successful 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.

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 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.

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

We will be required to take write‑downs of the carrying values of our properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time.

Accounting rules 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.

No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. The substantial majority of our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. In accordance with SEC guidance., management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and remained effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the

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exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired, which could materially adversely affect our results of operations for the periods in which such charges are taken.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016 and 2015 our Predecessor recorded a non‑cash impairment charges of approximately $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the reduction in commodity prices and other factors.

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.

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, 2017, we received revenue from over 700 operators. For the year ended December 31, 2017, we received approximately 45.03% of revenues from the top ten operators of our properties. For the years ended December 31, 2016 and 2015, our Predecessor received approximately 64.2% and 67.8% of its revenues from the top ten operators of its properties, respectively. If these operators do not adequately and efficiently perform operations or act in ways that are beneficial to us, our production and revenues could decline. The operators of our properties are often not obligated to undertake any development activities. 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

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·

the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our oil, natural gas and NGL revenues and cash available for distribution. 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.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from the operators of our properties than we or they currently anticipate.

As of December 31, 2017, 26.5% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by the operators of our properties. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the operators of our properties are required to develop such reserves. We typically do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. We take into consideration the estimated costs of development or the scheduled development plans from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators. The development of such reserves may take longer and may require higher levels of capital expenditures from the operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for the operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

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

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

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

Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on our properties or we acquire properties containing proved reserves, or both. Aside from acquisitions, we have no control over the exploration and development of 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.

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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.

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 distribution. 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.

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

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

·

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 ability 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.

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. While we believe the Contributing Parties, including affiliates of our Sponsors, will be incentivized through their direct and indirect ownership of common units to offer us the opportunity to acquire additional mineral and royalty interests, including with respect to certain assets for which certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of our IPO, should they choose to sell such assets, there can be no assurance that any such offer will be made, 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.

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 may be materially adversely affected.

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

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

Our and our Predecessor’s historical estimates of proved reserves and related valuations as of December 31, 2017 and 2016 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.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as the operators of our properties pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five‑year timeframe. Furthermore, we typically do not have access to the drilling schedules of our operators and make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of our operators.

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.

We entered into a $50.0 million secured revolving credit facility in connection with our IPO. The secured revolving credit facility includes an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders). 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;

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·

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 more fully defined in the secured revolving credit facility) of not more than 4.0 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 because of the limitations that the restrictive covenants under our secured revolving credit facility impose on us.

A failure to comply with the provisions of our secured revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our secured revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Revolving Credit Agreement.”

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

Our secured revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi‑annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The borrowing base is determined based on our oil and gas properties and the oil and gas properties of our wholly owned subsidiaries. We have non‑wholly owned subsidiaries whose assets are not subject to a lien and not included in borrowing base valuations. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our secured revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Decreases in the 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.

Our existing and 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;

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·

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

·

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.

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, 2017, the average estimated yearly five‑year decline rate for our existing proved developed producing reserves is 8.8%. 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.

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. 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.

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

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Meanwhile, continued hostilities in the Middle East and the

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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 natural gas liquid 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 further, 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.

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.

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. 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 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 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 has entered into separate services agreements with certain entities controlled by affiliates of our Sponsors and Benny Duncan, 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. 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.

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. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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

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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.

A terrorist attack or armed conflict could harm our business.

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

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

We may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. 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. 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 Contributing Parties have limited indemnity obligations to us for liabilities arising out of the ownership and operation of our assets prior to the closing of our IPO, including title defects.

In connection with our IPO, we entered into a contribution agreement with the Contributing Parties that governs, among other things, their obligation to indemnify us for certain liabilities associated with the entities and assets contributed to us in connection with our IPO. Under the contribution agreement, the Contributing Parties are required, severally but not jointly, to indemnify us (i) for a period of one year following the closing of our IPO, for breaches of specified representations and warranties related to, among other things, (x) their authority to enter into the transactions contemplated by the contribution agreement and (y) the capitalization of the entities that were contributed to us; and (ii) 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. In addition, pursuant to the contribution agreement, the Contributing Parties, severally but not jointly, indemnified us for losses arising from certain liens and title defects created during their ownership of the entities and assets contributed to us in connection with our IPO.

Except as otherwise described above, 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. Moreover, the representations, warranties and indemnities provided by the Contributing Parties are subject to significant limitations, including indemnity caps, and may not protect us against all liabilities or other problems associated with the entities and assets contributed to us. For example, the existence of a material title deficiency covering a material amount of our assets can render a lease worthless and could materially adversely affect our financial condition, results of operations and cash available for distribution. We do not obtain title insurance covering mineral leaseholds, and our failure to cure any title defects may delay or prevent us from realizing the benefits of ownership of the mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects, or defects in the assignment of leasehold rights in properties in which we hold an interest, our business, results of operations and cash available for distribution may be adversely affected.

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The indemnities that the Contributing Parties agreed to provide under the contribution agreement may be inadequate to fully compensate us for losses we may suffer or incur as a result of liabilities arising out of the ownership and operation of our assets prior to the closing of our IPO. Even if we are insured or indemnified against such risks, we may be responsible for costs or penalties to the extent our insurers or indemnitors do not fulfill their obligations to us, and the payment of any such costs or penalties could be significant. The occurrence of any losses that are neither indemnified for under the contribution agreement nor covered under our insurance plans could materially adversely affect our financial condition, results of operations and cash available for distribution. 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—Indemnification.”

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

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

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.

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

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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.

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 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 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.

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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.

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

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

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

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the establishment of maximum rates of production from wells;

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the spacing of wells;

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the plugging and abandonment of wells; and

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the removal of related production equipment.

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

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 operators and delay production from our properties, which could reduce the amount of cash available for distribution to our 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

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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 “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.

Various federal, state and local initiatives are underway to investigate or regulate hydraulic fracturing. The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or restricting or even banning hydraulic fracturing in certain circumstances could make drilling certain wells less economically attractive to or impossible for the operators of our properties, which could materially adversely affect our business, results of operations, financial condition and ability to pay cash distributions to our unitholders.

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

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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. A number of lawsuits and enforcement actions have been initiated at the state level implicating hydraulic fracturing practices. 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 to account for induced seismicity. For example, following earthquakes in and around Cushing, Oklahoma, the Oklahoma Corporation Commission announced plans on November 7, 2016, to shut down or reduce the volume of disposal at certain injection wells that discharge into the Arbuckle formation. 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 “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.

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. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case‑by‑case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified 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. These requirements 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 “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 June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated. The State Department informed the United Nations of the United States’ withdrawal in August 2017. Under the terms of the Paris Agreement, the earliest possible effective withdrawal date is November 2020. 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.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent 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

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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.

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, floods, and other climatic events; if any of these effects were to occur, they could materially adversely affect our properties and operations.

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.

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

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unusual or unexpected geological formations;

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loss of drilling fluid circulation;

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title problems;

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facility or equipment malfunctions;

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unexpected operational events;

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shortages or delivery delays of equipment and services;

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compliance with environmental and other governmental requirements; and

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adverse weather conditions.

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

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.

The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their

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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 may be adversely affected.

Prior to our acquisition of the assets in connection with our IPO and during the year ended December 31, 2017, record title to the mineral and royalty interests was held by various unrelated entities. At the closing of our IPO and each subsequent acquisition, a significant amount of these mineral and royalty interests were conveyed to us or our subsidiaries as asset assignments, 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.

Risks Inherent in an Investment in Us

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.

AffiliatesAs of February 17, 2023, the owners of our General PartnerSponsors own or control up to an aggregate of 23.5%approximately 9.9% of our outstanding common units and Class B units, and our Sponsors indirectly own and control our General Partner. Our General Partner has sole responsibility for conducting our business and managing our operations. Although our General Partner has a duty to manage us in a manner that is in, or not adverse to, the best interests of us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is beneficial to Kimbell Holdings and its parents, our Sponsors. Conflicts of interest may arise between our Sponsors and their respective affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our General Partner may favor its own interests and the interests of its affiliates, including our Sponsors and their respective affiliates, over the interests of our unitholders. These conflicts include, among others, the following situations:

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

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

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·

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

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our partnership agreement does not limit our Sponsors’ or their respective affiliates’ ability to compete with us and, subject to the 50% participation right included in the contribution agreement that we entered into with our Sponsors and the Contributing Parties in connection with our IPO, neither our Sponsors nor the Contributing Parties have any obligation to present business opportunities to us, and although certain of the Contributing Parties have granted us a right of first offer for a period of three years after the closing of our IPO with respect to certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, such Contributing Parties are under no obligation to offer such assets to us;

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

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

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

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

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

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

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

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

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

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

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our General Partner may exercise its right to call and purchase all of the common units and Class B units not owned by it and its affiliates if it and its affiliates own more than 80% of our common units;

units and Class B units (taken as a single class);

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

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

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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 common 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.

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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. In connection with our IPO, weWe have entered into a management services agreement with Kimbell Operating, which in turn has entered into separate services agreements with certain entities controlled by

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affiliatescertain of our Sponsors and Mr. Duncan,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 holders of our common unitsunitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

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

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

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

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

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

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

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

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

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

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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 holders of our common unitsunitholders with contractual standards governing its duties.

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

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

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whether to exercise its limited call right;

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

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

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

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

By purchasingacquiring an interest in us, a common unit, a common unitholderlimited 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 “Certain“Item 13. Certain Relationships and Related Party Transactions, and Director Independence.” Unlike publicly traded corporations, we willdo not conduct annual meetings of our

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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.

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Even if holders of our common unitsunitholders are dissatisfied, they cannot initially remove our General Partner without its consent.

If our unitholders are dissatisfied with the performance of our General Partner, they will have limited ability to remove our General Partner. Our General Partner may not be removed unless such removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 662/3% of all outstanding units (including common units. Affiliatesunits and Class B units held by the General Partner and its affiliates). As of February 17, 2023, the owners of our General PartnerSponsors own or control an aggregate of 23.5%approximately 9.9% of our outstanding common units and Class B units, 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 common units (other than our General Partner and its affiliates, the Contributing Parties and their respective affiliates and permitted transferees).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, and persons who acquired such units with the prior approval of the Board of Directors, and holders who own 20% or more of any class of units as a result of any redemption or purchase of any other holder’s units at our option, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common 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 doesand 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 doesand 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 providesand 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 “Market“Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities— Cash Distribution Policy and Restrictions on Distributions.”

In connection with the closing of our IPO, weWe 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 and Mr. Duncan,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

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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.

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.

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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 17‑60717-607 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‑recoursenon-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.

While interest rates have been at record low levels inThe recent years, this low interest rate environment likely will not continue indefinitely. An increaseincreases in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield‑basedyield-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 common 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‑currentthen-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.

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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. UponAct of 1934, as amended (the “Exchange Act”). As of February 17, 2023, the completionowners of our IPO, affiliates of our General PartnerSponsors own or control up to an aggregate of 23.5%approximately 9.9% of our outstanding common units and Class B units, and our Sponsors will indirectly own and control our General Partner.

We may issue additional common units and other equity interests 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 interests, includingpartnership interests. 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, withoutrespectively, which are together exchangeable on a vote of the unitholders.one-for-one basis into common units. The issuance by us of additional common units or other equity interests of equal or senior rank willto the common units would have the following effects:

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

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

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the ratio of our taxable income to distributions may increase;

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

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the market price of the common units may decline.

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

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

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

As a result of our IPO, we had 16,332,708 common units outstanding. As of December 31, 2017,2022, we had 16,509,79964,231,833 common units outstanding and 15,484,400 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.

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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We are no longer an “emerging growth company,” and, as a result, we now must comply with increased reporting and disclosure requirements, which may increase our costs.

We no longer qualify as an “emerging growth company” within the meaning of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 and, as a result, are subject to various disclosure and compliance requirements that did not previously apply, such as:

●the requirement that our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act of 2002;
●compliance with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding obligatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements;
●the requirement that we provide full and more detailed disclosures regarding executive compensation; and
●the requirement that we hold a non-binding advisory vote on executive compensation and obtain unitholder approval of any golden parachute payments not previously approved.

We expect that the loss of emerging growth company status and compliance with these additional requirements may increase our legal and financial compliance costs and cause management and other personnel to divert attention from operational and other business matters to devote substantial time to public company reporting requirements. In addition, if we are not able to comply with changing requirements in a timely manner, the Contributing Parties have registration rights.trading price of our common units could decline and we could be subject to sanctions or investigations by the NYSE, the SEC or other regulatory authorities, which would require additional financial and management resources.

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

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

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changes in commodity prices;

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

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

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changes in market valuations of similar companies;

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departures of key personnel;

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commencement of or involvement in litigation;

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

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

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

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

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

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

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future sales of our common units; and

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the other factors described in these “Risk Factors.”

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We have incurred and will continue to incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we have and will continue to incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes‑Oxley Act of 2002 (the “Sarbanes‑Oxley Act”) and the Dodd‑Frank Act of 2010, as well as rules implemented by the SEC and the New York Stock Exchange (“NYSE”), require, or will require, publicly traded entities to maintain various corporate governance practices that further increase our costs. Before we are able to pay distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that apply to other public companies.

We are an “emerging growth company” as defined in the Jumpstart Our Business Act (“JOBS Act”). For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes‑Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

In addition, Section 102 of the JOBS Act also provides that an “emerging growth company” can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. An “emerging growth company” can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we choose to “opt out” of such extended transition period, and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non‑emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls are or will be successful, able to maintain adequate controls over our financial processes and reporting in the future or able to comply with our obligations under Section 404 of the Sarbanes‑Oxley Act. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. However, for as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

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

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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 purchasing a common unit,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 purchasing a common unit,acquiring an interest in us, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. These provisions may have the effect of discouraging lawsuits against us and our General Partner’s officers and directors.

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

We have adopted certain requirements regarding those investors who may own our common 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‑currentthen-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

Tax Risks Related to Common UnitholdersEconomic 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 tax treatment dependsrevenues, operating results, cash available for distribution on common units and the carrying value of our status asoil 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 partnershipvariety 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;

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●the level of United States domestic production;
●political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;
●the ability of members of the OPEC to agree to and maintain oil price and production controls;
●the ability of Iran to increase the export of oil and natural gas upon the relaxation of international sanctions;
●speculative trading in crude oil, natural gas and NGL derivative contracts;
●the level of consumer product demand;
●weather conditions and other natural disasters, the frequency and impact of which could be increased by the effects of climate change;
●risks associated with operating drilling rigs;
●technological advances affecting energy consumption;
●domestic and foreign governmental regulations and taxes;
●the continued threat of terrorism and the impact of military and other action, including military actions involving Russia and Ukraine;
●the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities;
●the price and availability of alternative fuels; and
●overall domestic and global economic conditions.

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 federal income tax purposes,WTI, has ranged from a low of $(36.98) per Bbl in April 2020 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price of natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. On December 31, 2022, the WTI posted price for crude oil was $80.16 per Bbl and the Henry Hub spot market price of natural gas was $3.52 per MMBtu. On February 6, 2023, the WTI posted price for crude oil was $74.11 per Bbl and the Henry Hub spot market price of natural gas was $2.17 per MMBtu. 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 beinghedge 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

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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, 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. 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

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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 entity‑level taxationoil 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.

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 individual states. If the Internal Revenue Service (“IRS”) wereoperators 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 treat usreturn 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 corporationresult of other factors, including:

●unusual or unexpected geological formations;
●loss of drilling fluid circulation;
●title problems;
●facility or equipment malfunctions;

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●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 federal income tax purposes or we were to become subject to entity‑level taxation for state tax purposes, thenany 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 be substantially reduced.result in financial losses and reduce earnings.

The anticipated after‑tax economic benefitTo achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of an investmentoil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, wefuture oil and natural gas production, including fixed price swaps, collars and basis swaps. We have not requested,designated and do not plan to request,designate any of our derivative contracts as hedges for accounting purposes and, as a rulingresult, 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.

In addition, these types of derivative contracts can limit the benefit we would receive from increases in the IRS on thisprices 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 $350.0 million and includes an elected commitment amount feature permitting aggregate commitments under the secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base, which is currently $350.0 million, and to the satisfaction of certain conditions and the election of existing lenders to increase commitments or anythe procurement of additional commitments from new lenders. 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 matter affecting us. A changethings:

●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;

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●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 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, 2022, we had approximately $233.0 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;

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●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, 2022, we received revenue from approximately 1,500 operators and we received approximately 40.3% of revenues from the top ten purchasers of our properties. During the year ended December 31, 2022, payments we received from our top purchaser accounted for approximately 11.3% 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;

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●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 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;

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●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 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;

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●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 Springbok Acquisition, and we may enter into transition services agreements with future sellers (or their affiliates) of any mineral and royalty interests that we may acquire. 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.

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 law could cause usdrilling 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 treatedinaccurate. 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, 2022, 2021 and 2020 were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us. 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

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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, 2022, the average estimated yearly five-year decline rate for our existing proved developed producing reserves is 12.4%. However, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to acquire additional reserves to replace the current and future production of our properties at economically acceptable terms, which could materially adversely affect our business, financial condition, results of operations and cash available for distribution on common units.

We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution on common units. We do not intend to retain cash from our operations for replacement capital expenditures primarily due to our expectation that the continued development of our properties and completion of drilled but uncompleted wells by working interest owners will substantially offset the natural production declines from our existing wells.

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

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pursuant to a contract, could materially adversely affect our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

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

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

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

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

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

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

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Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.

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

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

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

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

The operators of our properties will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to the operators of our properties due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

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

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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 properties if commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. 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 material impairments in prior years as a result of the decline in oil and natural gas prices. For example, for the year ended December 31, 2020, we recorded an impairment on our oil and natural gas properties of $251.6 million. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

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 U.S.United States federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporationand for federalstate income tax purposes in most states in which we would paydo 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%. Distributions, and to our unitholders would generally be taxed again as corporate distributions, and nostate income gains, losses or deductions would flow throughtax at rates that vary from state to our unitholders. Because a tax would be imposed upon us as a corporation, ourstate. The amount of cash available for distribution to our unitholders wouldyou will be substantially reduced. In addition, changes in current state law may subject us to additional entity‑level taxationreduced by individual states. Several states have subjected, or are evaluating ways to subject, partnerships to entity‑level taxation through the imposition of state income, franchise and other forms of taxation. Impositionamount of any such taxes may substantially reduce the cash available for distribution to our unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity‑level taxation would result in a material reduction in the anticipated cash flow and after‑tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders’ allocable share of our net income, in which case our unitholders’ tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.

Pursuant to the recently enacted tax reform law known as the Tax Cuts and Jobs Act (“TCJA”), for taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a publicly traded partnership’s U.S. trade or business. Because we own only passive mineral and royalty interests, we may not be viewed as engaged in a U.S. trade or business within the meaning of the new law. Therefore, most or all of the income that we now generate, or will generate in the future, may not be qualifying publicly traded partnership income eligible for the 20% deduction. Thus, our unitholders may not be able to claim the 20% deduction on any income allocated from us, and any such claim may be successfully challenged by the IRS. We are continuing to evaluate the extent to which we may qualify for the deduction and possible actions to address the issue. If the deduction is not available, our unitholders’ tax liability from ownership and disposition of our units may be materially higher than if the deduction is available. We urge our unitholders to consult with their tax advisors regarding the availability of the 20% deduction on any income allocated from us. The TCJA is complex and far-reaching and we have not completed our analysis of the impact its enactment has on us. There may be other material adverse effects resulting from the TCJA that we have not identified and that could have an adverse effect on our business, results of operations, financial condition and cash flow.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, the President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for federal income tax purposes.

On January 24, 2017, the IRS and the U.S. Department of the Treasury published in the Federal Register final regulations (the “Final Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Final Regulations apply to taxable years beginning after January 19, 2017. The Final Regulations provide that income earned from a royalty interest is qualifying income. Under current law and the Final Regulations, we believe that our royalty income is qualifying income and that we satisfy the qualifying income requirement for us to be treated as a partnership for U.S. federal income tax purposes. However, there are no assurances that current law or the Final Regulations will not be revised to take a position that is contrary to our interpretation.

We are unable to predict whether any of these changes or any other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us or our unitholders. The IRS may adopt positions that differ from the conclusions of our counsel expressed in the prospectus for our IPO or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions frompayable by us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage.  For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt.  A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law.  For instance, under the TCJA, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications.  If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period.  These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates.  Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors.  The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

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

If a unitholder sells itsA holder of common units itgenerally will recognize acapital 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

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an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, equalour distributable cash flow may 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.

For example, in August 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”), which includes a new corporate alternative minimum tax, beginning in fiscal year 2024, and an excise tax of 1% tax on the fair market value of net units repurchases made after December 31, 2022. We are evaluating the corporate alternative minimum tax and its potential impact on our future U.S. tax expense, cash taxes, and effective tax rate, as well as any other impacts the Inflation Reduction Act may have on our financial position and results of operations.

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 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 difference betweenextent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits are not be treated as “dividends” for United States federal income tax purposes; instead, they are treated first as a tax-free return of capital to the amount realized and itsextent of your tax basis in thoseyour units and then as capital gain realized on the sale or exchange of such units.

If you are a holder of our common units. Becauseunits, 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

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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 excessany 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 allocable share of our net taxable income decreases thebasis in its common units, such distributions will reduce such unitholder’s adjusted tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sellswhich will result in effect, become taxable income to the unitholder if the unitholder sell such units at a price greater than its tax basisan increase in those units, even if the price the unitholder receives is less than its original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cashgain (or a decrease in the amount of loss) that will be recognized by the unitholder receives from the sale.

Tax‑exempt entities and non‑U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax‑exempt entities, such as employee benefit plans and individual retirement accounts or annuities known as IRAs, and non‑U.S. persons raises issues unique to them. For example,on a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Under the TCJA, an exempt organization will be required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non‑U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non‑U.S. persons, and each non‑U.S. person may be required to file U.S. federal income tax returns and

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pay tax on their share of our taxable income if it is treated as income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”).

Under the TCJA, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the Department of the Treasury and the IRS have determined that this withholding requirement should not apply to anyfuture disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.

Unitholders that are a tax-exempt entities or non‑U.S. persons should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of our common units, and becauseto 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 other reasons,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 will adopt depreciation and amortization positionsthe 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.

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 not conformbe 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 aspectsfederal 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 existing Treasury

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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 (“Treasury Regulations”). Our counsel is unableprimarily relating to opine asprotection of human health and safety and the environment. Failure to comply with these laws and regulations by the validityoperators of this approach. A successful IRS challenge to those positions could adverselyour 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 the amountproduction levels. The operators of tax benefits available to unitholders. It also could affect the timing of these tax benefitsour 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 the amount of gain from unitholders’ sales of common unitsalter applicable pipeline safety laws and could have a negative impactregulations, compliance with which may require increased capital costs on the valuepart of our common units or result in audit adjustments to unitholders’ tax returns.operators and third party downstream natural gas transporters associated with production from our properties.

We prorate our items of income, gain, loss and deduction between transferors and transfereesThe operators of our common units each month based uponproperties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the ownershipextent the operators of our common unitsproperties are shippers on interstate pipelines, they must comply with the first business daytariffs of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, lossthose pipelines and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions,with federal policies related to the use of this proration method may not be permitted under existing Treasury Regulations. interstate capacity.

The U.S. Treasury Department recently adopted final Treasury Regulations allowing similar monthly simplifying conventions. However, the final Treasury Regulations do not specifically authorize the useoperators of the proration method we have adopted. If the IRS were to challenge our proration method, weproperties may be required to changemake significant expenditures to comply with the allocationgovernmental 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 itemsthe operators and delay production from our properties, which could reduce the amount of income, gain, loss and deduction among our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.common unitholders.

PursuantThe operators of our properties are subject to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penaltiescomplex and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances.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 current unitholdersbusiness and financial condition.

The operators of our properties may bear some or allincur 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 tax liabilityenvironment 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

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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 such audit adjustments, even if such unitholders didthe 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 own unitsable 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 us duringincreased costs and additional operating restrictions or delays.

The operators of our properties use hydraulic fracturing for the year under audit.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 wethe operators of our properties are requiredunable to make paymentsobtain 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 taxes, penaltiesoperations and interest resulting from audit adjustments, our cash available for distribution on common units.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that hydraulic fracturing activities can impact drinking water resources under certain circumstances, including large volume spills and inadequate mechanical integrity of wells. These and other ongoing or proposed studies could spur initiatives to our unitholders might be substantially reduced.

Infurther regulate hydraulic fracturing and could ultimately make it more difficult or costly for the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryoversoperators 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

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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 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

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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 compensation fromof 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 such unitholders),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.

The ongoing COVID-19 pandemic and the related impact on oil and natural gas prices have adversely affected, and could continue to adversely affect, our business, financial condition and results of operations.

​

The ongoing COVID-19 pandemic reached more than 200 countries and has continued to be a rapidly evolving economic and public health situation. The pandemic resulted in widespread adverse impacts on the global economy and financial markets, including record economic contraction in the United States, and we and our third-party operators and other parties with whom we have business relations experienced disrupted business operations as a result. There is considerable uncertainty regarding the extent to which COVID-19, or any of its variants, will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19, or any of its variants, such underpayment is attributableas large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. While many countries have removed or reduced the restrictions taken in response to COVID-19, the emergence of new variants may result in renewed governmental lockdowns, quarantine requirements or other restrictions.

The impact of the pandemic, including the resulting significant reduction in global demand for oil and, to a net decreaselesser extent, natural gas, coupled with the sharp decline in passive activity losses allocableoil prices following the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, led to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

A unitholder whose common units are loanedsignificant global economic contraction generally and in our industry in particular. Although OPEC agreed in April 2020 to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loancut oil production and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss fromextended such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not liveproduction cuts through March 2021, crude oil prices remained depressed through December 31, 2020 as a result of investingan increasingly utilized global storage network and the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 pandemic, and as changes in oil and natural gas inventories, industry demand and economic performance are reported. The volatile price environment in 2020 and early 2021 caused some of our operators’ wells to become uneconomic, which resulted, and may result in the future, in suspension of production from those wells or a significant reduction in, or no royalty revenues from, existing production. Some operators may also attempt to shut in producing wells and avoid lease

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termination or payment of shut-in royalties by claiming force majeure, if provided for in the applicable lease. The curtailment of production or the shut-in of wells as a result of the ongoing COVID-19 pandemic and any drop in commodity prices are both outside of our control, and the materialization of either circumstance could have a significant impact on our result of operations. We cannot predict whether any shut-ins or curtailments of production will be instituted by our operators in the future.  

Due to the significant decline in oil and natural gas prices related to reduced demand for oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, as well as longer-term commodity price outlooks that existed during 2020, we recorded an impairment on our oil and natural gas properties of $251.6 million for the year ended December 31, 2020. If the price of oil, natural gas and NGLs decrease further in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. The Partnership did not record an impairment on its oil and natural gas properties for the years ended December 31, 2022 and 2021.

To the extent that access to the capital and other financial markets is adversely affected by the effects of COVID-19, or it variants, and commodity prices generally, we may need to consider alternative sources of funding for our future acquisitions, which may increase our cost of, as well as adversely impact our access to, capital or otherwise impact our ability to complete acquisitions. We cannot predict the full impact that COVID-19, or its variants, or the significant disruption and volatility in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impact will depend on future developments beyond our control, which are highly uncertain and cannot be predicted, including, among others, the ultimate severity of COVID-19 and its variants, the consequences of governmental and other measures designed to prevent the spread of COVID-19, the development, availability and administration of effective treatments and vaccines, the duration of the pandemic, future actions taken by members of OPEC and other foreign oil-exporting countries, actions taken by governmental authorities, third-party operators and other third parties and the timing and extent of any return to normal economic and operating conditions.

A terrorist attack or armed conflict could harm our business.

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

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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. For example, the oil and natural gas industry depends on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with customers, employees and third-party partners. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The United States government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. We are dependent on our and our operators’ information systems and computer-based programs. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our or our operators’ hardware or software network infrastructure, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition to the service providers who provide substantial services to us under our services agreement with Kimbell Operating, we rely on third party service providers to perform some of our data entry, investor relations and other functions. If the programs or systems used by our third-party service providers are not adequately functioning, we could experience loss of important data.

In addition, unauthorized access to our reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Our systems for protecting against cyber security risks may not be sufficient. Further, as cyber-attacks continue to evolve, including by state actors or other abroad, we or our service providers, who we are generally obligated to reimburse for costs incurred in connection with the provision of their services to us, may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

Risks Related to Our Investment in TGR

​

TGR may not be able to complete its initial business combination within the prescribed time frame, in which case it would cease all operations except for the purpose of winding up and it would redeem its public shares and liquidate. In that circumstance, we would lose our entire investment in TGR, including the Private Placement Warrants.

TGR must complete its initial business combination within 15 months from its IPO (or up to 21 months, if TGR Sponsor exercises its extension options). TGR may not be able to find a suitable target business and complete its initial business combination within such time period, in which case it would cease all operations except for the purpose of winding up and it would redeem its public shares and liquidate. In that circumstance, we would lose our entire investment in TGR, including the Private Placement Warrants, which were purchased for $14,100,000, and this would likely have a negative effect on the trading price of our common units.

In addition to federal income taxes, unitholders will likelyResources could be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxeswasted in researching acquisitions that are imposed by the various jurisdictions innot completed, which we conduct businesscould materially adversely affect subsequent attempts to locate and acquire or own property now or in the future, even if they do not live in any of those jurisdictions. merge with another business.

We own assets and conduct business in 20 states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. Unitholders maywill be required to file statedevote significant management and local income tax returnsemployee attention and pay stateresources to matters relating to TGR while it pursues a business combination. The investigation of each specific target business and local income taxesthe negotiation, drafting and execution of relevant agreements, disclosure documents and other instruments will require substantial management time and attention and substantial costs for accountants, attorneys and others. If TGR decides not to complete a specific initial business combination, the costs incurred up to that point for the proposed transaction likely would not be recoverable. Furthermore, if TGR reaches an agreement relating to a specific target business, it may fail to complete its initial business combination for any number of reasons including those beyond its control. Any such event will result in a loss of the related costs incurred which could materially adversely affect subsequent attempts to locate and acquire or merge with another business.

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There has recently been heightened regulatory focus on SPACs, including recently issued accounting guidance, resulting in substantial uncertainty in the SPAC markets. TGR’s pursuit of a business combination in this uncertain SPAC environment may result in delays, reduced investor and acquisition target interest in SPAC transactions, additional costs as instrument terms are reevaluated and our management and employees needing to devote extensive attention and resources to these jurisdictions. Further, unitholders maymatters. The accounting guidance applicable to SPACs could subsequently be subjectrevisited, potentially necessitating restatements of TGR’s financial statements, which could then impact and necessitate restatements of our financial statements. These matters have the potential to penalties for failure to comply with those requirements. As we make acquisitions or expanddisrupt us from conducting our business weoperations or pursuing other business strategies and could adversely affect our businesses, financial condition, results of operations and cash available for distribution on our common units.

We and TGR have overlapping directors and management, which may own assetslead to conflicting interests.

Some of our officers and directors also serve as executive officers and directors of TGR. Any such persons who serve in similar capacities at TGR have fiduciary duties to that company’s stockholders. Therefore, such persons may have conflicts of interest or conduct business in additional statesthe appearance of conflicts of interest with respect to matters involving or foreign jurisdictions that impose a personal income tax. It isaffecting us and one or more of the unitholders responsibilityrelated companies to file all U.S. federal, foreign, state and local tax returns.which they owe fiduciary duties.

​

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

The range of high and low intraday sales prices for the Partnership’s common units for the periods indicated, as reported by the NYSE, is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

High

 

Low

 

Distributions (1)

2017

 

 

 

 

 

 

 

 

 

First Quarter (from February 3, 2017 through March 31, 2017)

 

$

20.89

 

$

18.06

 

$

0.23

Second Quarter

 

$

20.00

 

$

15.65

 

$

0.30

Third Quarter

 

$

17.58

 

$

15.06

 

$

0.31

Fourth Quarter

 

$

17.50

 

$

15.70

 

$

0.36

(1)

Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.

As of March 2, 2018,February 17, 2023, there were 16,836,45364,231,833 common units outstanding held by 274158 holders of record and 15,484,400 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 and Restrictions

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on Distributions

Ourhand 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. We adjusted the amount of our distribution for the period from the closing of our IPO through March 31, 2017, based on the actual length of the period. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. We define available“Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company and our partnership agreement, in the glossary of terms.agreement. We expect that the Operating Company’s available cash for each quarter will generally equal ourits 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 2022 for the repayment of $13.1 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2022. 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 generally intend tocurrently maintain excess distribution coveragea material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, or otherwise to reserve cash for distributions, nor do we generally intend to incur debt to pay quarterly distributions, although the Board of Directors may choose to do so if they believe it is warranted.change this policy.

Unlike a number of other master limited partnerships,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(“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. Although we expect no or limited organic growth at lower commodity prices, we believe that our operators have significant drilling inventory remaining on the acreage underlying our mineral or royalty interest in multiple resource plays that will provide a solid base for organic growth when commodity prices increase. If they believe it is warranted, theexpenditures”). 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

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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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We expect to pay our distributions for the quarters ending March 31, June 30 and September 30 by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 60 days following the end of such quarter. We expect to pay our distributions for the quarter ending December 31 by the earlier of (i) 20 business days following the publication of our results of operations with respect to such quarter or (ii) 90 days following the end of such quarter.

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 Cashthe 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

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the Operating Company of its results of operations with respect to such quarter or (ii) 90 days following the end of such quarter. The limited liability company agreement of the Operating Company generally defines “available cash” as:

●the sum of:
●all cash and cash equivalents of the Operating Company and its subsidiaries on hand at the end of that quarter; and
●as determined by the managing member of the Operating Company, all cash or cash equivalents of the Operating Company and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings (as described below) made after the end of that quarter;
●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 and

Subject to the distribution preferences of the Class B units, we intend to distribute available cash to our common unitholders pro rata. Our Abilitypartnership agreement permits, but does not require, us to Change Our Cash Distribution Policy

Thereborrow to pay distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter. The Class B units will receive the distribution preference described below.

Class B units

As of February 17, 2023, we had 15,484,400 Class B units outstanding. Each holder of Class B units pays five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution” and such per unit amount, the “Class B Capital Contribution Per Unit Amount”) in exchange for Class B units. Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution prior to distributions on our common units.

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Common Units

As of February 17, 2023, we had 64,231,833 common units outstanding. Subject to the distribution preferences of the Class B units, each common unit is entitled to receive cash distributions to our unitholders each quarter.the extent we distribute available cash. Common units do not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional equity interests of equal or senior rank.

General Partner Interest

Our General Partner owns a non-economic general partner interest in us and therefore is not entitled to receive cash distribution policy is subject to certain restrictions, including the following:

·

Following the formation transactions in connection with our IPO, we borrowed $1.5 million under our secured revolving credit facility to fund certain transaction expenses and we borrowed an additional $29.3 million to fund asset acquisitions made during the year ended December 31, 2017. Our credit agreement contains certain financial tests and covenants that we 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 the restrictions under any 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 partnerdistributions. However, it may acquire common units and other partnership interests including those held by the Contributing Parties, will be subordinate in right of distribution payment to our common units.

·

Our General Partner will have 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. Our partnership agreement does not set 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 on our units, we will reimburse our General Partner and its affiliates, including Kimbell Operating pursuant to its management services agreement discussed below, for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides 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 entered into a management services agreement with Kimbell Operating in connection with our IPO, which entered into separate services agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, 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, reduce the amount of cash to pay distributions to our unitholders.

·

Under Section 17‑607 of 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 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.

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business. As a result, our growth will depend initially on our operators’ ability, and perhaps our ability in the future to raise debt and equity capital from third parties

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in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.entitled to receive pro rata distributions in respect of those partnership interests.

We expect to pay our distributions within 45 days of the end of each quarter.

Securities Authorized for Issuance under Equity Compensation Plans.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, 2017.2022.

Unregistered Sales of Securities.Equity Securities

None.

Repurchases of Equity Securities.

None.

Item 6. Selected Financial Data

SELECTED FINANCIAL DATA

Kimbell Royalty Partners, LP was formed in October 2015.On February 8, 2017,March 30, 2022, we completed our IPO of 5,750,000issued 9,357,919 common units representing limited partner interests, which included 750,000to PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (the “PEP Entities”) in exchange for 9,357,919 OpCo common units and an equal number of Class B units pursuant to the underwriters’ optionterms of the Exchange Agreement, dated as of September 23, 2018 (the “Exchange Agreement”), by and among the PEP Entities, us, the General Partner, the Operating Company and the other holders of OpCo Common Units and Class B Units from time to purchase additionaltime party thereto.

On April 22, 2022, we issued 42,081 common units. The mineralunits to PEP II Holdings, LLC in exchange for 42,081 OpCo common units and royalty interests making up the Partnership’s initial assets were contributedan equal number of Class B units pursuant to the Partnership by the Contributing Parties at the closingterms of the IPO. As a result, asExchange Agreement.

The issuance of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely thateach of the Predecessor, Rivercrest Royalties, LLC, and does not includeforegoing securities was exempt from the resultsregistration requirements of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and NGL production revenues of our Predecessor represented approximately 11% of our Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

The following table sets forth, asSecurities Act in reliance upon Section 4(a)(2) of the dates and for the periods indicated, our selected financial information, which is derived from our audited consolidated financial statements for the respective periods. The information should be read in conjunction with “ItemSecurities Act.

​

Item 6. [Reserved]

​

​

​

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

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Operations” and our consolidated financial statements and notes thereto contained in “Item 8. Financial Statements and Supplementary Data.”

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

    

2015

 

2014

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues

 

$

30,665,092

 

 

$

318,310

 

$

3,606,659

 

$

4,684,923

 

$

7,219,822

Loss on commodity derivative instruments

 

 

(318,829)

 

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Total revenues

 

 

30,346,263

 

 

 

318,310

 

 

3,606,659

 

 

4,684,923

 

 

7,219,822

Cost and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

2,452,058

 

 

 

19,651

 

 

280,474

 

 

426,885

 

 

568,327

Depreciation, depletion and accretion expense

 

 

15,546,341

 

 

 

113,639

 

 

1,604,208

 

 

4,008,730

 

 

4,044,802

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,992,897

 

 

28,673,166

 

 

7,416,747

Marketing and other deductions

 

 

1,648,895

 

 

 

110,534

 

 

750,792

 

 

747,264

 

 

526,727

General and administrative expenses

 

 

8,191,792

 

 

 

532,035

 

 

1,746,218

 

 

1,789,884

 

 

1,757,377

Total costs and expenses

 

 

27,839,086

 

 

 

775,859

 

 

9,374,589

 

 

35,645,929

 

 

14,313,980

Operating income (loss)

 

 

2,507,177

 

 

 

(457,549)

 

 

(5,767,930)

 

 

(30,961,006)

 

 

(7,094,158)

Other expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

791,437

 

 

 

39,307

 

 

424,841

 

 

385,119

 

 

302,118

Income (loss) before income taxes

 

 

1,715,740

 

 

 

(496,856)

 

 

(6,192,771)

 

 

(31,346,125)

 

 

(7,396,276)

State income taxes

 

 

 —

 

 

 

 —

 

 

19,848

 

 

(32,199)

 

 

16,970

Net income (loss)

 

$

1,715,740

 

 

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

 

$

(7,413,246)

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.11

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

 

$

(12.27)

Diluted

 

$

0.10

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

 

$

(12.27)

Cash distributions declared and paid

 

$

0.36

 

 

 

*

 

 

*

 

 

*

 

 

*

Statement of Cash Flows Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

18,573,481

 

 

$

186,719

 

$

1,086,603

 

$

2,713,133

 

$

4,038,018

Investing activities

 

$

(125,910,708)

 

 

$

(523)

 

$

(97,464)

 

$

(538,640)

 

$

(53,463,030)

Financing activities

 

$

112,962,722

 

 

$

 —

 

$

(863,000)

 

$

(2,062,818)

 

$

39,645,738

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA (1)

 

$

19,170,760

 

 

$

(293,488)

 

$

1,434,234

 

$

2,325,949

 

$

4,518,656

Selected Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

5,625,495

 

 

$

692,077

 

$

505,880

 

$

379,741

 

$

268,066

Total assets

 

$

295,291,004

 

 

$

19,915,596

 

$

20,538,731

 

$

27,905,790

 

$

58,753,888

Long‑term debt

 

$

30,843,593

 

 

$

10,598,860

 

$

10,598,860

 

$

11,448,860

 

$

9,003,860

Total liabilities

 

$

33,225,570

 

 

$

11,431,068

 

$

11,906,869

 

$

13,666,368

 

$

10,556,272

Predecessor members' equity

 

$

 —

 

 

$

8,484,528

 

$

8,631,862

 

$

14,239,422

 

$

48,197,616

Partners' capital

 

$

262,065,434

 

 

$

 —

 

$

 —

 

$

 —

 

$

 —

* Information is not applicable for the periods prior to the initial public offering.

(1)

For more information, please read “—Non‑GAAP Financial Measures.”

Non‑GAAP Financial Measures Operations

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental non-GAAP (as defined below) financial measure by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe

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Adjusted EBITDA is useful because it allows 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) before interest expense, net of capitalized interest, non‑cash unit‑based compensation, unrealized gains and losses on commodity derivative instruments, impairment of oil and natural gas properties, income taxes and depreciation, depletion and accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by the generally accepted accounting principles in the United States (“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.

Adjusted EBITDA should not be considered an alternative to net income, 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 may not be comparable to other similarly titled measures of other companies.

The tables below present a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

 

2015

 

2014

Net income (loss)

 

$

1,715,740

 

 

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

 

$

(7,413,246)

Depreciation, depletion and accretion expense

 

 

15,546,341

 

 

 

113,639

 

 

1,604,208

 

 

4,008,730

 

 

4,044,802

Interest expense

 

 

791,437

 

 

 

39,307

 

 

424,841

 

 

385,119

 

 

302,118

State income taxes

 

 

 —

 

 

 

 —

 

 

19,848

 

 

(32,199)

 

 

16,970

EBITDA

 

 

18,053,518

 

 

 

(343,910)

 

 

(4,163,722)

 

 

(26,952,276)

 

 

(3,049,356)

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,992,897

 

 

28,673,166

 

 

7,416,747

Unit‑based compensation

 

 

798,413

 

 

 

50,422

 

 

605,059

 

 

605,059

 

 

151,265

Loss on commodity derivative instruments

 

 

318,829

 

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Adjusted EBITDA

 

$

19,170,760

 

 

$

(293,488)

 

$

1,434,234

 

$

2,325,949

 

$

4,518,656

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash interest expense

 

 

455,228

 

 

 

34,505

 

 

373,513

 

 

333,289

 

 

247,921

Capital expenditures

 

 

 —

 

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Cash available for distribution

 

$

18,715,532

 

 

$

(327,993)

 

$

1,060,721

 

$

1,992,660

 

$

4,270,735

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Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

 

2015

 

2015

Reconciliation of net cash provided by operating activities to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

18,573,481

 

 

$

186,719

 

$

1,086,603

 

$

2,713,133

 

$

4,038,018

Interest expense

 

 

791,437

 

 

 

39,307

 

 

424,841

 

 

385,119

 

 

302,118

State income taxes

 

 

 —

 

 

 

 —

 

 

19,848

 

 

(32,199)

 

 

16,970

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

(4,992,897)

 

 

(28,673,166)

 

 

(7,416,747)

Amortization of loan origination costs

 

 

(57,292)

 

 

 

(4,241)

 

 

(46,969)

 

 

(40,965)

 

 

(34,916)

Amortization of tenant improvement allowance

 

 

 —

 

 

 

2,864

 

 

34,369

 

 

14,321

 

 

 —

Unit-based compensation

 

 

(798,413)

 

 

 

(50,422)

 

 

(605,059)

 

 

(605,059)

 

 

(151,265)

Loss on commodity derivative instruments

 

 

(318,829)

 

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues receivable

 

 

1,689,609

 

 

 

(14,551)

 

 

66,455

 

 

(464,877)

 

 

373,644

Other receivables

 

 

236,673

 

 

 

(333,056)

 

 

(1,027,172)

 

 

1,365,099

 

 

(72,742)

Accounts payable

 

 

(316,486)

 

 

 

(247,972)

 

 

952,800

 

 

(1,604,999)

 

 

(77,152)

Other current liabilities

 

 

(1,746,662)

 

 

 

77,442

 

 

(76,541)

 

 

(8,683)

 

 

(27,284)

EBITDA

 

$

18,053,518

 

 

$

(343,910)

 

$

(4,163,722)

 

$

(26,952,276)

 

$

(3,049,356)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,992,897

 

 

28,673,166

 

 

7,416,747

Unit‑based compensation

 

 

798,413

 

 

 

50,422

 

 

605,059

 

 

605,059

 

 

151,265

Loss on commodity derivative instruments

 

 

318,829

 

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Adjusted EBITDA

 

$

19,170,760

 

 

$

(293,488)

 

$

1,434,234

 

$

2,325,949

 

$

4,518,656

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 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data” and related notes included elsewhere in this Annual Report.

On February 8, 2017, we completed our IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests comprising our initial assets were contributed to us by the Contributing Parties, including certain affiliates of our Sponsors at the time of our IPO. As a result, as of December 31, 2016, we had not yet acquired any of such assets.

Unless otherwise indicated in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for periods on or prior to February 7, 2017 refers only to Rivercrest, the predecessor for accounting purposes, and does not include the results of the Partnership as a whole. The interests underlying the oil, natural gas and NGL production revenues of our Predecessor represent approximately 11% of our Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott as of December 31, 2016.

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This discussion contains forward‑lookingforward-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‑lookingforward-looking statements as a result of various factors, including those that may not be in the control of our management. We do not undertake any obligation to publicly update any forward‑lookingforward-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“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. Effective as of September 24, 2018, 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

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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‑productionpost-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 third 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, 2017, Kimbell Royalty Partners, LP2022, we owned mineral and royalty interests in approximately 3.711.5 million gross acres and overriding royalty interests in approximately 24.7 million gross acres, with approximately 35%52% of our aggregate acres located in the Permian Basin. We refer to these non‑cost‑bearing interests collectively as our “mineralBasin and royalty interests.”Mid-Continent. As of December 31, 2017,2022, over 98%99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, (includingincluding approximately 100% of our overriding royalty interests),interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 2028 states and in nearly every major onshore basin across the continental United States and include ownership in over 50,000124,000 gross producing wells, including over 30,00048,000 wells in the Permian Basin.

Our Predecessor is a Delaware limited liability company formed on October 25, 2013Recent Developments

2022 Equity Offering

In November 2022, we completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to own oil, natural gas and NGL mineral and royalty interestspurchase OpCo common units. The Operating Company in turn used the United States. In additionnet proceeds to mineral and royalty interests,repay approximately $116.0 million of the Predecessor’s assets include overriding royalty interests. The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior tooutstanding borrowings under the Partnership’s IPO, secured revolving credit facility.

Acquisitions

On December 15, 2022, we completed the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

Recent Developments

2017 Acquisitions

In the second quarter of 2017, we acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, Hatch Acquisition for an aggregate purchase price of (i) approximately $16.8 million.$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 these acquisitionsthe cash payment of the purchase price with borrowings under its secured revolving credit facility.

On October 9, 2017, we The assets acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On November 8, 2017, we acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

On December 13, 2017, we acquired a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3 million. The core positionsthe Hatch Acquisition are located in Californiathe Permian Basin.

Fourth Quarter Distributions

On February 23, 2023, the Board of Directors declared a quarterly cash distribution of $0.48 per common unit and Wyoming$0.480265 per OpCo common units for the quarter ended December 31, 2022. We intend to pay the distributions on March 16, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on March 9, 2023.

As to us, $0.000265 of the OpCo common unit distribution corresponds to a tax payment made by us in the fourth quarter of 2022. 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.

Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan

On May 18, 2022, the unitholders of the Partnership voted to approve the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”). The A&R LTIP increases the maximum number of common units issuable under the Partnership’s long-term incentive plan by 3,700,000 common units. A summary of the A&R LTIP is described in Proposal One in the Partnership’s definitive proxy statement on Schedule 14A, filed with the SEC on April 4, 2022.

Business Environment

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

Despite improvements in global economic activity levels and higher energy demand compared to 2020 and 2021, the impact of COVID-19 continues to be unpredictable, including the possible impact of new virus strains, the risk of

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renewed restrictions and the package also includes small interests located in Kansas, Arkansas, Texasuncertainty of successful administration of effective treatments and Utah.vaccines. The Partnership funded this acquisition with borrowings underis unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact the Partnership’s business, results of operations, financial condition or cash flows. Commodity prices have risen from 2021; however, further negative impact from COVID-19 may require the Partnership to adjust its secured revolving credit facility.business plans.

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Commodity Derivative Instruments

On November 14, 2017, we entered into an International SwapsCOVID-19 and Derivatives Association, Inc (“ISDA”) Master Agreement (“Master Agreement”) with Frost Bank forthe volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, such as new variants or outbreaks, the length and severity of the worldwide economic downturn, the ability of OPEC and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, decreases in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing in the case of new outbreaks or a resurgence. Although prices have recovered, the impact of COVID-19 on our business, including supply chain concerns, among others continues to affect our industry. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity derivativesprices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of the invasion of Ukraine; however, we will continue to monitor for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively, with a trade date of December 12, 2017.events that could materially impact us.

Business Environment

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. In late 2014, prices forAs noted above, the supply and demand imbalance resulting from the COVID-19 outbreak and various OPEC announcements, the winter storms experienced in parts of the United States in February 2021 and the current conflict between Russia and Ukraine, have created increased volatility in oil and natural gas declined precipitously, and prices remained low throughout 2015 andprices. The table below demonstrates such volatility for the majority of 2016 until rebounding inperiods presented as reported the fourth quarter of 2016. For the year ended December 31, 2017, WTI ranged from a low of $42.48 per Bbl on June 21, 2017 to a high of $60.46 per Bbl on December 29, 2017, and for the year ended December 31, 2016, WTI ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $54.01 per Bbl on December 28, 2016. For the year ended December 31, 2017 the Henry Hub spot market price of natural gas ranged from a low of $2.44 per MMBtu on February 27, 2017 to a high of $3.71 per MMBtu on January 2, 2017, and for the year ended December 31, 2016, the Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.80 per MMBtu on December 7, 2016. United States Energy Information Administration (the “EIA”).

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 2022

​

Year Ended December 31, 2021

​

Year Ended December 31, 2020

​

​

High

    

Low

​

High

    

Low

​

High

    

Low

Oil ($/Bbl)

​

$

123.64

​

$

71.05

​

$

85.64

​

$

47.47

​

$

63.27

​

$

(36.98)

Natural gas ($/MMBtu)

​

$

9.85

​

$

3.46

​

$

23.86

​

$

2.43

​

$

3.14

​

$

1.33

​

On February 26, 2018,6, 2023, the WTI posted price for crude oil was $63.81$74.11 per Bbl and the Henry Hub spot market price of natural gas was $2.60$2.17 per MMBtu.

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

 

 

 

 

 

 

 

 

 

 

 

 

For the Year Ended December 31, 

EIA Average Price:

 

2017

 

2016

 

2015

Oil (Bbl)

 

$

50.80

 

$

43.14

 

$

48.69

Natural gas (MMBtu)

 

$

2.99

 

$

2.52

 

$

2.63

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

 

2020

Oil ($/Bbl)

​

$

94.90

​

$

68.14

​

$

39.16

Natural gas ($/MMBtu)

​

$

6.45

​

$

3.89

​

$

2.03

Source: EIA.

Rig Count

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

The Baker Hughes U.S.United States Rotary Rig count was 929increased 34% to 762 active land rigs at December 31, 2017, a greater than 41% increase from 6582022 compared to 570 active land rigs at December 31, 2016.2021. The 658570 active rig count at December 31, 2016 declined 6% from 6982021 increased significantly compared to 332 active land rigs at December 31, 2015. In addition, according2020. The overall increase in rig count is primarily

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attributable to the Baker Hughes U.S. Rotary Rig count, rig activityan uptake in the 20 statesoil and natural gas market as a result of improved oil and natural gas prices and overall supply shortages.

While the U.S. rig count increased during the year and is now approaching pre-COVID levels, we do not expect significant oil production growth from U.S. operators. A primary reason for this is that the number of DUCs in whichthe United States, one of the best indicators for near-term production growth, has dropped precipitously since 2020. In fact, in the Permian Basin alone, DUCs have dropped from a peak of over 3,500 in July 2020 to just over 1,000 today – levels not seen since 2015. While many companies will focus on replenishing their DUC inventories in the short-term, we own mineralbelieve that inflationary pressures in the drilling, completion and royalty interests increased 44% from 590labor side of their businesses will continue to temper oil production growth during 2023.

The following table summarizes the number of active rigs at December 31, 2016 to 847 active rigs at December 31, 2017. The 590 active rig count at December 31, 2016 declined 6% from 630 active rigs at December 31, 2015. The active rig count acrossoperating on our acreage at December 31, 2017 totaled 19 rigs, a 27% increase compared toby United States basins and producing regions for the 15 rigs at year-end 2016.periods indicated.

​

​

​

​

​

​

​

​

​

December 31, 

Basin or Producing Region

​

2022

​

2021

​

2020

Permian Basin

​

47

​

25

​

17

Mid‑Continent

​

12

​

8

​

7

Terryville/Cotton Valley/Haynesville

​

15

​

12

​

9

Appalachian Basin

​

1

​

1

​

1

Bakken/Williston Basin

​

6

​

6

​

3

Eagle Ford

​

7

​

6

​

1

DJ Basin/Rockies/Niobrara

​

—

​

1

​

1

Other

​

4

​

2

​

—

Total

​

92

​

61

​

39

​

Sources of Our Revenue

Our revenues and our Predecessor’s 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. For the period from February 8, 2017 to December 31, 2017, our revenues were generated 59% from oil sales, 28% from natural gas sales, 11% from NGL sales and 2% from other sales. For the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”), our Predecessor’s revenues were generated 55% from oil sales, 36% from natural gas sales and 9% from NGL sales. For the combined year ended December 31, 2017, the revenues were generated 59% from oil sales, 28% from natural gas sales, 11% from NGL sales and 2% from other sales. For the year ended December 31, 2016, our Predecessor’s revenues were generated 60% from oil sales, 30% from natural gas sales and 10% from NGL sales. For the year ended December 31, 2015, our Predecessor’s revenues were generated 63% from oil

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sales, 29% from natural gas sales and 8% from natural gas liquid sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.prices received.

InThe following table presents the fourth quarterbreakdown of 2017, weour oil, natural gas, and NGL revenues for the following periods:

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

    

2021

    

2020

Revenue

​

​

​

​

​

​

​

​

​

Oil sales

​

46

%

​

50

%

​

56

%

Natural gas sales

​

44

%

​

38

%

​

35

%

NGL sales

​

10

%

​

12

%

​

9

%

​

​

100

%

​

100

%

​

100

%

We have entered into oil and natural gas commodity derivative agreements, with Frost Bank for the years endedwhich extend through December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively. Our Predecessor did not enter into hedging arrangements2024, to establish, in advance, a price for the sale of a portion of the oil and natural gas and NGLs produced from our mineral and royalty interests. As a result,For further discussion on our Predecessor may have realized the benefit of any short‑term increase in the price of oil, natural gas and NGLs, but was not protected against decreases in price, and if the price of oil, natural gas and NGLs decreased significantly, our Predecessor’s business, results of operations and cash available for distribution may have been materially adversely effected.commodity derivative agreements, see “Note 4—Derivatives.”

Reserves and Pricing

The tabletables below identifiesidentify our and our Predecessor’s proved reserves at December 31, 2017, 20162022, 2021 and 2015,2020, 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.

 

 

 

 

 

 

 

Partnership

 

Predecessor

 

December 31, 

 

December 31, 

Estimated Net Proved Reserves:

    

2017

 

2016

    

2015

​

​

​

​

​

​

​

​

​

December 31, 

Estimated Net Proved Reserves

    

2022

​

2021

​

2020

Oil (MBbls)

 

7,463

 

886

 

958

 

12,355

​

12,511

​

12,294

Natural gas (MMcf)

 

63,916

 

7,140

 

7,166

 

160,298

​

157,764

​

144,233

Natural gas liquids (MBbls)

 

2,838

 

235

 

207

 

7,388

​

6,669

​

6,085

Total (MBoe)(6:1)

 

20,954

 

2,311

 

2,359

 

46,459

​

45,474

​

42,418

​

 

 

 

 

 

 

 

 

Partnership

 

Predecessor

 

December 31, 

 

December 31, 

Unweighted Arithmetic Average First‑Day‑of‑the‑Month Prices

    

2017

 

2016

 

2015

​

​

​

​

​

​

​

​

​

​

December 31, 

Unweighted Arithmetic Average First‑Day‑of‑the‑Month Prices

    

2022

​

2021

​

2020

Oil (Bbls)

 

$

51.34

 

$

42.75

 

$

50.28

​

$

93.67

​

$

66.56

​

$

39.57

Natural gas (Mcf)

 

$

2.98

 

$

2.49

 

$

2.59

​

$

6.36

​

$

3.60

​

$

1.99

​

Factors Affecting the Comparability of Our Results to the Historical Results of Our Predecessor

Our Predecessor’s historical financial condition and results of operations may not be comparable, either from period to period or going forward, to the Partnership’sour future financial condition and results of operations, for the reasons described below:below.

No Effect Given to Formation Transactions in Connection with Initial Public OfferingOngoing Acquisition Opportunities

The historical financial statementsAcquisitions are an important part of our Predecessor included in this Annual Report do not reflect the financial condition or resultsgrowth strategy, and we expect to pursue acquisitions of operations of the Partnership. Further, these historical financial statements do not give effect to the transactions that were completed in connection with the closing of the Partnership’s IPO. In connection with our IPO, our Predecessor assigned all of its non‑operating working interests to an affiliate that was not contributed to us, and all of the membership interests of our Predecessor were contributed to us in exchange for common units and a portion of the net proceeds from the IPO. In addition, the Contributing Parties directly or indirectly contributed to us the other assets that made up our initial assets in exchange for common units and a portion of the net proceeds from the IPO. The combination of the assets contributed to us by the Contributing Parties was accounted for at fair value as an asset acquisition. The fair value of the purchase price consideration was based upon the fair value of the common units purchased in the Partnership’s IPO by third-party investors.

The historical financial data of our Predecessor included in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not include the results of the Partnership as a whole and may not provide an accurate indication of what our actual results would have been if the transactions completed in connection with

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our IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. The mineral and royalty interests from third parties, affiliates of our Predecessor only represented approximately 11%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 total future undiscounted cash flows, basedSponsors 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 reserve report prepared by Ryder Scott ascomparability of our results for the years ended December 31, 2016.2022, 2021 and 2020 include the Hatch Acquisition, the Cornerstone Acquisition and the Springbok 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 rules 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.

NoWe did not record an impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. The substantial majority ofon our proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. In accordance with SEC guidance, management determined that the fair value of the properties acquired at the closing of the IPO clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and remained effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired, which could materially adversely affect our results of operations for the periods in which such charges are taken.

No impairment expense was recorded for the Predecessor 2017 Period. During the years ended December 31, 2016 and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline in commodity prices and other factors. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

Credit Agreements

In connection with our IPO, we entered into a new $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. As of December 31, 2017, we had borrowed $30.8 million to fund certain IPO-related transaction expenses, our entrance into a management services agreement with Kimbell Operating and the acquisition of mineral and royalty interests for an aggregate purchase price of approximately $29.3 million. For the period from February 8, 2017 to December 31, 2017, we incurred $0.8 million in interest expense.

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In January 2014, our Predecessor entered into a credit agreement with Frost Bank, as lender. For the Predecessor 2017 Period our Predecessor’s interest expense was de minimis and for the years ended December 31, 20162022 and 20152021. We recorded an impairment on our Predecessor’s interest expense was $0.4 million. Our Predecessor had outstanding borrowingsoil and natural gas properties of $10.6$251.6 million during the year ended December 31, 2020. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas as a result of the continued impact of the external factors mentioned below. As of December 31, 2020, the 12-month average prices of oil and natural gas were $39.57 per Bbl of oil and $1.99 per Mcf of natural gas. These prices represent a 28.9% and 22.9% decrease, respectively, from the 12-month average prices of oil and natural gas as of December 31, 2016. We2019, which were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas.

After evaluating certain external factors in 2020, we determined that we did not assume any indebtednesshave reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties. We similarly recorded an impairment on the value of our Predecessorunevaluated oil and natural gas properties in connection with the2020, which primarily were acquired in various acquisitions since our IPO.

Acquisition Opportunities

Acquisitions are an important partAs of December 31, 2022 and 2021, all of our growth strategy,proved reserves are classified as PDP reserves and we expecthave not, and do not intend to pursue acquisitionsrecord any PUD reserves going forward. Further, if the price of mineraloil, natural gas and royalty interests from our Sponsors, the Contributing Parties and third parties. We alsoNGLs decreases in future periods, we may pursue acquisitions jointly with our Sponsors and the Contributing Parties. Asbe required to record additional impairments as a consequence of any such acquisition and acquisition‑related expense, the historical financial statements of our Predecessor will differ from our financial statements in the future.

Management Services Agreements

In connection with our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with certain entities controlled by affiliates of our Sponsors and Mr. Duncan, 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. 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 unitholders.

Non‑Operated Working Interest Assignment

Prior to the transactions that were completed in connection with the IPO, our Predecessor assigned its non‑operated working interests and associated asset retirement obligations to an affiliated entity that was not contributed to the Partnership. Asresult of the closing of its IPO and through the date of this Annual Report, the Partnership does not own any working interests and does not have any asset retirement obligations or any lease operating expenses as a working interest owner.full-cost ceiling limitation.

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‑productionunit-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. We do not assign any value to unproved properties in which we hold a mineral or royalty interest. 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.

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Marketing and Other Deductions

Marketing and other deductions include product marketing expense, which is a post-production expense. Generally, the terms of the lease governing the development of our properties permit the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

General and Administrative Expense

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits, office expenses and fees for professional services. In connection with our IPO, weWe 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 and Mr. Duncan,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 anticipated incurring incremental generalfinance a portion of our capital requirements and administrative expensesacquisitions with borrowings under our secured revolving credit facility. As a result, we incur interest expense, which is included in our accompanying consolidated statements of approximately $1.5 millionoperations. Please read “Liquidity and Capital Resources—Indebtedness” for further discussion of our secured revolving credit facility.

Income Tax Expense

Effective as of September 24, 2018, the Partnership elected to be taxed as a result of operating as a publicly traded partnership, such as expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K‑1 preparation and distribution expenses, Sarbanes‑Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses.

Income Tax Expense

We are treated as a partnership under the Code, with each partner being separately taxed on its proportionate share of our taxable income; therefore, there will be nocorporation for United States federal income tax expense reflected inpurposes. As a result, we are subject to federal income tax on our financial statements.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 and our Predecessor’s revenue and expenses and production data for the periods indicated.

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Predecessor

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

2017

 

 

2017

 

2016

 

2015

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Operating Results:

 

 

 

 

 

 

 

 

 

 

 

​

​

​

​

​

​

​

​

Revenue

 

 

 

 

 

 

 

 

 

 

 

​

​

​

​

​

​

​

​

Oil, natural gas and NGL revenues

 

$

30,665,092

 

 

$

318,310

 

$

3,606,659

 

$

4,684,923

​

$

281,964,126

​

$

175,088,021

​

$

92,586,685

Loss on commodity derivative instruments

 

 

(318,829)

 

 

 

 —

 

 

 —

 

 

 —

Lease bonus and other income

​

3,073,609

​

​

3,319,104

​

345,771

Loss on commodity derivative instruments, net

​

​

(36,978,550)

​

​

(42,791,909)

​

​

(2,450,541)

Total revenues

 

 

30,346,263

 

 

 

318,310

 

 

3,606,659

 

 

4,684,923

​

​

248,059,185

​

​

135,615,216

​

​

90,481,915

Costs and expenses

 

 

 

 

 

 

 

 

 

 

​

​

​

​

​

​

Production and ad valorem taxes

 

2,452,058

 

 

 

19,651

 

280,474

 

 

426,885

​

 

16,238,814

​

 

10,480,481

​

 

6,389,231

Depreciation, depletion and accretion expense

 

15,546,341

 

 

 

113,639

 

1,604,208

 

 

4,008,730

Depreciation and depletion expense

​

 

50,086,414

​

 

36,797,881

​

 

47,988,796

Impairment of oil and natural gas properties

 

 —

 

 

 

 —

 

4,992,897

 

 

28,673,166

​

 

—

​

 

—

​

 

251,558,557

Marketing and other deductions

 

1,648,895

 

 

 

110,534

 

750,792

 

 

747,264

​

 

13,383,074

​

 

12,048,643

​

 

9,376,375

General and administrative expenses

 

 

8,191,792

 

 

 

532,035

 

 

1,746,218

 

 

1,789,884

​

 

29,128,659

​

 

26,977,519

​

 

25,902,496

Consolidated variable interest entities related:

​

​

​

​

​

​

​

General and administrative expense

​

​

2,304,445

​

 

—

​

​

—

Total costs and expenses

 

 

27,839,086

 

 

 

775,859

 

 

9,374,589

 

 

35,645,929

​

 

111,141,406

​

 

86,304,524

​

 

341,215,455

Operating income (loss)

 

 

2,507,177

 

 

 

(457,549)

 

 

(5,767,930)

 

 

(30,961,006)

​

 

136,917,779

​

 

49,310,692

​

 

(250,733,540)

Other expense

 

 

 

 

 

 

 

 

 

 

 

Other income (expense)

​

​

​

​

​

​

​

Equity income in affiliate

​

2,668,844

​

​

1,119,819

​

763,988

Interest expense

 

 

791,437

 

 

 

39,307

 

 

424,841

 

 

385,119

​

 

(13,818,310)

​

 

(9,182,103)

​

 

(6,430,061)

Income (loss) before income taxes

 

1,715,740

 

 

 

(496,856)

 

(6,192,771)

 

 

(31,346,125)

State income taxes

 

 

 —

 

 

 

 —

 

 

19,848

 

 

(32,199)

Loss on extinguishment of debt

​

—

​

 

—

​

 

(476,350)

Other income (expense)

​

 

4,043,530

​

 

1,263,566

​

(100,000)

Consolidated variable interest entities related:

​

​

​

​

​

​

​

Interest earned on marketable securities in trust account

​

​

3,721,145

​

 

—

​

​

—

Net income (loss) before income taxes

​

133,532,988

​

​

42,511,974

​

(256,975,963)

Income tax expense (benefit)

​

​

2,738,702

​

​

74,100

​

​

(885,193)

Net income (loss)

 

$

1,715,740

 

 

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

​

130,794,286

​

​

42,437,874

​

(256,090,770)

Distribution and accretion on Series A preferred units

​

—

​

​

(11,249,969)

​

(7,810,588)

Net (income) loss and distributions and accretion on Series A preferred units attributable to non-controlling interests in OpCo

​

(18,822,552)

​

​

(8,496,104)

​

96,642,334

Distribution on Class B units

​

​

(42,243)

​

​

(76,780)

​

​

(91,869)

Net income (loss) attributable to common units of Kimbell Royalty Partners, LP

​

$

111,929,491

​

$

22,615,021

​

$

(167,350,893)

Production Data:

 

 

 

 

 

 

 

 

 

 

​

​

​

​

​

​

Oil (Bbls)

 

379,182

 

 

 

3,696

 

55,587

 

 

59,321

​

 

1,425,842

​

 

1,343,771

​

 

1,409,163

Natural gas (Mcf)

 

3,184,861

 

 

 

32,961

 

496,778

 

 

548,386

​

 

20,310,991

​

 

19,085,400

​

 

17,891,384

Natural gas liquids (Bbls)

 

157,177

 

 

 

1,220

 

22,360

 

 

22,351

​

 

746,865

​

 

714,494

​

 

681,575

Combined volumes (Boe) (6:1)

 

1,067,169

 

 

 

10,410

 

160,743

 

 

173,070

​

 

5,557,872

​

 

5,239,165

​

 

5,072,635

​

Comparison of the Year Ended December 31, 20172022 to the Year Ended December 31, 20162021 and the Year Ended December 31, 20162021 to the Year Ended December 31, 20152020

The period presented forOil, Natural Gas and NGL Revenues

For the year ended December 31, 2017 includes the results of operations of2022, our Predecessor for the Predecessor 2017 Period and our results of operations for the period from February 8, 2017 to December 31, 2017.

Oil, Natural Gas and Natural Gas Liquids Revenues

For the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, our and our Predecessor’s oil, natural gas and NGL revenues were $30.7$282.0 million, and $0.3an increase of $106.9 million respectively, for combined revenues of $31.0from $175.1 million for the year ended December 31, 2017,2021. 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 of $27.4in production volumes for the year ended December 31, 2022 as discussed below.

Our revenues for the year ended December 31, 2021 increased by $82.5 million, from $3.6$92.6 million for the year ended December 31, 2016.2020. The significant increase in oil, natural gas and NGL revenues was primarily duerelated to the $247.8 million acquisition

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increase in the average prices we received for oil, natural gas and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevantNGL production, and revenues from those acquired interests.

Our Predecessor’s revenuesto a lesser extent, an increase in production volumes for the year ended December 31, 2016 decreased by $1.1 million, from $4.7 million for the year ended December 31, 2015. Our Predecessor’s decrease in revenues was primarily due to the industry-wide steep declines in the price of oil, natural gas and natural gas liquids experienced through most of 2016, coupled with a decrease in production for the year ended December 31, 2016 of 12,327 Boe when compared to production for the year ended December 31, 2015.

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2021 as discussed below.

Our and our Predecessor’s revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,067,1695,557,872 Boe or 3,264 Boe/d and 10,410 Boe or 274 Boe/d, for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period, respectively. The combined production for the year ended December 31, 2017 was 1,077,579 Boe or 2,952 Boe/d, an increase of 916,836 Boe or 2,512 Boe/d, from 160,743 Boe or 440 Boe/d, for year ended December 31, 2016.

Our Predecessor’s volumes for the year ended December 31, 2016 decreased by 12,326 or 34 Boe/d from 173,070 or 47415,025 Boe/d, for the year ended December 31, 2015. This decrease2022, an increase of 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, 2016 when compared2022 was primarily attributable to production associated with the Cornerstone Acquisition, which included a full year of production for the year ended December 31, 2015 was primarily due2022, compared to decreased drilling on our Predecessor’s interests duringapproximately three months of production for the year ended December 31, 2016 due2021, and to a lesser extent, production associated with the industry wide steep declinesHatch Acquisition.

Our production volumes for the year ended December 31, 2021 increased by 166,530 Boe or 494 Boe/d, from 5,072,635 Boe or 13,860 Boe/d, for the year ended December 31, 2020. The increase in production for the priceyear ended December 31, 2021 was primarily attributable to production associated with the Springbok Acquisition, which included a full year of oil, natural gas and NGLs experienced through mostproduction for the year ended December 31, 2021, compared to approximately eight months of 2016.production for the year ended December 31, 2020.

Our operators received an average of $47.08$91.74 per Bbl of oil, $2.74$6.04 per Mcf of natural gas and $21.50 per Bbl of NGL for the volumes sold during the period from February 8, 2017 to December 31, 2017. Our Predecessor’s operators received an average of $47.04 per Bbl of oil, $3.47 per Mcf of natural gas and $24.61 per Bbl of NGL for the volumes sold during the Predecessor 2017 Period. For the combined year ended December 31, 2017, the operators received an average of $47.08 per Bbl of oil, $2.74 per Mcf of natural gas and $21.52 per Bbl of NGL for the volumes sold. Average prices received by the operators during the combined year ended December 31, 2017 increased 21.7% or $8.39 per Bbl of oil and 24.0% or $0.53 per Mcf of natural gas as compared to our Predecessor’s operators which received an average of $38.69 per Bbl of oil, $2.21 per Mcf of natural gas and $15.99$38.19 per Bbl of NGL for the volumes sold during the year ended December 31, 2016 These increases are2022 and $64.86 per Bbl of oil, $3.51 per Mcf of natural gas and $29.33 per Bbl of NGL for the volumes sold during the year ended December 31, 2021. 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. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increasesincrease of 17.8%39.3% or $7.66$26.76 per Bbl of oil and 18.7%65.8% or $0.47$2.56 per Mcf of natural gas for the comparable periods.

Our Predecessor’s operators received an average of $49.79 per Bbl of oil, $2.44 per Mcf of natural gas and $17.56 per Bbl of NGL for the volumes sold during the year ended December 31, 2015. Average prices received by the Predecessor’sour operators during the year ended December 31, 2016 decreased 22.2%2020 increased 75.4% or $11.10$27.88 per Bbl of oil and 9.4%96.1% or $0.23$1.72 per Mcf of natural gas as compared to the year ended December 31, 2015.2020, which our operators received an average of $36.98 per Bbl of oil, $1.79 per Mcf of natural gas and $12.39 per Bbl of NGL. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 74.0% or $28.98 per Bbl of oil and 91.6% or $1.86 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income remained relatively flat at $3.1 million for the year ended December 31, 2022, compared to $3.3 million for the year ended December 31, 2021.

Our lease bonus and other income for the year ended December 31, 2021 increased by $3.0 million, from $0.3 million for the year ended December 31, 2020. The increase in lease bonus and other income is primarily related to a $1.5 million lease bonus received during the year ended December 31, 2021, related to properties in the Permian Basin, and also due to the volatility and uncertainty experienced in the oil and gas market for the 2020 period, which discouraged operators from drilling new wells.

​

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the year ended December 31, 2022 included $16.0 million of mark-to-market gains and $53.0 million of losses on the settlement of commodity derivative instruments compared to $22.1 million of mark-to-market losses and $20.7 million of losses on the settlement of commodity derivative instruments for the year ended December 31, 2021. 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, 2020 included $7.1 million of mark-to-market losses and $4.6 million of gains on the settlement of commodity derivative instruments.

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Production and Ad Valorem Taxes

Our production and ad valorem taxes for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $2.5 million and $0.02 million, respectively. The combined productionProduction and ad valorem taxes for the year ended December 31, 20172022 were $2.5$16.2 million, an increase of $2.2$5.7 million from $0.3$10.5 million for the year ended December 31, 2016.2021. The increase in production and ad valorem taxes was primarily attributable to the $247.8 million acquisition of various mineralincrease in the average prices we received for oil, natural gas and royalty interests fromNGL production for the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineralyear ended December 31, 2022, and royalty interests throughout the 2017 period and the relevantto a lesser extent, production and revenues from those acquired interests.ad valorem taxes associated with the Cornerstone Acquisition.

For the year ended December 31, 2016, our Predecessor’s2021, production and ad valorem taxes decreasedincreased by $0.1$4.1 million from $0.4$6.4 million for the year ended December 31, 2015.2020. The decreaseincrease in production and ad valorem taxes was primarily attributable to a declinethe increase in the average prices we received for oil, natural gas and natural gas liquids prices.NGL production for the year ended December 31, 2021, and to a lesser extent, production and ad valorem taxes associated with the Springbok Acquisition.

Depreciation and Depletion Expense

Depreciation Depletion and Accretion Expense

Our and our Predecessor’s depreciation, depletion and accretion expense for the period from February 8, 2017 toyear ended December 31, 2017 and the Predecessor 2017 Period2022 was $15.5$50.1 million, and $0.1an increase of $13.3 million respectively, for a combined expense of $15.6from $36.8 million for the year ended December 31, 2017. This2021. The increase in depreciation and depletion expense was an increase of $14.0due to the Cornerstone Acquisition and the Hatch Acquisition, which significantly increased our net capitalized oil and natural gas properties.

For the year ended December 31, 2021, depreciation and depletion expense decreased by $11.2 million from our Predecessor’s depreciation, depletion and accretion expense of $1.6$48.0 million for the year ended December 31, 2016.2020. The increasedecrease in the depreciation depletion and accretiondepletion expense was primarily attributabledue to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired properties.

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Our Predecessor’s depreciation, depletion and accretion expense decreased by $2.4 million forimpairment that was recorded during the year ended December 31, 2016 from $4.0 million for the year ended December 31, 2015.2020, which significantly reduced 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 units‑of‑productionunit-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. Our and our Predecessor’s average depletion rate per barrel was $14.43 and $10.31$8.84 for the period from February 8, 2017 toyear ended December 31, 2017 and2022, an increase of $2.06 per barrel from the Predecessor 2017 Period, respectively. The combined$6.78 average depletion rate per barrel for the year ended December 31, 20172021. The increase in our average depletion rate per barrel was $14.39, an increase of $4.53due to the Cornerstone Acquisition and the Hatch Acquisition, which collectively increased our net capitalized oil and natural gas properties.

For the year ended December 31, 2021, our average depletion rate per barrel decreased by $2.61 per barrel from anthe $9.39 average depletion rate of $9.86 per barrel for the year ended December 31, 2016.2020. The increasedecrease in the average depletion rate per barrel was primarily attributabledue to the $247.8 million acquisition of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production from those acquired properties.

Forsignificant impairment that was recorded during the year ended December 31, 2016,2020 which significantly reduced our Predecessor’s average depletion rate per barrel decreased by $13.30 from $23.16 for the year ended December 31, 2015. The decrease in the average depletion rate per barrel was primarily attributable to a $28.7 million impairment recorded onnet capitalized oil natural gas and natural gas liquids properties in 2015, which resulted in a lower depletable base in oil, natural gas and NGL properties for the year ended December 31, 2016.properties.

Impairment of Oil, Natural Gas and Natural Gas LiquidsNGL Expense

NoWe did not record an impairment expense was recordedon our oil and natural gas properties for the period from February 8, 2017 toyears ended December 31, 2017. See “Factors2022 and 2021. We recorded an impairment expense on our oil and natural gas properties of $251.6 million during the year ended December 31, 2020, as the result of the continued decline in the 12-month average price of oil and natural gas, in each case as further described under “—Factors Affecting the Comparability of Our Results to theOur Historical Results of Our Predecessor―Results—Impairment of Oil and Natural Gas Properties” for a discussion regarding the exemption of impairment of oil and natural gas properties for the Partnership for the period from February 8, 2017 to December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired.Properties.”

Impairments for our Predecessor totaled $5.0 million and $28.7 million for the years ended December 31, 2016 and 2015, respectively, primarily due to the impact that declines in commodity prices had on the value of reserve estimates.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post‑production expense, and our Predecessor’s marketing and other deductions also include lease operating expenses related to its non‑operated working interests.post-production expense. Marketing and other deductions for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $1.6 million and $0.1 million, respectively. The combined marketing and other deductions for the year ended December 31, 20172022 were $1.7$13.4 million, an increase of $0.9$1.4 million from our Predecessor’s marketing$12.0 million for the year ended December 31, 2021, which was primarily attributable to the increase in prices for oil, natural gas and NGL production.

Marketing and other deductions for the year ended December 31, 2016 of $0.8 million.2021 increased by $2.6 million from $9.4 million for the year ended December 31, 2020. The increase in marketing and other deductions was primarily attributable the $247.8 million acquisitionincrease in prices for oil, natural gas and NGL production.

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Table of various mineral and royalty interests from the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.Contents

Our Predecessor’s marketing and other deductions for the year ended December 31, 2016 increased by $0.1 million from $0.7 million for the year ended December 31, 2015.

General and Administrative Expense

Our and our Predecessor’s general and administrative expenses for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $8.2 million and $0.5 million, respectively. General and administrative expenses for the combined year ended December 31, 2017 were $8.7 million, an increase of $7.0 million from our Predecessor’s general and administrative expenses of $1.7 million for year ended December 31, 2016. The increase in general and administrative expenses was attributable to the increased costs related to operating the Partnership as a publicly traded entity.

Our Predecessor’s general and administrative expenses for the year ended December 31, 2016 decreased by $0.12022 were $29.1 million, an increase of $2.1 million from $1.8$27.0 million for the year ended December 31, 2015. Decreases2021. The increase in general and administrative expenses

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were was primarily attributable to the decrease in costslegal and professional fees incurred related to the offeringspecial 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.

General and administrative expenses for the year ended December 31, 2015 to the year ended December 31, 2016.

Interest Expense

Our and our Predecessor’s interest expense for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period was $0.8 million and $0.04 million, respectively. The interest expense for the combined year ended December 31, 2017 was $0.8 million as2021 remained relatively flat compared to our Predecessor’s interest expense of $0.4$25.9 million for the year ended December 31, 2016.2020.

Our Predecessor’sInterest Expense

Interest expense for the year ended December 31, 2022 was $13.8 million as compared to interest expense remained relatively flat at $0.4of $9.2 million for the yearsyear ended December 31, 20162021. 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 2015.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.

Interest expense for the year ended December 31, 2021 increased by $2.8 million as compared to interest expense of $6.4 million for the year ended December 31, 2020. The increase in interest expense was primarily due to borrowings on the secured revolving credit facility during 2021 to fund the redemption of the Series A preferred units.

Income Tax Expense (Benefit)

For the year ended December 31, 2022, we recognized an income tax expense of $2.7 million, resulting in an effective tax rate of 2.05%, compared to income tax expense of $0.1 million for the year ended December 31, 2021, resulting in an effective tax rate of 0.17%. We recognized an income tax benefit of $0.9 million for the year ended December 31, 2020, resulting in an effective tax rate of 0.34%. The overall change in our effective tax rate for the year ended December 31, 2022 is primarily due estimated current federal income tax that cannot be sheltered by a net operating loss carryforward.

Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of December 31, 2022 and 2021, we recorded a full valuation allowance on our deferred tax assets. 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 for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. We have entered into a $50.0 million secured revolving credit facility with an accordion feature permitting aggregate commitments under the facility to be increased up to $100.0 million (subject to the satisfactionSee “Indebtedness” below for further discussion of certain conditions and the procurement of additional commitments from new or existing lenders), to initially be used for general partnership purposes, including working capital, acquisitions and certain IPO-related transaction expenses. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million, providing for maximum availability under the secured revolving credit facility of $50.0 million. As of March 2, 2017, we had an outstanding balance of $30.8 million under our secured revolving credit facility.

OurCash 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 less reserves established byin an amount equal to our General Partner. We refer to thisavailable cash as “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

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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 or approximate ourits 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 including replacementthat 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 growth capital expenditures,needs that the Board of Directors may determine is appropriate.

UnlikeThe Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the fourth quarter of 2022 for the repayment of $13.1 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the fourth quarter of 2022. With respect to future quarters, the Board of Directors intends to continue to allocate a numberportion 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 master limited partnerships, wemanners 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 generallycurrently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to retain cash from our operations for capital expenditures necessaryincur debt to replace our existing oil and natural gas reserves or otherwise maintain our asset base (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. If they believe it is warranted,pay quarterly distributions, although the Board of Directors may withhold replacement capital expenditures from cash available for distribution, which would reduce the amount of cash available for distribution in the period(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.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, althoughsecurities. For example, we issued 7,272,821 OpCo common units and an equal number of Class B units as partial consideration in connection with the Hatch Acquisition. 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, or(ii) otherwise reserve cash for distributions or to(iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.

Because our partnership agreement will require us to distribute an amount equal to all available cash we generate each quarter, our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount See “Recent Developments—Fourth Quarter Distributions” above for discussion of our quarterly distributions, if any, will fluctuate based on variations in, among other factors,

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(i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGL, changes to working capital or capital expenditures and (iii) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of our quarterly distributions may be significant and could result in our not making any distribution for any particular quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The Board of Directors may change our distribution policy at any time at its discretion, without unitholder approval, and could elect not to pay distributions for one or more quarters.fourth quarter 2022 distributions.

On May 2, 2017, the Board of Directors declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The Partnership’s calculated cash available for distribution was $0.18 per common unit for the quarter. However, during the period ended March 31, 2017, pursuant to the contribution agreement entered into by the Contributing Parties prior to the IPO, the Partnership received cash from the Contributing Parties for oil, natural gas and NGL production for periods prior to the IPO. The Board of Directors voted to distribute an additional $0.05 per common unit. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017.

On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The Partnership’s calculated cash available for distribution was $0.28 per common unit for the quarter.  The Board of Directors voted to distribute an additional $0.02 per common unit due to excess working capital generated primarily from positive prior period production from our operators. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017.

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution was paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

On January 26, 2018, the Board of Directors declared a quarterly cash distribution of $0.36 per common unit for the quarter ended December 31, 2017. The distribution was paid on February 14, 2018 to unitholders of record as of the close of business on February 7, 2018.

Cash Flows

The following table presents our and our Predecessor’s cash flows for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

 

2015

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows provided by operating activities

 

$

18,573,481

 

 

$

186,719

 

$

1,086,603

 

$

2,713,133

Cash flows used in investing activities

 

 

(125,910,708)

 

 

 

(523)

 

 

(97,464)

 

 

(538,640)

Cash flows provided by (used in) financing activities

 

 

112,962,722

 

 

 

 —

 

 

(863,000)

 

 

(2,062,818)

Net increase in cash

 

$

5,625,495

 

 

$

186,196

 

$

126,139

 

$

111,675

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

   

2021

​

2020

Cash Flow Data:

​

​

​

​

​

​

​

​

​

Net cash provided by operating activities

​

$

166,636,493

​

$

91,442,481

​

$

62,245,341

Net cash used in investing activities

​

 

(374,723,901)

​

 

(55,572,551)

​

 

(90,827,734)

Net cash provided by (used in) financing activities

​

 

226,061,562

​

 

(38,622,493)

​

 

24,183,120

Net increase (decrease) in cash and cash equivalents

​

$

17,974,154

​

$

(2,752,563)

​

$

(4,399,273)

Operating Activities

Our and our Predecessor’s operatingOperating cash flow is impacted by many variables, the most significant of which isare the changechanges 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.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 and our Predecessor’s control and are difficult to predict. Cash flows provided by operating activities for the period from February 8, 2017 to December 31, 2017 and the Predecessor 2017 Period were $18.6 million and $0.2 million, respectively. Cash flows provided by operating activities for the combined year ended December 31, 20172022 were $18.8$166.6 million, an increase of $17.7$75.2 million compared to our Predecessor’s cash flows provided by operating activities of $1.1$91.4 million for the year ended December 31, 2016.2021. The

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increase in cash flows provided by operating activities was largelyprimarily attributable to the $247.8 million acquisition of various mineralincrease in the average prices we received for oil, natural gas and royalty interests fromNGL production for the Contributing Parties at the closing of our IPO, the $29.3 million acquisition of various mineral and royalty interests throughout the 2017 period and the relevant production and revenues from those acquired interests.year ended December 31, 2022.

The decreases in cashCash flows provided by operating activities for the year ended December 31, 2016 as2021 increased by $29.2 million compared to $62.2 million for the year ended December 31, 20152020. The increase in cash flows provided by operating

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Table of $1.6 million were largelyContents

activities was primarily attributable to lowerthe increase in the average prices we received for oil, natural gas and NGL sales prices.

Investing Activities

Cash flows used in investing activitiesproduction for the period from February 8, 2017 toyear ended December 31, 2017 were $125.9 million, an increase of $125.8 million compared to our Predecessor’s cash2021.

Investing Activities

Cash flows used in investing activities for the year ended December 31, 2016 of $0.1 million. Our Predecessor’s cash flows used in investing activities2022 were de minimis for the Predecessor 2017 Period. For the period from February 8, 2017 to December 31, 2017, we used the $96.2$374.7 million in proceeds received from our IPO to pay the cash portion of our acquisition of oil and natural gas properties at the IPO and we used $29.3 million to fund the acquisition of various mineral and royalty interests. The purchase of interests in producing oil and gas properties and office equipment accounted for our Predecessor’s cash outlays for investing activities.

For the year ended December 31, 2016, our Predecessor used $0.1 million for investing activities compared to $0.5$55.6 million for the year ended December 31, 2015. The $0.4 million decrease was due to less drilling activity on our Predecessor’s working interest properties during2021. Cash flows used in investing activities for the year ended September 30, 2016.

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

Cash flows provided by financingused in investing activities was $113.0 million for the period from February 8, 2017year ended December 31, 2017 as2021 increased by $35.2 million compared to our Predecessor’s cash flows used in financingused in investing activities of $0.9$90.8 million for the year ended December 31, 2016. Our Predecessor did not have any cash2020. For the year ended December 31, 2020, we used $87.6 million primarily to fund the Springbok Acquisition, $2.2 million to fund the capital commitments of the Joint Venture and $1.0 million to fund the remodel of office space.

Financing Activities

Cash flows used in or provided by financing activities for the Predecessor 2017 Period. During the period from February 8, 2017 to December 31, 2017, we received $96.2 million in proceeds from our IPO, we borrowed $30.8 million, paid a distribution to unitholders of $13.8 million and paid loan origination costs of $0.3 million.

Cash used in financing activities was $0.9were $226.1 million for the year ended December 31, 2016 as2022 compared to $38.6 million of cash flows used in financing activities of $2.1 million for the year ended December 31, 2015. During the year ended December 31, 2016, our Predecessor repaid $0.9 million of long-term debt. Our Predecessor borrowed $3.0 million in long-term debt, offset2021. Cash flows provided by $4.5 million in distributions to members and repayments on long-term debt of $0.6 million,financing activities for the year ended December 31, 2015.2022 consists of $227.6 million in proceeds from the TGR IPO (these proceeds are held in trust for the benefit of public stockholders and not available to KRP), $199.2 million of additional borrowings under our secured revolving credit facility, $116.1 million in proceeds from the 2022 Equity Offering and $0.4 million in contributions from Class B unitholder, partially offset by $183.3 million used to repay borrowings under out secured revolving credit facility, $126.8 million of distributions paid to holders common units, OpCo common units and Class B units, $3.3 million of restricted units repurchased for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units and $0.7 million payment of loan origination costs.

Capital Expenditures

DuringCash flows used in financing activities for the period from February 8, 2017 toyear ended December 31, 2017, we acquired mineral2021 consists of $71.7 million of distributions paid to holders of common units and royalty interestsOpCo 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 Contributing Parties2021 Equity Offering and $136.6 million of additional borrowings under our secured revolving credit facility.

Cash flows provided by financing activities for the year ended December 31, 2020 consists of $162.6 million of additional borrowings under our secured revolving credit facility and $73.6 million in proceeds from the 2020 Equity Offering. Cash flows provided by financing activities for the year ended December 31, 2020 were partially offset by $91.2 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units, $54.9 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, $4.5 million paid in connection with a total value atamending our secured revolving credit facility and $0.4 million paid in connection with the IPOredemption of $169.1 million and $96.2 million in cash. Additionally, we spent an aggregate amount of $29.3 million for the acquisition of various mineral and royalty interests.Class B units.

Capital Expenditures

During the year ended December 31, 2016, our Predecessor spent $0.12022, we paid approximately $141.3 million on lease and well equipment relatedprimarily to our working interests and office equipment.fund the Hatch Acquisition. During the year ended December 31, 2015, our Predecessor spent $0.52021, we paid approximately $55.3 million, on additional costs fromwhich was primarily

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attributable to the 2014 acquisitionscompletion of interests, lease and well equipment and intangible drilling costs relatedthe Cornerstone acquisition. During the year ended December 31, 2020, we paid approximately $87.6 million primarily to fund with the Springbok Acquisition.

Indebtedness

On December 15, 2022, we entered into Amendment No. 4 (the “Fourth Credit Agreement Amendment”) to our working interestsexisting Credit Agreement, dated as of January 11, 2017 (as amended by that certain Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, and office equipment.

Indebtedness

Revolvingthat certain Amendment No. 2 to Credit Agreement,

We entered into a $50.0 million revolving credit facility in connection with our IPO, which is secured by substantially all dated as of our assetsDecember 8, 2020, and that certain Amendment No. 3 to Credit Agreement, dated as of June 7, 2022, and as otherwise amended or modified prior to such date, the “Credit Agreement” and the assetsCredit Agreement, as amended by the Fourth Credit Agreement Amendment, the “Amended Credit Agreement”), with certain subsidiaries of our wholly owned subsidiaries. Under the Partnership, as guarantors, the lenders party thereto and Citibank as administrative agent.

The Fourth Credit Agreement Amendment amended the Credit Agreement to, among other things, (i) increase the aggregate elected commitments under the Amended Credit Agreement’s senior secured revolving credit facility availability under the facility will equal the lesser of the aggregate maximum commitments of the lenders(the “Credit Facility”) and the borrowing base. The borrowing base will be re-determined semiannually on February 1 and August 1 of each year based

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on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries and will mature on February 8, 2022. The secured revolving credit facility permits aggregate commitments under the facility to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. In connection with the February 1, 2018 redetermination under the secured revolving credit facility,(ii) the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0Credit Facility, in each case, from $300.0 million to $350.0 million.

The secured revolving credit facilityAmended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, 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. The secured revolving credit facilityAmended Credit Agreement 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 more fully defined in the secured revolving credit facility) of not more than 4.03.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facilityAmended Credit Agreement also contains customary events of default, including non‑payment,non-payment, breach of covenants, materially incorrect representations, cross‑cross default, bankruptcy and change of control. As of March 2, 2018,December 31, 2022, we had outstanding borrowings of $233.0 million under the secured revolving credit facility and $117.0 million of available capacity.

The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after September 30, 2023. In response, our secured revolving credit facility has transitioned to the use of the SOFR published by the Federal Reserve Bank of New York in replacement of LIBOR.

For additional information on our Amended Credit Agreement, please read Note 8―Long-Term Debt to the consolidated financial statements included in Item 8 of 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 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 2022. 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

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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 borrowed $30.8 millionadopted 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 fund certain IPO-related transaction expenses, our entrance into a management services agreementconsult with Kimbell Operating Company, LLC and the acquisition of various mineral and royalty interests for an aggregate purchase price of approximately $29.3 million.your tax advisor on this matter. Please read “Item 1A. Risk Factors—Tax Risks” elsewhere in this Annual Report.

Contractual Obligations and Off-Balance Sheet Arrangements

As of December 31, 2017, neither we nor our Predecessor had any off-balance sheet arrangements other than operating leases. The following table summarizes the contractual obligations of the Partnership as of December 31, 2017:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

Less than

    

 

 

    

 

 

    

More than 5

 

 

Total

 

1 year

 

1‑3 years

 

3‑5 years

 

years

Long-term debt

 

$

30,843,593

 

$

 -

 

$

 -

 

$

30,843,593

 

$

 -

Operating leases

 

 

429,220

 

 

127,506

 

 

221,306

 

 

80,408

 

 

 -

Total

 

$

31,272,813

 

 

127,506

 

$

221,306

 

$

30,924,001

 

$

 -

New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we chose to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non‑emerging growth companies. Our election to “opt out” of the extended transition period is irrevocable.

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

Critical Accounting PoliciesEstimates

The discussion and analysis of our financial condition and results of operations are based upon the historicalour consolidated financial statements, of our Predecessor, which have been prepared in accordance with GAAP.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. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change. Below, we have provided expanded discussion of our more significant accounting policies.estimates.

See the notesNote 2—Summary of Significant Accounting Policies to our and our Predecessor’s financial statements included elsewhere in this Annual Report for additional information regarding these accounting policies.

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Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated byfor a summary of our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.significant accounting policies.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, valuation of commodity derivative financial instruments and equity‑based compensation.

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 plus estimated future development 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.reserves, which is primarily based upon when such properties become producing. We assess all items classified as unevaluated property on an annuala periodic basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: the operators’ intent to drill; remaining lease term; geological and geophysical evaluations; the operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to datecarrying 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.amortization or potential impairment.

Oil, Natural Gas and Natural Gas LiquidsNGL Reserve Quantities and Standardized Measure of Future Net Revenue

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

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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

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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‑productionpost-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 associated productsale is sold.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.

Derivatives and Financial Instruments

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. From time to time, such contracts may include fixed-price contracts, variable to fixed price swaps, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately record.

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. Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. We have not designated any of our derivative contracts as hedges for accounting purposes. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.

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‑month12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first‑day‑of‑the‑monthfirst-day-of-the-month prices for the prior 12‑month12-month period and costs used are those as of the end of the appropriate quarterlyreporting period.

Accounting for Unit‑Based Compensation

We measure unit‑based compensation grants at their grant date fair value and related compensation expense is recognized over the vesting period of the grant. The fair value of our restricted units issued under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) to our employees and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The LTIPand related accounting policies are defined and described more fully in Note 9—Unit-Based Compensation in our audited consolidation financial statements included elsewhere in this Annual Report.

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the period from January 1, 2014 through December 31, 2016.

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 this volatilitycommodity prices to continuebe even more volatile in the future.future as a result of COVID-19 and its variants, 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

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contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.

At December 31, 2017, ourOur commodity derivative contracts consistedconsist of fixed price swaps, under which the Partnership receiveswe receive a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. We hedge our daily production based on the amount of debt and/or preferred equity as a percent of our enterprise value. As of December 31 2022, these economic hedges constituted approximately 21% of our daily oil and natural gas production.

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 in Item 8 of this reportAnnual Report for additional information regarding the Partnership’sour 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, 2017,2022, we had one counterparty,three counterparties to our derivative contracts, which isare also the lenderlenders 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 period from February 8, 2017 toyears ended December 31, 2017, one2022, 2021 and 2020, our top purchaser accounted for approximately 14%11.3%, 6.0% and 7.1%, respectively, of our oil, natural gas and NGL revenues. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of our Predecessor’s 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, 2017,2022, we had total borrowings outstanding under our secured revolving credit facility of $30.8$233.0 million. The impact of a 1% increase in the interest rate on this amount of debt would resulthave resulted in an increase in interest expense of approximately $0.3$2.3 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any

On January 27, 2021, we entered into an interest rate hedgesswap 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 place.

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

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Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2020 through December 31, 2022. 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, non cash unit based compensation, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income. 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 (loss) and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated.

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:

​

​

​

​

​

​

​

​

​

Net income (loss)

​

$

130,794,286

​

$

42,437,874

​

$

(256,090,770)

Depreciation and depletion expense

​

​

50,086,414

​

​

36,797,881

​

​

47,988,796

Interest expense

​

​

13,818,310

​

​

9,182,103

​

​

6,430,061

Cash distribution from affiliate

​

​

385,326

​

​

1,015,559

​

​

812,810

Income tax expense (benefit)

​

​

2,738,702

​

​

74,100

​

​

(885,193)

EBITDA

​

​

197,823,038

​

​

89,507,517

​

​

(201,744,296)

Impairment of oil and natural gas properties

​

​

—

​

​

—

​

​

251,558,557

Unit-based compensation

​

​

11,107,639

​

​

10,632,725

​

​

9,261,756

Loss on extinguishment debt

​

​

—

​

​

—

​

​

476,350

(Gain) loss on derivative instruments, net of settlements

​

​

(14,300,570)

​

​

20,343,783

​

​

7,085,364

Cash distribution from affiliate

​

​

645,451

​

​

500,389

​

​

—

Equity income in affiliate

​

​

(2,668,844)

​

​

(1,119,819)

​

​

(763,988)

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Interest earned on marketable securities in trust account

​

​

(3,721,145)

​

​

—

​

​

—

General and administrative expenses

​

​

2,304,445

​

​

—

​

​

—

Consolidated Adjusted EBITDA

​

​

191,190,014

​

​

119,864,595

​

​

65,873,743

Adjusted EBITDA attributable to non-controlling interest

​

​

(27,154,867)

​

​

(35,608,960)

​

​

(23,914,812)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

​

​

164,035,147

​

​

84,255,635

​

​

41,958,931

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

​

​

​

​

​

​

​

​

​

Cash interest expense

​

​

9,583,004

​

​

5,297,810

​

​

3,399,655

Cash distributions on Series A preferred units

​

​

—

​

​

1,943,385

​

​

3,047,466

Restricted units repurchased for tax withholding

​

​

—

​

​

1,433,265

​

​

—

Cash income tax expense

​

​

3,082,245

​

​

—

​

​

—

Distributions on Class B units

​

​

42,243

​

​

76,780

​

​

91,869

Cash available for distribution on common units

​

$

151,327,655

​

$

75,504,395

​

$

35,419,941

​

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​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:

​

​

​

​

​

​

​

​

​

Net cash provided by operating activities

​

$

166,636,493

​

$

91,442,481

​

$

62,245,341

Interest expense

​

 

13,818,310

​

 

9,182,103

​

 

6,430,061

Income tax expense (benefit)

​

​

2,738,702

​

​

74,100

​

​

(885,193)

Impairment of oil and natural gas properties

​

 

—

​

 

—

​

 

(251,558,557)

Amortization of right-of-use assets

​

​

(319,674)

​

 

(298,093)

​

​

(276,180)

Amortization of loan origination costs

​

 

(1,872,700)

​

 

(1,556,769)

​

 

(1,108,685)

Loss on extinguishment of debt

​

​

—

​

 

—

​

 

(476,350)

Equity (loss) income in affiliate, net

​

 

(716,481)

​

 

1,119,819

​

 

763,988

Forfeiture of restricted units

​

​

19,813

​

​

—

​

​

127,934

Unit-based compensation

​

 

(11,107,639)

​

 

(10,632,725)

​

 

(9,261,756)

Gain (loss) on derivative instruments, net of settlements

​

 

14,300,570

​

 

(20,343,783)

​

 

(7,085,364)

Changes in operating assets and liabilities:

​

​

​

​

​

​

​

​

​

Oil, natural gas and NGL receivables

​

 

11,846,567

​

 

17,594,389

​

 

(1,618,006)

Accounts receivable and other current assets

​

 

511,319

​

 

2,077,637

​

 

897,088

Accounts payable

​

 

(399,318)

​

 

77,716

​

 

319,001

Other current liabilities

​

 

(1,590,016)

​

 

463,828

​

 

(533,582)

Operating lease liabilities

​

​

324,913

​

 

306,814

​

​

275,964

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Interest earned on marketable securities in trust account

​

​

3,721,145

​

 

—

​

​

—

Other assets and liabilities

​

​

(88,966)

​

 

—

​

​

—

EBITDA

​

​

197,823,038

​

​

89,507,517

​

​

(201,744,296)

Add:

​

​

​

​

​

​

​

​

​

Impairment of oil and natural gas properties

​

 

—

​

 

—

​

 

251,558,557

Unit-based compensation

​

 

11,107,639

​

 

10,632,725

​

 

9,261,756

Loss on extinguishment of debt

​

​

—

​

​

—

​

​

476,350

(Gain) loss on derivative instruments, net of settlements

​

 

(14,300,570)

​

 

20,343,783

​

 

7,085,364

Cash distribution from affiliate

​

​

645,451

​

​

500,389

​

​

—

Equity income in affiliate

​

​

(2,668,844)

​

​

(1,119,819)

​

​

(763,988)

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Interest earned on marketable securities in Trust Account

​

​

(3,721,145)

​

​

—

​

​

—

General and administrative expenses

​

​

2,304,445

​

​

—

​

​

—

Consolidated Adjusted EBITDA

​

​

191,190,014

​

​

119,864,595

​

​

65,873,743

Adjusted EBITDA attributable to non-controlling interest

​

​

(27,154,867)

​

​

(35,608,960)

​

​

(23,914,812)

Adjusted EBITDA attributable to Kimbell Royalty Partners, LP

​

​

164,035,147

​

​

84,255,635

​

​

41,958,931

Adjustments to reconcile Adjusted EBITDA to cash available for distribution

​

​

​

​

​

​

​

​

​

Cash interest expense

​

​

9,583,004

​

​

5,297,810

​

​

3,399,655

Cash distributions on Series A preferred units

​

​

—

​

​

1,943,385

​

​

3,047,466

Restricted units repurchased for tax withholding

​

​

—

​

​

1,433,265

​

​

—

Cash income tax expense

​

​

3,082,245

​

​

—

​

​

—

Distributions on Class B units

​

​

42,243

​

​

76,780

​

​

91,869

Cash available for distribution on common units

​

$

151,327,655

​

$

75,504,395

​

$

35,419,941

​

​

Item 8. Financial Statements and Supplementary Data

The Partnership’s consolidated financial statements required by this item are included in this reportAnnual Report beginning on page F‑1.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)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)13a-15(e) and 15d‑15(e)15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosureOn December 15, 2022, we completed the Hatch Acquisition, whose accounts are included in our consolidated financial statements beginning on the acquisition date and reflect total assets and revenues of 24% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022. The scope of our assessment of internal control over financial reporting excludes the Hatch Acquisition. Disclosure controls and procedures are defined as controls designed to provide reasonable assuranceensure that the information required to be disclosed by us 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 and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC.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, 2017.2022.

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, 2022 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.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 principlesprinciples.

BecauseInternal 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 may not prevent or detect misstatements.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.

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As of December 31, 2017,2022, 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 that,our internal controls over financial reporting were effective as of December 31, 2017,2022.

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, 2022, 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, 2022, 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, 2022, and our report dated February 23, 2023 expressedan 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 is effective based on those criteria.

Attestation Report of the Registered Public Accounting Firm

This Annual Report does not include an attestation report of our independent registeredaudit. We are a public accounting firm dueregistered 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 SEC. Our independent registered public accounting firm will not be required to formally attest toSecurities and Exchange Commission and the effectiveness ofPCAOB.

We conducted our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant toaudit in accordance with the provisionsstandards of the JOBS Act.

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Changes in Internal Control over Financial Reporting

There were no changes in ourPCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting during the quarter ended December 31, 2017 that materially affected, or are reasonably likely to materially affect, ourwas maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting.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 related to the mineral and royalty interests acquired from Hatch Royalty LLC, (“Hatch”), whose accounts are included in the Partnership’s consolidated financial statements beginning on the acquisition date and reflect total assets and revenues of 24 and 1 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022. As indicated in Management’s Report, the mineral and royalty interests were acquired from Hatch on December 15, 2022. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of the mineral and royalty interests acquired from Hatch.

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

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transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ GRANT THORNTON LLP

Dallas, Texas

February 23, 2023

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Amendment to the Duncan Services AgreementNot applicable.

On March 7, 2018, Kimbell Operating Kimbell Operating entered into Amendment No. 1 (the “Duncan Amendment”) to the services agreement with Duncan Management, LLC (“Duncan Management”). The services agreement with Duncan management contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Duncan Management will renegotiate the monthly services fee in good faith. The Duncan Amendment amends the services agreement with Duncan Management to reflect the result of such renegotiation, which is a downward adjustment to the services fee from $54,872 per month to $43,498 per month. All other material terms and conditions of the services agreement with Duncan Management were unchanged.

Amendment to the K3 Royalties Services Agreement

On March 7, 2018, Kimbell Operating, entered into Amendment No. 1 (the “K3 Amendment”) to the services agreement with K3 Royalties, LLC (“K3 Royalties”). The K3 Amendment amends the services agreement with K3 Royalties to authorize K3 Royalties to provide additional services, including assistance with business development and relationship management between past and future sellers of mineral assets and the Partnership and assistance with current and future relations with the Kimbell Art Foundation. All other material terms and conditions of the services agreement with K3 Royalties were unchanged.

Amendment to the Nail Bay Royalties Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Nail Bay Amendment”) to the services agreement with Nail Bay Royalties, LLC (“Nail Bay Royalties”). The services agreement with Nail Bay Royalties contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Nail Bay Royalties will renegotiate the monthly services fee in good faith. The Nail Bay Amendment amends the services agreement with Nail Bay Royalties to reflect the result of such renegotiation, which is a downward adjustment to the services fee from $41,961 per month to $29,736 per month. All other material terms and conditions of the services agreement with Nail Bay Royalties were unchanged.

Amendment to the Steward Royalties Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Steward Amendment”) to the services agreement with Steward Royalties, LLC (“Steward Royalties”). The services agreement with Steward Royalties contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Steward will renegotiate the monthly services fee in good faith. The Steward Amendment amends the services agreement with Steward Royalties to reflect the result of such renegotiation, which is an upward adjustment to the services fee from $10,417 per month to $10,833 per month. All other material terms and conditions of the services agreement with Steward Royalties were unchanged.

Amendment to the Taylor Companies Services Agreement

On March 7, 2018, Kimbell Operating entered into Amendment No. 1 (the “Taylor Amendment”) to the services agreement with Taylor Companies Mineral Management, LLC (“Taylor Companies”). The services agreement with Taylor Companies contemplates that the monthly services fee thereunder is subject to annual redetermination and adjustment and that Kimbell Operating and Taylor Companies will renegotiate the monthly services fee in good faith. The Taylor Amendment amends the services agreement with Taylor Companies to reflect the result of such renegotiation, which is an

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upward adjustment to the services fee from $33,333 per month to $43,905 per month. All other material terms and conditions of the services agreement with Taylor Companies were unchanged.

The foregoing descriptions are not complete and are qualified in their entirety by reference to the full text of the amendments, which are filed as exhibits to this Annual Report on Form 10-K and incorporated herein by reference.

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, 2017.2022. 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.Board of Directors. Messrs. R. Ravnaas and D. Ravnaas are father and son, respectively, and Messrs. Fortson and Wynne are father‑in‑lawfather-in-law and son‑in‑law,son-in-law, respectively.

​

​

​

​

​

Name

Age

Position With Our General Partner

Robert D. Ravnaas

​

6065

​

Chief Executive Officer and Chairman of the Board of Directors

R. Davis Ravnaas

​

3237

​

President and Chief Financial Officer

Matthew S. Daly

​

4550

​

Chief Operating Officer

Jeff McInnisR. Blayne Rhynsburger

​

4136

​

Chief Accounting OfficerController

Brett G. Taylor

​

5762

​

Executive Vice Chairman of the Board of Directors

Benny D. Duncan

75

Director

Ben J. Fortson

​

8590

​

Director

T. Scott Martin

​

6772

​

Director

Mitch S. Wynne

​

5964

​

Director

William H. Adams III

​

5964

Independent Director

C.O. Ted Collins, Jr.

79

​

Independent Director

Craig Stone

​

5459

​

Independent Director

Erik B. Daugbjerg

​

53

​

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 has also served as President and director of Rivercrest Royalties II, LLC from 2014 until December 2017, and as President and director of Rivercrest Royalties, LLCour 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

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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. Mr. R. Ravnaas also serves as Chairman of Kimbell Tiger Acquisition Corporation.

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

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

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Mr. Daly has also served as Senior Vice President—Corporate Development of Rivercrest Royalties, LLC sinceour Predecessor from August 2016.2016 until our IPO. From 2014 to 2016, Mr. Daly served as Senior Analyst—Energy at Hirzel Capital Management LLC, a Dallas‑basedDallas-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. Mr. Daly also serves as Strategic Advisor of Kimbell Tiger Acquisition Corporation.

Jeff McInnis. Jeff McInnis was appointed Chief Accounting Officer of our General Partner in November 2015. Mr. McInnisR. Blayne Rhynsburger. R. Blayne Rhynsburger has served as Chief Accounting Officerthe Controller of Rivercrest Royalties, LLCthe General Partner since February 2017.  Mr. Rhynsburger previously served as the Controller of our Predecessor from MayNovember 2015 until our IPO. FromPrior to that time, Mr. Rhynsburger served as audit manager from July 2014 to November 2015, audit senior from July 2011 to June 2014, until May 2015, Mr. McInnis worked as an independent consultant, advising oil and gas companies on accounting and financial reporting matters. Previously, he was Director of Financial Reporting at JP Energy Partners LP, a midstream master limited partnership,audit staff from 2012September 2009 to June 2014. From 2010 to 2012, Mr. McInnis was Controller2011 at Hill & Hill Production, a suite of private, family‑run entities concentrated on exploration and production oil and gas ventures. Additionally, he held positions at PricewaterhouseCoopersWhitley Penn LLP, in their Assurance group from 2003 to 2006 and again from 2009 to 2010 and as a Transaction Services Manager from 2006 to 2009, during which timewhere he specialized in providingassurance and advisory services to a variety offor clients in multiple industries, primarily energy clients in the public and private clients. From 2001 to 2003, he wassectors. Mr. Rhynsburger also has served as an International Accounting Analyst at Triton Energy Limited.adjunct professor of petroleum accounting in the graduate school of Texas Christian University’s Neeley School of Business since 2015. Mr. McInnis hasRhynsburger holds a Bachelor of Business Administration degree in Accounting and Finance and a Master of Accounting degree from Texas Christian University andUniversity. He is also a certified public accountant.member of the Texas Society of Certified Public Accountants. Mr. Rhynsburger also serves as the Controller of Kimbell Tiger Acquisition Corporation.

Brett G. Taylor. Brett G. Taylor was appointed as Executive Vice Chairman of the Board of Directors in November 2015. Mr. Taylor has over 3337 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,co-founded, with Joe B. Neuhoff, Neuhoff‑TaylorNeuhoff-Taylor Royalty Company and began acquiring producing royalties and minerals. He has also served as President and Chief Executive Officer of various Taylor Companiesprivate companies since 1998, and certain of such companies are Contributing Parties. In 1999, Messrs. Taylor, Fortson and R. Ravnaas co‑founded Kimbell Royalty Partners group, which is led by the Kimbell Art Foundation. 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.

Benny D. Duncan. Benny D. Duncan was appointed as a director of our General Partner in November 2016. Mr. Duncan has over 50 years of experience in the oil and gas industry. He began his career with Vaughn Petroleum, Inc. and its subsidiaries (“VPI”) as Assistant Land Manager from 1961 through 1970. Mr. Duncan joined First National Bank of Dallas in 1970 as Land Manager and Engineering Technician and later served as Assistant Vice President—Trust Oil and Gas Division until 1975. Mr. Duncan then returned to VPI, where he served in various operational positions from 1975 to 1990, including as Director and Land Manager, Executive Vice President and Chief Operating Officer, and President. In 1994, Mr. Duncan was actively involved in the formation of Vaughn Petroleum Royalty Partners, Ltd. (“VPRP”). He served as Manager of VPRP’s properties in 1999, and he has continued to manage such properties since their sale in 2004. Between 2005 and 2009, Mr. Duncan formed: Trunk Bay Royalty Partners, Ltd., Bitter End Royalties, LP, Oil Nut Bay Royalties, LP, Nail Bay Royalties, LLC and Gorda Sound Royalties, LP, which make up a portion of the Contributing Parties. He has served as manager of (i) Trunk Bay, LLC, the general partner of Trunk Bay Royalty Partners, Ltd., since 2005; (ii) Bitter End, LLC, the general partner of Bitter End Royalties, LP, since 2008; (iii) Oil Nut Bay, LLC, the general partner of Oil Nut Bay Royalties, LP, since 2008; (iv) Nail Bay Royalties, LLC since 2009; and (v) Gorda Sound, LLC, the general partner of Gorda Sound Royalties, LP, since 2009. Mr. Duncan studied business administration at Arlington State College (now the University of Texas at Arlington). He is an active member of the American Association of Professional Landmen and the Dallas Petroleum Club. Mr. Duncan was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

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 Vice President and 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

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Foundation since 1964. He is also a trustee and Vice President of the Burnett Foundation, a member of the Exchange Club of Fort Worth, a Trustee Emeritus

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of Texas Christian University and an Emeritus Member of the All‑AmericanAll-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 has served as Chief Executive Officer of our Predecessor since July 2014 anduntil 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 3540 years of experience in the oil and gas industry. Mr. Martin founded Ellora Energy LLC in 1995 and was Chairman and Chief Executive Officer of Ellora Energy Inc. from 2002 to 2010. Before that, he was Chief Operating Officer of Alta Energy Corporation from 1992 to 1994, Chief Executive Officer of TPEX Exploration, Inc. from 1990 to 1992 and a consulting engineer at BWAB, Inc. from 1985 to 1990. Mr. Martin began his career in the oil and gas industry in 1979 at Amoco Production Company. Mr. Martin has a Bachelor of Arts degree in Biology from Colorado College and a degree in Chemical Engineering from the University of Colorado at Boulder. He is a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Martin was selected to serve as a director because of his broad knowledge of, and extensive experience in, the oil and gas industry.

Mitch S. Wynne. Mitch S. Wynne was appointed as a director of our General Partner in November 2015. He has been President and owner of Wynne Petroleum Co. since 1992. Mr. Wynne has been engaged in the oil and gas industry for 3538 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 and Principal Owner 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., and he Mr. Adams currently serves as a member of the board of directors of MorningstarTXO Energy Partners, LP, a privatepublicly traded oil and gas production company.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.

C.O. Ted Collins, Jr. C.O. Ted Collins, Jr. passed away on January 27, 2018. Mr. Collins was an independent director and a member of the audit committee of our General Partner. We have begun a search for a third independent director to serve on the Board of Directors and the audit committee of our General Partner.

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‑year30-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 IPOs,initial public offerings, secondary offerings and public debt transactions. In February 2017, Mr. Stone accepted a ministry position with the Hills Church where he oversees and manages campus construction and campusenhancement plans and other strategic expansion and enhancement plans.initiatives. He has a Bachelor of SciencesScience 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 22 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.

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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

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by Kimbell Holdings, which is jointly owned by our Sponsors. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Director Independence

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

Board Role in Risk Oversight

Our corporate governance guidelines (“Governance Guidelines”) provide that the Board of Directors is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility is largely satisfied by the audit committee,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 corporate governance guidelinesGovernance Guidelines are available on our website at http://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 boardBoard of Directors may also have such other committees as they determineit 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‑310A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one‑year period following consummation of our IPO.Act. The audit committeeAudit Committee is composed of William H. Adams III, Craig Stone and Craig Stone.Erik B. Daugbjerg. The audit committeeAudit 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 committeeAudit 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‑approvespre-approves any non‑auditnon-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committeeAudit 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 committeeAudit Committee and our management, as necessary.

Each of Messrs. Adams, Stone and StoneDaugbjerg 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 committeeAudit Committee charter is available on our website at http://www.kimbellrp.com under “Investor Relations—Corporate Governance.”

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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 committeeConflicts and Compensation Committee to review specific matters that may involve conflicts of interest. The conflicts committeeConflicts 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 Craig Stone.Erik B. Daugbjerg. The members of our conflicts committeeConflicts 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 committeeConflicts 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‑termlong-term incentive plan. Our conflictsConflicts and compensation committeeCompensation Committee charter is available on our website at http://www.kimbellrp.com under “Investor Relations—Corporate Governance.”

Section 16(a) Beneficial Ownership Reporting Compliance

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 the period from February 8, 2017 to December 31, 2017 all our directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of

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the Exchange Act, except that a Form 4 was filed late by Messrs. Duncan and Martin to report transactions on November 29, 2017. On February 14, 2018, Mr. Duncan reported his receipt of common units through a distribution on a Form 4 and Mr. Martin reported his disposition of common units on a Form 5.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics applicable to all employees, directors and officers.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 covers topics including, but not limited to, conflicts of interest, gifts and disclosure controls. Our Code of Business Conduct and Ethics areis 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

We are providingThis 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 most highly compensated executive officers (collectively our named executive officers or “NEOs”) during the last completed fiscal year. Our NEOs for the year ended December 31, 2022 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 that satisfies the requirements applicable to emerging growth companies, as definedprovided in the JOBS Act.executive compensation tables below and to provide investors with the material information necessary to understanding our executive compensation program.

Overview of Our general partnerExecutive Compensation Program

Our General Partner has the sole responsibility for conducting our business and for managing our operations, and its boardexecutive officers and its Board of directors and executive officersDirectors make decisions on our behalf. WeAs is typical of publicly traded limited partnerships, we do not directly employ any of the persons responsible for managing our business. Our general partner’sGeneral Partner’s executive officers manage and operate our business as part of the services provided by Kimbell Operating to our general partnerGeneral Partner under a management services agreement. All of our general partner’sGeneral 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“Item 13. Certain Relationships and Related Party Transactions, and Director Independence—Independence—Management Services Agreements.” Neither Kimbell Operating nor any affiliated entity has entered into any employment agreement with any of its executive officers.

WeOur 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 2022. 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

Since 2018, our General Partner were formedPartner’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 October 2015,light of the rules of the SEC and we did not complete our IPO, or own anythe 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 2022 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 assetscompanies, of comparable size to the Partnership. This peer group, which was last updated in Fall 2021, 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 sixteen companies:

​

​

​

Black Stone Minerals, L.P.

HighPeak Energy, Inc.

Bonanza Creek Energy, Inc.

Laredo Petroleum, Inc.

Brigham Minerals, Inc.

Matador Resources Company

Callon Petroleum Company

Northern Oil and Gas, Inc.

Centennial Resource Development, Inc.

Oasis Petroleum Inc.

Contango Oil & Gas

PDC Energy, Inc.

Extraction Oil & Gas, Inc.

SM Energy Company

Gulfport Energy Corporation

Whiting Petroleum Corporation

​

Key Components of Our 2022 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 2022 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 and vesting 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 make upaffect us change. Our resulting compensation mix reflects alignment with our initial assets, until February 2017.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, neither we nor our General Partner accrued or paid any obligations with respectphilosophy is to management compensation or retirement benefits for the directors and executive officers of our general partner during the years ended December 31, 2016 and 2015. Accordingly, we are not presenting any compensation for historical periods prior to the year ended December 31, 2017.

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The table below provides information concerning the annual compensation of our named executive officers (our “Named Executive Officers” or “NEOs”) for the year ended December 31, 2017. As an emerging growth company, our NEOs include the Chief Executive Officer and our other two most highly compensated officers.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short Term

 

 

 

 

Other

 

 

 

Name and Principal Position

 

Salary (1)

 

Incentive Bonus

 

Unit Awards (2)

 

Compensation (3)

 

Total

Robert D. Ravnaas

 

$

275,562

 

$

125,000

 

$

423,765

 

$

123,809

 

$

948,136

(Chairman and Chief Executive Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

R. Davis Ravnaas

 

$

253,355

 

$

120,000

 

$

423,765

 

$

13,809

 

$

810,929

(President and Chief Financial Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Matthew S. Daly

 

$

159,359

 

$

75,000

 

$

53,502

 

$

1,743

 

$

289,604

(Chief Operating Officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly began to receive compensation from our general partner following the consummation of our IPO on February 8, 2017. Therefore, the amounts shown for the year ended December 31, 2017 represent the salary earned by each NEO for his partial year of service.

(2)

Amounts for 2017 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit.

(3)

Amounts reflect (i) for Mr. Robert D. Ravnaas: include $110,000 as part of the service agreement with Steward Royalties and Partnership distributions received from the awarded LTIP units of $13,809; (ii) for Mr. R. Davis Ravnaas: Partnership distributions received from the awarded LTIP units of $13,809; and (iii) for Mr. Daly: Partnership distributions received from the awarded LTIP units of $1,743.

For the year ended December 31, 2017, the principal elements of compensation provided to our NEOs wereset base salaries, short-term incentive bonuses (“STI Bonuses”) and LTIP awards.

Base Salary

Base salaries are generally setsalary at levels deemeda sufficient level necessary to attract and retain individuals with superior talent, commensurate with their relative 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.

Short-Term99

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Long-Term Incentive BonusesAwards

The STI Bonuses provide ourConflicts and Compensation Committee makes determinations regarding long-term incentive restricted unit awards for NEOs with an incentive in the formfirst quarter of an annual cash bonuseach year, subsequent to achieve our overall qualitative business goals. Foryear-end results. The target awards for 2022 performance were set in December 2021, with the 2017 fiscal year, Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly had an annual target bonus amountactual number of $125,000, $120,000 and $75,000, respectively. The actual amount of Messrs. Robert D. Ravnaas’, R. Davis Ravnaas’ and Matthew Daly’s annual bonuses arerestricted units granted determined byin February 2023, after the Conflicts and Compensation Committee in its sole discretion and may be higher or lower than their target amounts.reviewed the Partnership’s 2022 performance. The amounts of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly’s bonuses for fiscal year 2017 are set forth under the “Bonus” column in the table below.

The bonuses for each of Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly were based on their target bonus, qualitative performance and other discretionary factors, including achievement of strategic objectives, goals in compliance and ethics and teamwork within the Partnership. A variety of qualitative factors that vary by year and are given different weights in different years depending on facts and circumstances were considered, with no single factor being determinative to the overall bonus decision. The factors considered by the Conflicts and Compensation Committee in connection with Messrs. Robert D. Ravnaas’, R. Davis Ravnaas’ and Matthew S. Daly’s fiscal year 2017 bonuses are discussed in more detail below.

In makingbelieves that this approach furthers its philosophy of rewarding performance by determining the bonus determinations for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, other qualitative factors taken into account includednumber of restricted stock units only after the achievement of performance in internal and public financial reporting, budgeting and forecasting processes, compliance and infrastructure and investment and cost-savings initiatives. Non-financial factors considered also included, among other items, providing strategic leadership and direction for the Partnership, including corporate governance matters, managing the strategic direction of the Partnership, increasing operational efficiency, expanding our asset base and communicating to investors and other important constituencies.

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For fiscal year 2017, after considering the factors described above and management’s recommendations, the Conflicts and Compensation Committee determined that the bonuses for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly would be set at amounts equal to 100% of their annual target bonus amounts. Thismetrics is reflectedknown. Mr. Rhynsburger did not participate in the Conflictsexecutive compensation programs described in this CD&A in 2022; his compensation was determined in accordance with the compensation programs applicable to employees generally, which did not include Partnership performance criteria, and Compensation Committee’s and management’s assessment that overall corporate performance and discretionary factors justified payment of such bonus to each of theminstead was based on their and the Partnership’s performance during the fiscal year. Specifically, the Conflicts and Compensation Committee set the amount of Mr. Robert D. Ravnaas’ bonus after considering the quality of his individual performance in managing the overall operations and resources of the Partnership, Mr. R. Davis Ravnaas’ bonus after considering the quality of his individual performance in running the partnership-wide finance function and the amount of Mr. Matthew S. Daly’s bonus after considering the quality of his individual performance in running the ongoing business operationspeer benchmarking for similar positions as well as his individual contributions and performance.

Because the performancedetermination of the Partnership.number of restricted units in respect to 2022 performance is made in February 2023, after year end, pursuant to SEC reporting rules, 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 2022 in relation to 2021 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 Awards

The Board granted awards under the LTIP  to our NEOs on May 12, 2017, consisting of 48,132 restricted common units. EachPlan. Additionally, each award is subject to the terms and conditions of the award agreement that we entered into with the applicable NEO. The restricted common 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 2020 for 2021 performance were 155,000, 120,000 and 85,000 restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively. In February 2022, 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 137.5% of the target restricted units for Messrs. Robert D. Ravnaas, R. Davis Ravnaas, Matthew S. Daly would be granted for 2021 performance, resulting in awards of 213,125, 165,000 and 116,875 restricted units, respectively. As described above, Mr. Rhynsburger’s compensation was determined based on benchmarking of similar positions and he was granted 14,192 restricted units. Because these grants were made in 2022, they are included in the compensation tables included in this Form 10-K.

In December 2021, the Conflicts and Compensation Committee set the target restricted unit awards for 2022 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 2023, after the review of the achievement of compensation factors, as described below.

STI Bonuses

The following table reflects information regarding outstanding unvested common units held bySTI 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, Matthew S. Daly, and R. Blayne Rhynsburger 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, Matthew S. Daly, and R. Blayne Rhynsburger, other post-performance evaluation criteria taken into account include performance in internal and public financial reporting, budgeting and forecasting processes, compliance and infrastructure and investment and cost-savings initiatives. Non-financial factors considered also included, among other items, providing strategic leadership and direction for the Partnership, including corporate governance matters, managing

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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, Matthew S. Daly, and R. Blayne Rhynsburger are determined by the Conflicts and Compensation Committee in its sole discretion and may be higher or lower than their target amounts.

In December 2021, the Conflicts and Compensation Committee set the target STI Bonuses for 2022 performance at $575,000, $550,000 and $450,000 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 2022 performance are discussed below.

Factors Used for Determining Incentive Compensation and Compensation Decisions for 2022 Performance

The Conflicts and Compensation Committee approved five factors, which are described in further detail below, to be used in determining the 2022 long-term and short-term incentive awards for our NEOs, other than Mr. R. Blayne Rhynsburger. Four of December 31, 2017.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 2022, 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 2022

Compensation Factor

​

Weight

​

Target Objective for 2022

​

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%

​

$3.10 - $3.30

​

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 2022

Relative unitholder return

​

20%

​

Peer Ranking of TSR(1)

​

5th

​

4th

​

3rd

​

2nd

​

1st

​

​

​

​

​

​

0%

​

50%

​

100%

​

150%

​

200%

 

 

 

 

 

 

 

 

Unit Awards

 

 

Number of Restricted

 

Market Value of Restricted

 

 

Common Units that

 

Common Units that

Name

 

have not vested (1)

 

have not vested (2)

Robert D. Ravnaas

 

22,637

 

$

367,851

(Chairman and Chief Executive Officer)

 

 

 

 

 

R. Davis Ravnaas

 

22,637

 

$

367,851

(President and Chief Financial Officer)

 

 

 

 

 

Matthew S. Daly

 

2,858

 

$

46,443

(Chief Operating Officer)

 

 

 

 

 

(1)

(1)

The NEO’s outstanding restricted common unitsRanking of total shareholder return (“TSR”) for calendar year 2022 including the following companies: KRP, Brigham Minerals, Inc., Black Stone Minerals, L.P., Viper Energy Partners LP and Sitio Royalties Corp. If a peer company is acquired during year, TSR will vest in accordance withbe calculated from January 1, 2022 through 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, $16.25, of our common units on December 29, 2017, the last NYSE market trading day of the year ended December 31, 2017.

deal closing.

Please readPearl Meyer’s analysis determined that the descriptionproposed 2022 compensation at the target levels was below the median of the long‑term incentive plan we adopted priorpeer group for Messrs. Robert D. Ravnaas and R. Davis Ravnaas and at the median for Matthew S. Daly.

The chart below displays our actual 2022 results for each compensation.

​

​

​

​

​

​

​

​

​

Compensation Factor

​

Weight

​

Target Objective for 2022

​

Actual 2022 Results for the Partnership

​

Actual 2022 Results Compared to Target Objectives

Production growth

​

20%

​

0% - 4% Growth

​

6% Growth

​

Above Target

PDP reserve replacement

​

20%

​

95% - 100% Replacement

​

118% Replacement

​

Above Target

Cash G&A expense per BOE

​

20%

​

$3.10 - $3.30

​

$3.24

​

At Target

Achievement of core competencies

​

20%

​

Committee Discretion

​

Above Target

​

Above Target

Relative unitholder return

​

20%

​

Peer Ranking of TSR

​

5th

​

Below Target

​

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The 2022 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 two of the completionfour quantitative compensation factors were above the target objective for 2022, our actual results for the third quantitative compensation factor met the target objective 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 exceeded the target objective for the achievement of our IPOcore 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 undertarget objective for the heading “—Long‑Term Incentive Plan.”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 110.0% of their 2022 target amounts. The chart below displays the actual 2022 STI Bonuses earned and restricted unit awards granted for 2022 performance, based on the level of achievement of each compensation factor.

​

​

​

​

​

​

Name

​

Long-Term Restricted Units Awarded (1)

​

STI Bonus Earned

Robert D. Ravnaas

​

204,600

​

$

632,500

R. Davis Ravnaas

​

181,500

​

$

605,000

Matthew S. Daly

​

112,200

​

$

495,000

R. Blayne Rhynsburger (2)

​

15,409

​

$

70,000

(1)As described above, the restricted units were not granted until February 2023, after the Conflicts and Compensation Committee’s determination of the achievement of 2022 compensation factors.
(2)As described above, Mr. Rhynsburger’s compensation for 2022 was determined pursuant to the compensation programs applicable to employees generally, and not pursuant to the compensation factors described in this CD&A.

Additional Narrative Disclosure

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 have not maintained, and do not currently maintain a defined benefit pension401(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.

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 nonqualified deferredrole in evaluating and mitigating any risk that may exist relating to our compensation planplans, 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 a 401(k)-plan providing for retirement benefits.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.

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Conflicts and Compensation Committee Report

Long‑Term Incentive Plan

In order to incentivize ourThe 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, directorsbased on such review and discussions, the Conflicts and Compensation Committee recommended to continue to grow our business, the Board of Directors adopted a LTIP for employees, officers, consultantsthat the compensation discussion and directors of our General Partner, Kimbell Operating and their respective affiliates, who perform services for us. Our General Partner implemented the LTIP prior to the completion of our IPO to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us. We filed a registration statementanalysis be included in this Annual Report on Form S‑8 on May 12, 2017 for shares issued pursuant to the LTIP.10-K.

The descriptionRespectfully submitted,

Members of the LTIP set forth below is a summary of the material features of the LTIP. This summary, however, does not purport to be a complete description of all the provisions of the LTIP. This summary is qualified in its entirety by reference to the LTIP, which has been filed as an exhibit to a Form 8‑K.

The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights and cash awards (collectively, “awards”). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long‑term performance. Any awards that are made under the LTIP will be approved by the Board of Directors or a committee thereof that may be established for such purpose. We are responsible for the cost of awards granted under the LTIP.

Administration

The Board of Directors appointed the Conflicts and Compensation committee to administerCommittee,

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

Summary Compensation Table

The table below presents the LTIP, which we refer to as the “committee” for purposes of this summary. The committee administers the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee has the power to determine to whom and when awards will be granted, determine the number of awards (measured in cash orannual compensation of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “non‑employee directors” within the meaning of Rule 16b‑3 under the Exchange Act, we expect that the full Board of Directors or a subcommittee of two or more non‑employee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 2,041,600 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. Under the LTIP, the maximum aggregate grant date fair value of awards granted to a non‑employee director of our General Partner, in such individual’s capacity as a non‑employee director, during any calendar year will not exceed $500,000 (or $600,000 in the first year in which an individual becomes a non‑employee director).

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferableNamed Executive Officers for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our General Partner in the open market, from any other person, directly from us, or any combination of the foregoing.

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Awards

Unit Options

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for a unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option. Unit options may be exercised in the manner and at such times as the committee determines for each unit option and the term of the unit option will not exceed ten years. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

Unit Appreciation Rights

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right. The term of the unit appreciation right will not exceed ten years.

Restricted Units

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed. Unless otherwise determined by the committee, each restricted unit will be entitled to receive distributions in the same manner as other outstanding common units.

Unit Awards

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

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Miscellaneous

Tax Withholding

At our discretion, and subject to conditions that the committee may impose, the payment of any applicable taxes with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of our common units in each case up to the maximum statutory rate.

Anti‑Dilution Adjustments

In the event that any distribution, recapitalization, split, reverse split, reorganization, merger, consolidation, split‑up, spin‑off, combination, repurchase or exchange of our common units, issuance of warrants or other rights to purchase our common units or other similar transaction or event affects our common units, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change of Control

Notwithstanding the foregoing, if the Participant remains in Continuous Service as of the date of a Change in Control, any unvested restricted common units will be vested as of the date of such Change in Control.  For this purpose, “Change in Control” means, and shall be deemed to have occurred upon the occurrence of one or more of the following events: (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than Kimbell GP Holdings, LLC or their respective Affiliates, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Partnership or an Affiliate of the Partnership; or (iv) a transaction resulting in a Person other than the Partnership or an Affiliate of the Partnership being the general partner of the Partnership.

Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the Board of Directors will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

We and our General Partner were formed in October 2015 and we did not complete our IPO or own any of the mineral and royalty assets that make up our initial assets, until February 2017. As such, neither we nor our General Partner accrued or paid any obligations with respect to compensation for directors of our General Partner during the years ended December 31, 20162022, 2021 and 2015.2020.

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 Master Service Agreement (a “non-employee director”) receives the following cash compensation:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Non-Equity

​

​

​

​

​

​

​

​

​

​

​

​

​

Long-Term

​

Incentive Plan

​

Other

​

​

​

Name

​

Year

​

Salary

​

Restricted Units (1)(2)

​

Compensation (1)(3)

​

Compensation (4)

​

Total

Robert D. Ravnaas

​

2022

​

$

575,000

​

$

3,473,938

​

$

632,500

​

$

790,311

​

$

5,471,749

Chairman and CEO

​

2021

​

$

575,000

​

$

2,186,663

​

$

790,625

​

$

456,380

​

$

4,008,668

​

​

2020

​

$

575,000

​

$

2,372,081

​

$

790,625

​

$

245,890

​

$

3,983,596

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

R. Davis Ravnaas

​

2022

​

$

550,000

​

$

2,689,500

​

$

605,000

​

$

615,298

​

$

4,459,798

President and CFO

​

2021

​

$

550,000

​

$

1,692,900

​

$

756,250

​

$

355,134

​

$

3,354,284

​

​

2020

​

$

550,000

​

$

1,836,450

​

$

756,250

​

$

184,881

​

$

3,327,581

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Matthew S. Daly

​

2022

​

$

450,000

​

$

1,905,063

​

$

495,000

​

$

440,284

​

$

3,290,347

COO

​

2021

​

$

450,000

​

$

1,199,138

​

$

618,750

​

$

254,625

​

$

2,522,513

​

​

2020

​

$

450,000

​

$

1,300,819

​

$

618,750

​

$

125,079

​

$

2,494,648

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

R. Blayne Rhynsburger

​

2022

​

$

250,000

​

$

232,568

​

$

70,000

​

$

67,136

​

$

619,704

Controller

​

2021

​

$

190,000

​

$

146,390

​

$

70,000

​

$

43,349

​

$

449,739

​

​

2020

​

$

190,000

​

$

158,803

​

$

55,000

​

$

28,855

​

$

432,658

(1)

·

An annual base retainer fee of $60,000 per year;

·

an additional retainer of $15,000 per year if such director serves asNEOs receive their long-term incentive restricted units and STI Bonus in the chairpersonfirst quarter of the Audit Committee; and

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 2022, the number of which represent the achievement of compensation factors for fiscal 2021.

(2)

·

an additional retainer of $15,000 per year if such director servesAmounts reflect the grant date value as the chairperson of the Conflictsdetermined pursuant to FASB Accounting Standards Codification (“ASC”) Topic 718, “Compensation – Stock Compensation”, without regard to potential forfeitures. Amounts for 2022, 2021 and Compensation Committee

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Table of Contents

In addition to cash compensation, our non-employee directors receive annual equity-based compensation under the LTIP. Each non-employee director was granted 1,904 fully vested common units on August 14, 2017. Each such award has an aggregate grant date value equal to $30,000. Future annual equity-based compensation under the LTIP will be granted to our non-employee directors, vesting ratably over three years from the respective grant dates.

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 or its committees.

The following table provides information concerning the compensation of our non-employee directors for the fiscal year ended December 31, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

All Other

 

 

 

Name

 

Fees Earned

 

Unit Awards

 

Compensation

 

Total

Brett G. Taylor (1)

 

$

 -

 

$

423,765

 

$

366,667

 

$

790,432

Benny D. Duncan (2)

 

$

 -

 

$

29,988

 

$

1,065,167

 

$

1,095,155

Ben J. Fortson (3)

 

$

 -

 

$

423,765

 

$

 -

 

$

423,765

T. Scott Martin (4)

 

$

40,000

 

$

29,988

 

$

 -

 

$

69,988

Mitch S. Wynne (5)

 

$

 -

 

$

423,765

 

$

110,000

 

$

533,765

William H. Adams III (6)

 

$

47,500

 

$

29,988

 

$

 -

 

$

77,488

C.O. Ted Collins, Jr. (4)

 

$

40,000

 

$

29,988

 

$

 -

 

$

69,988

Craig Stone (6)

 

$

52,500

 

$

29,988

 

$

 -

 

$

82,488

(1)

Mr. Taylor’s Unit Awards2020 reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the February 24, 2022 grant date at $18.72$16.30 per common unit.  Mr. Taylor’s All Other Compensationunit, the February 25, 2021 grant date at $10.26 per common unit and the February 28, 2020 grant date at $11.13 per common unit, respectively.

(3)Our non-equity incentive plan compensation consists of the paymentsSTI Bonus for each of the NEOs, other than Mr. Rhynsburger.
(4)Amounts reflected in “Other Compensation” are presented in the amounttable below:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Distributions

​

​

​

​

​

​

​

​

​

​

on Long-Term

​

401(k) Matching

​

Total Other

Name

​

Year

​

Restricted Units

​

Contributions

​

Compensation

Robert D. Ravnaas

​

2022

​

$

775,061

​

$

15,250

​

$

790,311

​

​

2021

​

$

441,880

​

$

14,500

​

$

456,380

​

​

2020

​

$

231,640

​

$

14,250

​

$

245,890

​

​

​

​

​

​

​

​

​

​

​

​

R. Davis Ravnaas

​

2022

​

$

600,048

​

$

15,250

​

$

615,298

​

​

2021

​

$

340,634

​

$

14,500

​

$

355,134

​

​

2020

​

$

170,631

​

$

14,250

​

$

184,881

​

​

​

​

​

​

​

​

​

​

​

​

Matthew S. Daly

​

2022

​

$

425,034

​

$

15,250

​

$

440,284

​

​

2021

​

$

240,125

​

$

14,500

​

$

254,625

​

​

2020

​

$

110,829

​

$

14,250

​

$

125,079

​

​

​

​

​

​

​

​

​

​

​

​

R. Blayne Rhynsburger

​

2022

​

$

51,886

​

$

15,250

​

$

67,136

​

​

2021

​

$

30,349

​

$

13,000

​

$

43,349

​

​

2020

​

$

16,605

​

$

12,250

​

$

28,855

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Table of Contents

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 2022 .

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

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

​

—

​

$

230,000

​

$

575,000

​

$

920,000

​

​

​

​

​

​

​

​

​

​

​

2/24/2022

​

​

​

​

​

​

​

​

​

​

77,500

​

155,000

​

232,500

​

$

3,473,938

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

R. Davis Ravnaas

​

—

​

$

220,000

​

$

550,000

​

$

880,000

​

​

​

​

​

​

​

​

​

​

​

2/24/2022

​

​

​

​

​

​

​

​

​

​

60,000

​

120,000

​

180,000

​

$

2,689,500

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Matthew S. Daly

​

—

​

$

180,000

​

$

450,000

​

$

720,000

​

​

​

​

​

​

​

​

​

​

​

2/24/2022

​

​

​

​

​

​

​

​

​

​

42,500

​

85,000

​

127,500

​

$

1,905,063

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

R. Blayne Rhynsburger

​

—

​

$

70,000

​

$

70,000

​

$

70,000

​

​

​

​

​

​

​

​

​

​

​

2/24/2022

​

​

​

​

​

​

​

​

​

​

14,268

​

14,268

​

14,268

​

$

232,568

(1)Amounts in these columns represent the minimum, target, and maximum possible payouts for STI Bonus. The actual value of $366,667 madebonuses paid to Taylor Companiesour NEOs for 2022 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 21, 2023.
(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: 213,125, 165,000 and 116,875 for Messrs. Robert D. Ravnaas, R. Davis Ravnaas and Matthew S. Daly, respectively.
(3)Amounts reflect the grant date value as described in Item 13. Certain Relationships and Related Transactions, and Director Independence-Management Services Agreements.

(2)

Mr. Duncan’s Unit Awardsdetermined 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 24, 2022 grant date at $15.75$16.30 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, 2022.

​

​

​

​

​

​

​

​

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

​

426,248

​

$

7,118,342

R. Davis Ravnaas

​

329,999

​

$

5,510,983

Matthew S. Daly

​

233,749

​

$

3,903,608

R. Blayne Rhynsburger

​

28,535

​

$

476,535

(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, $16.70, of our common units on December 31, 2022.

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Table of Contents

Units Vested

The following table provides information related to the vesting of restricted units held by a named executive officer during fiscal year ended 2022.

​

​

​

​

​

​

​

​

Name

​

Date Vested

​

Number of Units
Acquired on Vesting

​

Total

Robert D. Ravnaas

​

3/4/2022

​

71,043

​

$

1,143,792

​

​

3/5/2022

​

71,041

​

$

1,145,181

​

​

​

​

​

​

​

​

R. Davis Ravnaas

​

3/4/2022

​

55,000

​

$

885,500

​

​

3/5/2022

​

54,999

​

$

886,584

​

​

​

​

​

​

​

​

Matthew S. Daly

​

3/4/2022

​

38,959

​

$

627,240

​

​

3/5/2022

​

38,958

​

$

628,003

​

​

​

​

​

​

​

​

R. Blayne Rhynsburger

​

3/4/2022

​

4,756

​

$

76,572

​

​

3/5/2022

​

4,755

​

$

76,651

(1)Value calculated based on the closing price on the NYSE of our common units on 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 2022.

​

​

​

​

​

​

​

​

Unit Awards

​

​

Number of

​

Market Value of

​

​

Restricted Units Vested

​

Restricted Units Vested

Name

​

Upon Qualifying Event

​

Upon Qualifying Event

Robert D. Ravnaas

​

426,248

​

$

7,118,342

R. Davis Ravnaas

​

329,999

​

$

5,510,983

Matthew S. Daly

​

233,749

​

$

3,903,608

R. Blayne Rhynsburger

​

28,535

​

$

476,535

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 $70,000 per year or (ii) for an independent director, an annual base retainer fee of $90,000 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
●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.

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Table of Contents

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 each February 24, 2022, February 25, 2021 and February 28, 2020 consisting of 117,082 restricted units. Beginning in 2020, and continuing in subsequent years, long-term incentive awards are, and will be, granted once annually in the first quarter of each year.

The following table provides information concerning the compensation of our directors who are not NEOs for the year ended December 31, 2022.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

All Other

​

​

​

Name

​

Fees Earned

​

Unit Awards (6)

​

Compensation

​

Total

William H. Adams III (1)

​

$

105,000

​

$

154,850

​

$

—

​

$

259,850

Erik Daugbjerg (1)

​

$

105,000

​

$

154,850

​

$

—

​

$

259,850

Ben J. Fortson (2)

​

$

—

​

$

664,893

​

$

—

​

$

664,893

T. Scott Martin (3)

​

$

70,000

​

$

114,100

​

$

—

​

$

184,100

Craig Stone (1)

​

$

105,000

​

$

154,850

​

$

—

​

$

259,850

Brett G. Taylor (4)

​

$

—

​

$

2,414,372

​

$

250,000

​

$

2,664,372

Mitch S. Wynne (5)

​

$

—

​

$

664,893

​

$

120,000

​

$

784,893

(1)Mr. Duncan’sAdams’, 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 18,998 unvested restricted units outstanding as of December 31, 2022.
(2)Mr. Fortson has 81,581 unvested restricted units outstanding as of December 31, 2022.
(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 13,999 unvested restricted units outstanding as of December 31, 2022.
(4)Mr. Taylor’s All Other Compensation consists of thehis salary earned as an employee of Kimbell Operating. Mr. Taylor has 296,240 unvested restricted units outstanding as of December 31, 2022.
(5)Mr. Wynne’s All Other Compensation consists of payments in the amount of $603,591 and $461,576 made to Duncan Management Company and Nail BayK3 Royalties, respectively,LLC (“K3 Royalties”) as described in “Item 13. Certain Relationships and Related Party Transactions, and Director Independence-ManagementIndependence—Management Services Agreements.

Agreements.” Mr. Wynne has 81,581 unvested restricted units outstanding as of December 31, 2022.

(6)

(3)

Mr. Fortson’s Unit AwardsAmounts 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 24, 2022 grant date at $18.72$16.30 per common unit.

(4)

Mr. Martin’s and Mr. Collins’ Paid in Cash amounts include the annual cash retainer fee for each non-employee director during fiscal 2017, as more fully explained above.  Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $15.75 per common unit. 

(5)

Mr. Wynne’s Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $18.72 per common unit.  Mr. Wynne’s All Other Compensation consists of the payments in the amount of $110,000 made to K3 Royalties as described in Item 13. Certain Relationships and Related Transactions, and Director Independence-Management Services Agreements.

(6)

Mr. Adams’ and Mr. Stone’s Paid in Cash amounts include the annual cash retainer fee and committee chair fees for each non-employee director and during fiscal 2017, as more fully explained above.  Unit Awards reflect the grant date fair value of our common units, computed based on the average of the opening and closing price on the grant date at $15.75 per common unit.

Compensation Committee Interlocks and Insider Participation

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

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Table of Contents

Conflicts and Compensation Committee Report

The Conflicts and Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis. Based on the review and discussions, the Conflicts and Compensation Committee recommends to the Board of Directors that the Compensation Discussion and Analysis be included in this Form 10-K.

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 January 31, 2018February 17, 2023 by:

·

●

our General Partner;

·

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

·

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

·

●

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

●

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

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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.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

    

​

    

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

 

6.4

%

Directors and Officers

​

​

​

​

​

​

​

​

​

Robert D. Ravnaas (3)

​

1,059,141

​

—

 

1,059,141

 

1.3

%

R. Davis Ravnaas (4)

​

637,755

​

—

 

637,755

 

*

%

Matthew S. Daly (5)

​

417,475

​

—

 

417,475

 

*

%

Blayne Rhynsburger (6)

​

46,616

​

—

​

46,616

​

*

%

Brett G. Taylor (7)

​

733,998

​

—

 

733,998

 

*

%

Ben J. Fortson (8)

​

259,674

​

—

 

259,674

 

*

%

Mitch S. Wynne (9)

​

228,629

​

—

 

228,629

 

*

%

T. Scott Martin (10)

​

54,122

​

—

 

54,122

 

*

%

William H. Adams III (11)

​

69,654

​

—

 

69,654

 

*

%

Craig Stone

​

44,382

​

—

 

44,382

 

*

%

Erik B. Daugbjerg

​

74,185

​

—

​

74,185

​

*

%

All directors and executive officers as a group (11 persons)

​

3,625,631

​

—

 

3,625,631

 

4.5

%

 

 

 

 

 

 

 

    

 

    

Percentage of

 

 

 

Common Units

 

Common Units

 

 

 

Beneficially

 

Beneficially

 

Name of Beneficial Owner

 

Owned 

 

Owned 

 

Kimbell Art Foundation (1)

 

2,953,258

 

17.5

%

Fidelity Management and Research Company (2)

 

958,900

 

5.7

%

Yorktown X Associates, LLC (3)

 

925,634

 

5.5

%

Robert D. Ravnaas (4)

 

186,639

 

1.1

%

R. Davis Ravnaas (5)

 

61,116

 

*

%

Matthew S. Daly

 

11,829

 

*

%

Jeff McInnis

 

15,510

 

*

%

Brett G. Taylor (6)

 

214,566

 

1.3

%

Benny D. Duncan (7)

 

294,825

 

1.8

%

Ben J. Fortson (8)

 

3,049,768

 

18.1

%

T. Scott Martin 

 

13,087

 

*

%

Mitch S. Wynne (9)

 

110,669

 

*

%

William H. Adams III

 

12,654

 

*

%

C.O. Ted Collins, Jr.

 

22,570

 

*

%

Craig Stone

 

6,382

 

*

%

All directors and executive officers as a group (12 persons)

 

3,999,615

 

23.8

%

*Less than 1%

*

(1)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 for this beneficial ownerof 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, and heFoundation. Mr. Fortson was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting andor investment power over the 2,953,258 common unitssecurities owned by the Kimbell Art Foundation. Mr. Fortson disclaims beneficial ownership of such common units.

securities.

(3)

(2)

The address for this beneficial owner is 245 Summer Street, 14th Floor, Boston, Massachusetts, 02210.

(3)

The address for this beneficial owner 410 Park Avenue, 19th Floor, New York, New York, 10022.

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(4)

Robert D. Ravnaas is a partner or member in certain entities that directly or indirectly hold, in the aggregate, approximately 598,951327,812 common units.units, of which 117,032 common units are deemed to be beneficially owned by Mr. R. Ravnaas has sole voting and investment power with respect to 84,417 common units.included in the table above. Mr. R. Ravnaas doesis 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 have voting or investment power withto beneficially own any of the respect to the other commonClass B units held by such entities. Mr. R. Ravnaas’Ravnaas has a pecuniary interest in an aggregate of approximately 150,666 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.

(4)R. Davis Ravnaas is a partner or member in certain entities that hold, directly or indirectly, in the aggregate, 185,129 common units and 3,076,559 Class B units, however Mr. D. Ravnaas is deemed not to beneficially own any of the common units or Class B units held by such entities. Mr. D. Ravnaas has a pecuniary interest in an aggregate of approximately 153,63034,243 common units and 15,163 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.
(5)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.

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(6)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.
(7)Brett G. Taylor is a partner in, member of or sole trustee of certain entities that hold, directly or indirectly, in the aggregate, 155,900 common units, and Mr. R. RavnaasTaylor 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 121,405 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.

(8)

(5)

R. Davis RavnaasBen 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 partnermember, sole shareholder or member intrustee of certain entities that hold, directly or indirectly, in the aggregate, approximately 92,62763,082 common units.units, and Mr. D. Ravnaas does notFortson may be deemed to have voting or investment power with respect to such entities.common units. Mr. D. Ravnaas’Fortson has a pecuniary interest in an aggregate of approximately 38,082 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.

(9)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 21,78740,539 common units based on his ownership interest in such entities, and Mr. D. RavnaasWynne 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.

(6)

Brett G. Taylor is the sole trustee of and may be deemed to have voting and investment power over the 80,092 27,539 common units owned by Brett G. Taylor Royalty Trust.a trust for which Mr. Taylor is the Sole Member of and may be deemedWynne serves as trustee are subject to have voting and investment power over the 37,999 common units owned by BGT Minerals, LLC. Mr. Taylor is the Sole Member of and may be deemed to have voting and investment power over the 2,172 common units owned by BRD Royalty Holdings LLC. In addition, Mr. Taylora negative pledge under a loan agreement with a bank.

(10)T. Scott Martin is a partner or member inof an entity that holds, in the aggregate, approximately 16,326 additional12,970 common units. Mr. Taylor doesMartin 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 have voting or investment power with respect to beneficially own any of the Class B units held by such entity.entities. Mr. Taylor’sMartin has a pecuniary interest in such entity is an aggregate of approximately 1,143 additional12,970 common units and 15,163 Class B units based on his ownership interest in such entities, and Mr. TaylorMartin disclaims beneficial ownership of the common units that may be deemed to be owned by such entity except to the extent of his pecuniary interest therein.

(7)

Mr. Duncan directly owns 111,039 common units. Mr. Duncan’s minor children own 2,894 common units over which Mr. Duncan may be deemed to have voting and investment power. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 1,837 common units that may be deemed to be owned by GSEF, LLC. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 168 common units that may be deemed to be owned by, Bitter End, LLC. Bitter End, LLC is the general partner of, and may be deemed to have voting and investment power over the 3,769 common units owned by, Bitter End Royalties, LP. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 654 common units that may be deemed to be owned by, Gorda Sound, LLC. Mr. Duncan is the Sole Manager of, and may be deemed to have voting and investment power over the 7,604 common units that may be deemed to be owned by, Oil Nut Bay, LLC. Mr. Duncan is the Sole Manager of and may be deemed to have voting and investment power over the 9,913 common units that may be deemed to be owned by, Trunk Bay, LLC. Trunk Bay, LLC is the general partner of, and may be deemed to have voting and investment power over the 160,677 common units owned by, Trunk Bay Royalty Partners, Ltd. Each of Bitter End, LLC, Trunk Bay, LLC and Mr. Duncan disclaims beneficial ownership of the common unitssecurities that may be deemed to be owned by such entities or individual except to the extent of their pecuniary interest therein.

(8)

Ben J. Fortson is Vice President and Chief Investment Officer of the Kimbell Art Foundation, and he was delegated authority to manage the investment assets of the Kimbell Art Foundation and, therefore, may be deemed to have voting and investment power over the 2,953,258 common units owned by the Kimbell Art Foundation. Mr. Fortson is the trustee of and may be deemed to have voting and investment power over the 17,341 common units owned by Mattie K. Carter Trust. Mr. Fortson and is the trustee of and may be deemed to have voting and investment power over the 14,440 common units owned by certain trusts for which he serves as the trustee. Mr. Fortson and his wife are the sole directors and officers of and may be deemed to have voting and investment power over the 1,301 common units owned by, BK GenPar, Inc. Mr. Fortson disclaims beneficial ownership of all such common units except to the extent of his pecuniary interest therein.

(11)

(9)

Mitch S. Wynne is the trustee of and may be deemed to have voting and investment power over the 27,539Bill Adams has pledged approximately 41,156 common units owned by MSW Investment Trust. Mr. Wynne is the trustee of and may be deemed to have voting and investment power over the 2,000 common units owned by David Mitchell Wynne Asset Trust. Mr. Wynne is the co-trustee of and may be deemed to have voting and investment power over the 11,916 common units owned by certain niece’s and nephew’s trusts. Mr. Wynne disclaims beneficial ownership of all such common units except to the extent of his pecuniary interest therein.

as collateral for a margin account with a bank.

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The followingbelow table sets forth the beneficial ownership of the equity interests in our General Partner:Partner as of February 17, 2023:

​

​

​

​

Name of Beneficial Owner (1)

    

Membership Interest

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)

(1)

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

(2)

(2)

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

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(3)

(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‑economicnon-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

In connection with On May 18, 2022, the consummationPartnership held a special meeting of our IPO on February 3, 2017,unitholders of the Board of Directors adoptedPartnership, at which the Partnership’s unitholders voted to approve the Amended and Restated Kimbell Royalty Partners, LP Long TermGP, LLC 2017 Long-Term Incentive Plan.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, 2017:2022:

 

 

 

 

 

 

 

 

    

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

 

Column(a))

 

 

(a)

 

(b)

 

(c)

Equity compensation plans approved by unitholders

 

167,571

 

16.250

 

1,874,029

Equity compensation plans not approved by unitholders

 

 —

 

 —

 

 —

Total

 

167,571

 

16.250

 

1,874,029

​

​

​

​

​

​

​

​

(1)

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

—

—

4,166,054

Equity compensation plans not approved by unitholders

—

—

—

Total

​

—

​

—

​

4,166,054

(1)The long-term incentive plan currently permits the grant of awards covering an aggregate of 2,041,6008,241,600 units of which, 167,5714,075,546 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 17, 2023, Kimbell Holdings owns 30,000 common units, representing 0.04% 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 units and other partnership interests in the future and will be entitled to receive pro rata distributions in respect of those partnership interests.

Following the Restructuring, 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.

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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‑lengtharm’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 relaterelated to formation transactions that, by their nature, would not occur in a third‑partythird-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.

How We Pay Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. Available cash generally means:

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·

the sum of:

·

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

·

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;

·

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.

In addition, the limited liability company agreement of our General Partner will contain 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

We intend to distribute available cash to our 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.

Common Units

Each common unit will be entitled to receive cash distributions to the extent we distribute available cash. Common units will not accrue arrearages. 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 will not be 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.

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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 right of first offer to acquire mineral and royalty interests owned by certain of the Contributing Parties for a period of three years after the closing of our IPO;

·

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.

Right of First Offer. Under the contribution agreement, if certain of the Contributing Parties decide to sell, transfer or otherwise dispose of certain mineral and royalty interests in the Permian Basin, the Bakken/Williston Basin and the Marcellus Shale, they will provide us with the opportunity to make the first offer on such assets. The right of first offer will have a three‑year term from the closing of our IPO. The consummation and timing of any acquisition by us of the interests covered by our right of first offer will depend upon, among other things, the Contributing Parties’ decision to sell any of the assets covered by our right of first offer and our ability to reach an agreement with the Contributing Parties’ on price and other terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and the Contributing Parties are under no obligation to accept any offer that we may choose to make.

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,S-3, each of our Sponsors has the right to cause us to prepare and file a registration statement on Form S‑3S-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‑month12-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.

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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 certain limited matters, including as follows:

·

(i) For a period of one year following the closing of our IPO, the Contributing Parties will indemnify us for breaches of specified representations and warranties related to, among other things, (x) their authority to enter into the transactions contemplated by the contribution agreement and (y) the capitalization of the

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entities that will be contributed to us; and (ii) 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 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 and title defects 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

In connection with the closing of our IPO, weWe 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‑SponsorNon-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‑SponsorNon-Sponsor Managers have terminated. During 2017,the years ended December 31, 2022, 2021 and 2020, we paid to Kimbell Operating a monthly services feefees equal to $327,667,$0.2 million, $1.0 million and $0.9 million, respectively, which amount representsamounts 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‑SponsorNon-Sponsor Managers.

Services Agreements with Our Sponsors

Services. In connection with the closing of our IPO, Kimbell Operating entered intocurrently has services agreements with BJF Royalties, LLC (“BJF Royalties”), Steward Royalties, Taylor Companies and K3 Royalties (collectively, the “Sponsor Managers”), which are entities controlled by Messrs. Fortson R. Ravnaas, Taylor 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, 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.

·

●

Steward Royalties: For all of our assets and the assets of our affiliates, Steward Royalties  assists in sourcing, evaluating (including providing pricing guidance, reservoir engineering analysis, and geological work), and negotiating acquisition opportunities for us; and provides ongoing petroleum engineering services.

·

Taylor Companies:

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·

Taylor Companies assists in sourcing, evaluating (including directing all land and legal due diligence) and negotiating acquisition opportunities for us; assists in notifying and providing recorded transfer documents for newly acquired properties; assists in retaining outside legal counsel and landmen in connection with acquisition opportunities; maintains land and legal records with respect to newly acquired properties; and performs certain additional services with respect to newly acquired properties.

·

In addition, with respect to certain of our subsidiaries and assets, Taylor Companies provides management services including: negotiating and executing leases, right of way agreements, pooling orders and similar agreements and orders; providing certain recordkeeping services; resolving title issues; receiving and disbursing royalty and other payments; and providing certain additional accounting, title, human resources, regulatory compliance and other services.

·

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.

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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, with the Sponsor Managers, Kimbell Operating paid to Steward Royalties, Taylor Companies and K3 Royalties a monthly services fee of approximately $10,417, $33,333 and $10,000, respectively, for the period from February 8, 2017 to December 31, 2017. The services agreements were amended on March 7, 2018 to provide that Kimbell Operating will pay to Steward Royalties and Taylor Companies a monthly services fee of approximately $10,833 and $43,905, respectively, for the period from January 1, 2018 to December 31, 2018. K3 Royalties will continue to receive a monthly services fee of $10,000 for the period from January 1, 2018 toyears ended December 31, 2018.2022, 2021 and 2020. These amounts represent an estimated allocation of all projected costs to be incurred by such Sponsor Manager in providing services to Kimbell Operating.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, 2023 through December 31, 2023. 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‑partythird-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 is five years, after which date they will continue on a year‑to‑yearyear-to-year basis unless terminated by Kimbell Operating or by the applicable Sponsor Manager upon 90 days’ notice, except as otherwise stated below:

·

●

After the second anniversary of our IPO, theThe 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

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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.

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.

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Other Services Agreements

Management Services. In connection with the closing of our IPO, Kimbell Operating entered intopreviously had services agreements with Nail Bay Royalties and Duncan Management, LLC (collectively, the “Non‑Sponsor“Non-Sponsor Managers”), which are entities controlled by Mr. Duncan.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‑SponsorNon-Sponsor Managers provideprovided management, administrative and operational services to Kimbell Operating. These services include,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‑SponsorNon-Sponsor Managers, Kimbell Operating paid a services fee of approximately $116,341 for the year ended December 31, 2022. Kimbell Operating paid to Nail Bay Royalties and Duncan Managementthe Non-Sponsor Managers a monthly services fee of approximately $41,960$70,817 and $54,870, respectively,$68,806 for the year period from February 8, 2017 toyears ended December 31, 2017. The services agreements were amended on March 7, 2018, to provide that Kimbell Operating will pay to Nail Bay Royalties2021 and Duncan Management a monthly services fee of approximately $29,736 and $43,500, respectively, for the period from January 1, 2018 to December 31, 2018.2020, respectively. These amounts representrepresented an estimated allocation of all projected costs to be incurred by such Non‑SponsorNon-Sponsor Manager in providing services to Kimbell Operating. Subject toOperating for the approval of the Board of Directors, the monthly services fee will be adjusted (i) annually, (ii) in the event of any sale of serviced properties or (iii) in the event of the provision of any additional services by the Non‑Sponsor Manager. In addition, Kimbell Operating is required to reimburse each Non‑Sponsor Manager for all other reasonable costs and expenses (including, but not limited to, third‑party expenses and expenditures) that such Non‑Sponsor Manager incurs on behalf of Kimbell Operating in providing services. If Kimbell Operating terminates a services agreement for any reason other than the Non‑Sponsor Manager’s default (as described below), then Kimbell Operating will also reimburse the applicable Non‑Sponsor Manager for its reasonable costs and expenses incurred in connection with such termination.respective year.

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

·

After the second anniversary of our IPO, the applicable Non‑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 Non‑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  

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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 Non‑Sponsor Manager, upon 15 days’ notice to such Non‑Sponsor Manager. A Non‑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 any member of the Partnership Service Group.

·

Kimbell Operating or the Non‑Sponsor Manager may terminate the applicable services agreement upon the sale of all or substantially all of the properties serviced thereunder, upon at least 90 days’ notice to the other party.

Kimbell Operating’s only remedy for a Non‑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 Non‑SponsorNon-Sponsor Managers, Kimbell Operating agreed to indemnify each Non‑SponsorNon-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‑SponsorNon-Sponsor Managers dodid not have corresponding indemnification obligations with respect to Kimbell Operating.

Limited Liability Company Agreement of Kimbell Holdings

In connection with the closing of our IPO, ourOur 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.

Limited Liability Company Agreement of Kimbell Tiger Acquisition Sponsor, LLC

In connection with the formation of Tiger Sponsor, our executive officers and directors, among others, purchased equity interests in Tiger Sponsor. None of the individuals have voting or investment discretion with respect to the shares of TGR or TGR Opco held by Tiger Sponsor. The amount involved in each individual’s purchase did not exceed $120,000 per person.

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‑lawson-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 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‑situatedsimilarly-situated employees.

Robert D. Ravnaas served as President of Cawley, Gillespie & Associates, Inc. from 2011 until February 2017. Cawley, Gillespie & Associates, Inc. performed certain petroleum engineering services for the benefit of the Partnership. Compensation for such services totaled $123,393, $618,989 and $785,594 for the Predecessor 2017 Period and years ended December 31, 2016 and 2015, respectively. Mr. R. Ravnaas indirectly received a percentage of Cawley, Gillespie & Associates, Inc.’s revenues through his participation in the company’s employee bonus pool. In the aggregate, he received approximately $246,000 attributable to fees paid by the Partnership for the years ended December 31, 2016 and 2015.

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 will derivederived a commission of approximately $18,900 on $24,450, $22,160 and $20,160 for the years ended December 31, 2022, 2021 and 2020, respectively, for

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the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense iswas approximately $320,000.$611,204, $555,640 and $440,160 for the years ended December 31, 2022, 2021 and 2020, respectively.

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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 boardBoard 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 boardBoard 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 boardBoard 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 boardBoard of Directors in light of the circumstances, the resolution may be determined by the boardBoard 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

OurBecause we are a publicly traded partnership, the NYSE does not require our Board of Directors has determined that William H. Adams III and Craig Stone areto have a majority of independent underdirectors. For a discussion of the independence standards of the NYSE.our Board of Directors, please read “Item 10. Directors, Executive Officers and Corporate Governance.”

​

Item 14. Principal Accounting Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The audit committee’sAudit Committee’s charter requires the audit committeeAudit 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, 20172022, 2021 and 20162020 were approved by the audit committee.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, 

​

​

2022

​

2021

​

2020

Audit Fees (1)

​

$

915,208

​

$

771,214

​

$

691,569

Audit-Related Fees (2)

​

 

—

​

 

—

​

 

—

Tax Fees (3)

​

 

—

​

 

—

​

 

—

All Other Fees (4)

​

 

—

​

 

—

​

 

—

Total

​

$

915,208

​

$

771,214

​

$

691,569

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

Audit Fees (1)

 

$

294,775

 

 

$

98,050

 

$

737,684

Audit-Related Fees (2)

 

 

37,100

 

 

 

 —

 

 

 —

Tax Fees (3)

 

 

 —

 

 

 

 —

 

 

 —

All Other Fees (4)

 

 

 —

 

 

 

 —

 

 

 —

Total

 

$

331,875

 

 

$

98,050

 

$

737,684

(1)Audit fees relate to professional services rendered in connection with the audit of our Annual Report, quarterly review of our Quarterly Reports, and quarterly review of financial statements included in our Registration Statement on Form S-1 filed with the SEC.

(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, agreed upon procedures required to comply with financial, accounting or regulatory reporting and assistance with internal control documentation requirements.

(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.

Audit fees relate to professional services rendered in connection with the audit of our Annual Report, quarterly review of our Quarterly Reports, and quarterly review of financial statements included in our Registration Statement on Form S-1 filed with the SEC.

(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.

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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‑1F-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

2.1

3.1

—

Contribution, Conveyance, Assignment and Assumption Agreement, dated as of December 20, 2016, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Intermediate GP, LLC, Kimbell Intermediate Holdings, LLC, Kimbell Royalty Holdings, LLC, and the other parties named therein (incorporated by reference to Exhibit 2.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S‑1 (File No. 333‑215458) filed on January 6, 2017)

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‑1S-1 (File No. 333‑215458)333-215458) filed on January 6, 2017)

3.2

—

FirstFourth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of February 8, 2017May 18, 2022 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8‑K8-K filed on February 14, 2017)May 18, 2022)

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‑1S-1 (File No. 333‑215458)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‑K8-K filed on February 14, 2017)

10.1†3.5

—

Second Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of May 18, 2022 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 18, 2022)

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 April 17, 2020, by and among Kimbell Royalty Partners, LP, Silver Spur Resources, LLC, SEP I Holdings, LLC, Springbok Energy Partners II Holdings, LLC (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on April 20, 2020)

4.3

—

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)

4.4*

—

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‑K8-K filed on February 7, 2017)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*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

—

Credit Agreement, dated as of January 11, 2017, among Kimbell Royalty Partners, LP, the several lenders from time to time parties thereto and Frost Bank, as administrative agent and sole arranger (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Amendment No. 1 to Registration Statement on Form S‑1S-1 (File No. 333‑215458)333-215458) filed on January 17, 2017)

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10.6†

—

Commitment Letter, dated as of May 28, 2018, by and between Kimbell Royalty Partners, LP and Frost Bank, Wells Fargo Bank, National Association, Credit Suisse AG, Cayman Islands Branch, Wells Fargo Securities, LLC and Credit Suisse Loan Funding LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 1, 2018)

10.7

—

Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Frost Bank, 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 18, 2018)

10.8

—

Total Commitment Increase Agreement, dated as of May 23, 2019, between Frost Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)

10.9

—

Additional Lender Agreement, dated as of May 23, 2019, between Independent Bank, Kimbell Royalty Partners, LP and Frost Bank, as administrative agent (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 28, 2019)

10.10††

—

Amendment No. 2 to Credit Agreement, dated as of December 8, 2020, 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 10.11 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 25, 2021)

10.11††

—

Amendment No. 3 to Credit Agreement, dated as of June 7, 2022, 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 Form 8-K filed on June 9, 2022)

10.12††

—

Amendment No. 4 to Credit Agreement, dated as of December 15, 2022, 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 Form 8-K filed on December 15, 2022)

10.13†

—

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‑K8-K filed on February 14, 2017)

10.710.14†

—

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)

10.15†

—

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)

10.16†

—

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‑K8-K filed on February 14, 2017)

10.810.17†

—

Management Services Agreement, dated February 8, 2017, by and between Duncan Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.3 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)

10.9*†

—

Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Duncan Management, LLC and Kimbell Operating Company, LLC

10.10†

—

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‑K8-K filed on February 14, 2017)

10.11*10.18†

—

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)

10.1210.19†

—

Amendment No. 2 to Management Services Agreement, dated February 8, 2017,December 10, 2018, by and between Nail BayK3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.510.17 to Kimbell Royalty Partners, LP’s Annual Report on Form 8‑K10-K filed on February 14, 2017)March 12, 2019)

109

Table of Contents

10.13*10.20†

—

Amendment No. 13 to Management Services Agreement, dated March 7, 2017,December 16, 2019, by and between Nail BayK3 Royalties, LLC and Kimbell Operating Company, LLC

10.14†

—

Management Services Agreement, dated February 8, 2017, by and between Steward Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.6 to Kimbell Royalty Partners, LP’s Form 8‑K filed on February 14, 2017)

10.15*†

—

Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between Steward Royalties, LLC and Kimbell Operating Company, LLC

10.16†

—

Management Services Agreement, dated February 8, 2017, by and between Taylor Companies Mineral Management, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.710.18 to Kimbell Royalty Partners, LP’s Form 8‑K10-K filed on February 14, 2017)28, 2020)

117

Table of Contents

10.17*†10.21

—

Amendment No. 1 to Management ServicesExchange Agreement, dated March 7,as of September 23, 2018, by and between Taylor Companies Mineralamong 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)

10.22

—

Purchase and Sale Agreement, dated November 3, 2022, by and among Hatch Royalty LLC, Kimbell Royalty Partners, LP 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 November 3, 2022)

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)13a-14(a)/15d‑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)13a-14(a)/15d‑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

99.1*

—

Report of Ryder Scott Company, L.P. as of December 31, 20172020

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—Filed herewith.

**    —furnished herewith—Furnished herewith.

†      —Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10‑KAnnual 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.

​

110118

Table of Contents

SIGNATURES

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: March 9, 2018February 23, 2023

​

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

​

​

​

​

Name

Title

Date

​

/s/ Robert D. Ravnaas

​

Chairman of the Board of Directors and Chief

​

​

Robert D. Ravnaas

​

Executive Officer (Principal Executive Officer)

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ R. Davis Ravnaas

R. Davis Ravnaas

​

President and Chief Financial Officer (Principal

​

​

R. Davis Ravnaas

​

Financial Officer)

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Jeff McInnisR. Blayne Rhynsburger

​

Chief Accounting Officer​

​

​

Jeff McInnisR. Blayne Rhynsburger

​

(PrincipalController (Principal Accounting Officer)

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ William H. Adams III

​

​

​

​

William H. Adams III

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Benny D. DuncanErik B. Daugbjerg

​

​

​

​

Benny D. DuncanErik B. Daugbjerg

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Ben J. Fortson

​

​

​

​

Ben J. Fortson

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ T. Scott Martin

​

​

​

​

T. Scott Martin

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Craig Stone

​

​

​

​

Craig Stone

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Brett G. Taylor

​

​

​

​

Brett G. Taylor

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

/s/ Mitch S. Wynne

​

​

​

​

Mitch S. Wynne

​

Director

​

March 9, 2018February 23, 2023

​

​

​

​

​

​

​

​

111119

Table of Contents

INDEX TO FINANCIAL STATEMENTS

​

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)

F-2F-2

​

​

Consolidated Balance Sheets at December 31, 20172022 and 20162021

F-3F-5

​

​

Consolidated Statements of Operations for the Period from February 8, 2017 throughYears Ended December 31, 2017, the Period from January 1, 2017 through February 7, 20172022, 2021 and 2020

F-6

​

​

Consolidated Statements of Changes in Unitholders’ Equity for the Years Ended December 31, 20162022, 2021 and 20152020

F-4F-7

​

​

Consolidated Statements of Changes in Partners’ Capital for the Period from February 8, 2017 through December 31, 2017 and Members’ Equity for the Period from January 1, 2017 through February 7, 2017 and the Years Ended December 31, 2016 and 2015

F-5

Consolidated Statements of Cash Flows for the Period from February 8, 2017 through December 31, 2017, the Period from January 1, 2017 through February 7, 2017 and the Years Ended December 31, 20162022, 2021 and 20152020

F-6F-8

​

​

Notes to Consolidated Financial Statements

F-7F-10

​

​

F-1

Table of Contents

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 (the(collectively, the “Partnership”) as of December 31, 20172022 and December 31, 2016,2021, the related consolidated statements of operations, changes in partners’ capital and predecessor members’unitholders’ equity, and cash flows for each of the three years in the period from February 8, 2017 to December 31, 2017 (Partnership), January 1, 2017 to February 7, 2017 (Predecessor), and the years ended December 31, 2016 and December 31, 2015 (Predecessor),2022, 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, 20172022 and December 31, 2016,2021, and the results of its operations and its cash flows for each of the three years in the period from February 8, 2017 to December 31, 2017 (Partnership), January 1, 2017 to February 7, 2017 (Predecessor), and the years ended December 31, 2016 and December 31, 2015 (Predecessor),2022, 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, 2022, 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 23, 2023 expressed an unqualified opinion.

​

We did not audit the consolidated financial statements of Kimbell Tiger Acquisition Corporation, a consolidated variable interest entity, which statements reflect total assets constituting 22% of consolidated total assets as of December 31, 2022, and total revenues of 0% of consolidated total revenues for the year 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 Public Company Accounting Oversight Board (United States) (“PCAOB”)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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

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 supportingregarding 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 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 NGLs produced and sold from the property.  Production settlement statements from operators may not be received for one

F-2

Table of Contents

to four months after the date production is delivered, and 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, 2022, the Partnership has accrued $47 million of revenues that are included in oil, natural gas and NGL receivables in the consolidated balance sheet. 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 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 revenues.

​

Our audit procedures related to the estimation of accrued revenues included the following, among others.

●We evaluated the design and tested the operating effectiveness of 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 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.
●We assessed the completeness and accuracy of the accrued revenues through disaggregated analytical procedures.

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 record depletion expense and to determine if any impairment exists for its 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 as of December 31, 2022 was $753 million and the Partnership recorded depletion expense of $50 million for the year ended December 31, 2022. The Partnership did not record an impairment on its oil and natural gas properties for the year ended December 31, 2022.  The Partnership’s estimates of proved reserves are prepared by an independent petroleum engineering firm.  Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including the quantities of oil and natural gas reserves ultimately recovered by the Partnership’s 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 and tax rates by jurisdiction.  We identified the estimation of proved reserves 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 could have a significant impact on the estimation of proved reserves, and in turn, depletion expense and impairment. 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.

​

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

●We evaluated the design and tested the operating effectiveness of internal controls over the Partnership’s process to estimate proved reserves.
●We evaluated the level of knowledge, skill, and ability 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 inputs used to estimate proved reserves for consistency with requirements under the full cost method of accounting.

F-3

Table of Contents

●We performed disaggregated analytical procedures to test the reasonableness of the volumes and cash flows projected from the proved reserves.
●We selected a sample of wells to test the inputs used in the estimation of proved reserves, including volumes, pricing, and tax rates by jurisdiction.

​

/s/ GRANT THORNTON LLP

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

​

Dallas, Texas

March 9, 2018February 23, 2023

​

​

F-2F-4

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

December 31, 

 

 

December 31, 

 

 

2017

 

 

2016

ASSETS

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

5,625,495

 

 

$

505,880

Oil, natural gas and NGL receivables

 

 

6,792,837

 

 

 

474,103

Accounts receivable and other current assets

 

 

236,673

 

 

 

344,368

Total current assets

 

 

12,655,005

 

 

 

1,324,351

Property and equipment, net

 

 

165,232

 

 

 

261,568

Oil and natural gas properties

 

 

 

 

 

 

 

Oil and natural gas properties, using full cost method of accounting

 

 

297,609,797

 

 

 

70,888,121

Less: accumulated depreciation, depletion, accretion and impairment

 

 

(15,394,238)

 

 

 

(51,948,355)

Total oil and natural gas properties

 

 

282,215,559

 

 

 

18,939,766

Loan origination costs, net

 

 

255,208

 

 

 

13,046

Total assets

 

$

295,291,004

 

 

$

20,538,731

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS' CAPITAL (PREDECESSOR MEMBERS' EQUITY)

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Accounts payable

 

$

316,486

 

 

$

1,030,862

Other current liabilities

 

 

1,746,662

 

 

 

112,508

Commodity derivative liabilities

 

 

183,957

 

 

 

 —

Asset retirement obligations

 

 

 —

 

 

 

27,013

Total current liabilities

 

 

2,247,105

 

 

 

1,170,383

Asset retirement obligations

 

 

 —

 

 

 

14,468

Other liabilities

 

 

 —

 

 

 

123,158

Long-term debt

 

 

30,843,593

 

 

 

10,598,860

Commodity derivative liabilities

 

 

134,872

 

 

 

 —

Total liabilities

 

 

33,225,570

 

 

 

11,906,869

Commitments and contingencies

 

 

 

 

 

 

 

Predecessor members' equity

 

 

 —

 

 

 

8,631,862

Partners' capital

 

 

262,065,434

 

 

 

 —

Total liabilities and partners' capital (predecessor members' equity)

 

$

295,291,004

 

 

$

20,538,731

​

​

​

​

​

​

​

​

​

December 31, 

​

December 31, 

​

​

2022

​

2021

ASSETS

​

​

​

​

​

​

Current assets

​

​

​

​

​

​

Cash and cash equivalents

​

$

24,635,718

​

$

7,052,414

Oil, natural gas and NGL receivables

​

​

46,993,711

​

​

35,147,145

Derivative assets

​

​

—

​

​

166,307

Accounts receivable and other current assets

​

​

3,562,912

​

​

3,051,593

Total current assets

​

​

75,192,341

​

​

45,417,459

Property and equipment, net

​

​

953,781

​

​

1,888,247

Investment in affiliate (equity method)

​

​

—

​

​

4,738,822

Oil and natural gas properties

​

​

​

​

​

​

Oil and natural gas properties, using full cost method of accounting ($207,695,343 and $153,284,173 excluded from depletion at December 31, 2022 and December 31, 2021, respectively)

​

​

1,465,985,718

​

​

1,204,395,484

Less: accumulated depreciation, depletion and impairment

​

​

(712,716,951)

​

​

(663,603,142)

Total oil and natural gas properties, net

​

​

753,268,767

​

​

540,792,342

Right-of-use assets, net

​

​

2,525,323

​

​

2,844,997

Derivative assets

​

​

754,786

​

​

1,590,501

Loan origination costs, net

​

​

3,004,104

​

​

4,214,484

Assets of consolidated variable interest entities:

​

​

​

​

​

​

Cash

​

​

390,850

​

​

—

Investments held in trust

​

​

240,621,146

​

​

—

Prepaid expenses

​

​

35,201

​

​

—

Total assets

​

$

1,076,746,299

​

$

601,486,852

​

​

​

​

​

​

​

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY

​

​

​

​

​

​

Current liabilities

​

​

​

​

​

​

Accounts payable

​

$

1,210,337

​

$

811,019

Other current liabilities

​

​

4,909,510

​

​

3,319,495

Derivative liabilities

​

​

12,646,720

​

​

24,190,678

Total current liabilities

​

​

18,766,567

​

​

28,321,192

Operating lease liabilities, excluding current portion

​

​

2,236,361

​

​

2,561,274

Derivative liabilities

​

​

432,142

​

​

4,190,776

Long-term debt

​

​

233,015,911

​

​

217,115,911

Other liabilities

​

​

322,917

​

​

447,918

Liabilities of consolidated variable interest entities:

​

​

​

​

​

​

Other current liabilities

​

​

512,725

​

​

—

Deferred underwriting commissions

​

​

8,050,000

​

​

—

Total liabilities

​

​

263,336,623

​

​

252,637,071

Commitments and contingencies (Note 15)

​

​

​

​

​

​

Mezzanine equity:

​

​

​

​

​

​

Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

​

​

236,900,000

​

​

—

Kimbell Royalty Partners, LP unitholders' equity:

​

​

​

​

​

​

Common units (64,231,833 units and 47,162,773 units issued and outstanding as of December 31, 2022 and December 31, 2021, respectively)

​

​

601,841,776

​

​

328,717,841

Class B units (15,484,400 and 17,611,579 units issued and outstanding as of December 31, 2022 and December 31, 2021, respectively)

​

​

774,220

​

​

880,579

Total Kimbell Royalty Partners, LP unitholders' equity

​

​

602,615,996

​

​

329,598,420

Non-controlling (deficit) interest in OpCo

​

​

(26,106,320)

​

​

19,251,361

Total equity

​

​

576,509,676

​

​

348,849,781

Total liabilities, mezzanine equity and unitholders' equity

​

$

1,076,746,299

​

$

601,486,852

​

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

​

F-3F-5

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

 

2015

Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil, natural gas and NGL revenues

 

$

30,665,092

 

 

$

318,310

 

$

3,606,659

 

$

4,684,923

Loss on commodity derivative instruments

 

 

(318,829)

 

 

 

 —

 

 

 —

 

 

 —

Total revenues

 

 

30,346,263

 

 

 

318,310

 

 

3,606,659

 

 

4,684,923

Costs and expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and ad valorem taxes

 

 

2,452,058

 

 

 

19,651

 

 

280,474

 

 

426,885

Depreciation, depletion and accretion expense

 

 

15,546,341

 

 

 

113,639

 

 

1,604,208

 

 

4,008,730

Impairment of oil and natural gas properties

 

 

 —

 

 

 

 —

 

 

4,992,897

 

 

28,673,166

Marketing and other deductions

 

 

1,648,895

 

 

 

110,534

 

 

750,792

 

 

747,264

General and administrative expense

 

 

8,191,792

 

 

 

532,035

 

 

1,746,218

 

 

1,789,884

Total costs and expenses

 

 

27,839,086

 

 

 

775,859

 

 

9,374,589

 

 

35,645,929

Operating income (loss)

 

 

2,507,177

 

 

 

(457,549)

 

 

(5,767,930)

 

 

(30,961,006)

Other expense

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

791,437

 

 

 

39,307

 

 

424,841

 

 

385,119

Income (loss) before income taxes

 

 

1,715,740

 

 

 

(496,856)

 

 

(6,192,771)

 

 

(31,346,125)

State income taxes

 

 

 —

 

 

 

 —

 

 

19,848

 

 

(32,199)

Net income (loss)

 

$

1,715,740

 

 

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.11

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

Diluted

 

$

0.10

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,336,871

 

 

 

604,137

 

 

604,137

 

 

604,137

Diluted

 

 

16,455,602

 

 

 

604,137

 

 

604,137

 

 

604,137

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Revenue

​

​

​

​

​

​

​

​

​

Oil, natural gas and NGL revenues

​

$

281,964,126

​

$

175,088,021

​

$

92,586,685

Lease bonus and other income

​

​

3,073,609

​

​

3,319,104

​

​

345,771

Loss on commodity derivative instruments, net

​

​

(36,978,550)

​

​

(42,791,909)

​

​

(2,450,541)

Total revenues

​

​

248,059,185

​

​

135,615,216

​

​

90,481,915

Costs and expenses

​

​

​

​

​

​

​

​

​

Production and ad valorem taxes

​

​

16,238,814

​

​

10,480,481

​

​

6,389,231

Depreciation and depletion expense

​

​

50,086,414

​

​

36,797,881

​

​

47,988,796

Impairment of oil and natural gas properties

​

​

—

​

​

—

​

​

251,558,557

Marketing and other deductions

​

​

13,383,074

​

​

12,048,643

​

​

9,376,375

General and administrative expense

​

​

29,128,659

​

​

26,977,519

​

​

25,902,496

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

General and administrative expense

​

​

2,304,445

​

​

—

​

​

​

Total costs and expenses

​

​

111,141,406

​

​

86,304,524

​

​

341,215,455

Operating income (loss)

​

​

136,917,779

​

​

49,310,692

​

​

(250,733,540)

Other income (expense)

​

​

​

​

​

​

​

​

​

Equity income in affiliate

​

​

2,668,844

​

​

1,119,819

​

​

763,988

Interest expense

​

​

(13,818,310)

​

​

(9,182,103)

​

​

(6,430,061)

Loss on extinguishment of debt

​

​

—

​

​

—

​

​

(476,350)

Other income (expense)

​

​

4,043,530

​

​

1,263,566

​

​

(100,000)

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Interest earned on marketable securities in trust account

​

​

3,721,145

​

​

—

​

​

​

Net income (loss) before income taxes

​

​

133,532,988

​

​

42,511,974

​

​

(256,975,963)

Income tax expense (benefit)

​

​

2,738,702

​

​

74,100

​

​

(885,193)

Net income (loss)

​

​

130,794,286

​

​

42,437,874

​

​

(256,090,770)

Distribution and accretion on Series A preferred units

​

​

—

​

​

(11,249,969)

​

​

(7,810,588)

Net (income) loss and distributions and accretion on Series A preferred units attributable to non-controlling interests in OpCo

​

​

(18,822,552)

​

​

(8,496,104)

​

​

96,642,334

Distribution on Class B units

​

​

(42,243)

​

​

(76,780)

​

​

(91,869)

Net income (loss) attributable to common units of Kimbell Royalty Partners, LP

​

$

111,929,491

​

$

22,615,021

​

$

(167,350,893)

​

​

​

​

​

​

​

​

​

​

Net income (loss) per unit attributable to common units of Kimbell Royalty Partners, LP

​

​

​

​

​

​

​

​

​

Basic

​

$

1.75

​

$

0.56

​

$

(4.85)

Diluted

​

$

1.72

​

$

0.51

​

$

(4.85)

Weighted average number of common units outstanding

​

​

​

​

​

​

​

​

​

Basic

​

​

54,112,595

​

​

40,400,907

​

​

34,530,398

Diluted

​

​

65,837,017

​

​

60,957,824

​

​

34,530,398

​

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

​

F-4F-6

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL AND PREDECESSOR MEMBERS’UNITHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

    

Units

    

Total

Members' equity - January 1, 2015 - Predecessor

 

 

604,137

 

$

48,197,616

 

 

 

 

 

 

 

Distribution to members

 

 

 —

 

 

(3,249,327)

 

 

 

 

 

 

 

Unit-based compensation

 

 

 —

 

 

605,059

 

 

 

 

 

 

 

Net income

 

 

 —

 

 

(31,313,926)

 

 

 

 

 

 

 

Members' equity - December 31, 2015 - Predecessor

 

 

604,137

 

 

14,239,422

 

 

 

 

 

 

 

Unit-based compensation

 

 

 —

 

 

605,059

 

 

 

 

 

 

 

Net income

 

 

 —

 

 

(6,212,619)

 

 

 

 

 

 

 

Members' equity - December 31, 2016 - Predecessor

 

 

604,137

 

 

8,631,862

 

 

 

 

 

 

 

Unit-based compensation

 

 

 —

 

 

50,422

 

 

 

 

 

 

 

Net loss

 

 

 —

 

 

(496,856)

 

 

 

 

 

 

 

Transfer of membership units to Rivercrest Royalties Holdings, LLC

 

 

(604,137)

 

 

(98,988)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners' capital - February 8, 2017 - Partnership

 

 

 —

 

 

8,086,440

 

 

 

 

 

 

 

Common units issued to Predecessor in exchange for oil and natural gas properties

 

 

1,191,974

 

 

 —

 

 

 

 

 

 

 

Common units issued to contributors in exchange for oil and natural gas properties

 

 

9,390,734

 

 

169,033,212

 

 

 

 

 

 

 

Common units sold to public

 

 

5,750,000

 

 

103,500,000

 

 

 

 

 

 

 

Underwriting discount and structuring fee incurred at initial public offering

 

 

 —

 

 

(7,245,000)

 

 

 

 

 

 

 

Distributions to unitholders

 

 

 —

 

 

(13,823,371)

 

 

 

 

 

 

 

Unit-based compensation

 

 

177,091

 

 

798,413

 

 

 

 

 

 

 

Net income

 

 

 —

 

 

1,715,740

 

 

 

 

 

 

 

Partners' capital - December 31, 2017 - Partnership

 

 

16,509,799

 

$

262,065,434

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Non-controlling

​

Non-controlling

​

​

​

​

Common Units

   

Amount

​

   Class B Units

   

Amount

​

Interest
in OpCo

​

Interest
in TGR

​

Total

Balance at January 1, 2020

​

​

23,518,652

​

$

282,549,841

​

​

25,557,606

​

$

1,277,880

​

$

281,157,393

​

$

—

​

$

564,985,114

Common units issued for equity offering

​

​

5,000,000

​

​

73,601,668

​

​

—

​

​

—

​

​

—

​

​

—

​

​

73,601,668

Units issued for Springbok Acquisition

​

​

2,224,358

​

​

13,257,174

​

​

2,497,134

​

​

124,857

​

​

14,758,062

​

​

—

​

​

28,140,093

Conversion of Class B units to common units

​

​

7,274,959

​

​

92,065,325

​

​

(7,274,959)

​

​

(363,748)

​

​

(92,065,325)

​

​

—

​

​

(363,748)

Redemption of Series A preferred units

​

​

—

​

​

(16,150,018)

​

​

—

​

​

—

​

​

(9,697,873)

​

​

—

​

​

(25,847,891)

Restricted units used for tax withholding

​

​

(29,181)

​

​

(273,244)

​

​

—

​

​

—

​

​

—

​

​

—

​

​

(273,244)

Forfeitures of restricted units

​

​

(16,737)

​

​

(127,934)

​

​

—

​

​

—

​

​

—

​

​

—

​

​

(127,934)

Unit-based compensation

​

​

946,638

​

​

9,535,000

​

​

—

​

​

—

​

​

—

​

​

—

​

​

9,535,000

Distributions to unitholders

​

​

—

​

​

(29,513,612)

​

​

—

​

​

—

​

​

(20,507,481)

​

​

—

​

​

(50,021,093)

Distribution and accretion on Series A preferred units

​

​

—

​

​

(4,946,646)

​

​

—

​

​

—

​

​

(2,863,942)

​

​

—

​

​

(7,810,588)

Distribution on Class B units

​

​

—

​

​

(91,869)

​

​

—

​

​

—

​

​

—

​

​

—

​

​

(91,869)

Net loss

​

​

—

​

​

(162,312,378)

​

​

—

​

​

—

​

​

(93,778,392)

​

​

—

​

​

(256,090,770)

Balance at December 31, 2020

​

​

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

​

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

F-5F-7

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

   

2021

​

2020

CASH FLOWS FROM OPERATING ACTIVITIES

​

​

​

​

​

​

​

​

​

Net income (loss)

​

$

130,794,286

​

$

42,437,874

​

$

(256,090,770)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

​

​

​

​

​

​

​

​

​

Depreciation and depletion expense

​

​

50,086,414

​

​

36,797,881

​

​

47,988,796

Impairment of oil and natural gas properties

​

​

—

​

​

—

​

​

251,558,557

Amortization of right-of-use assets

​

​

319,674

​

​

298,093

​

​

276,180

Amortization of loan origination costs

​

​

1,872,700

​

​

1,556,769

​

​

1,108,685

Loss on extinguishment of debt

​

​

—

​

​

—

​

​

476,350

Equity income in affiliate

​

​

(2,668,844)

​

​

(1,119,819)

​

​

(763,988)

Cash distribution from affiliate

​

​

3,770,651

​

​

1,015,559

​

​

812,810

Forfeiture of restricted units

​

​

(19,813)

​

​

—

​

​

(127,934)

Unit-based compensation

​

​

11,107,639

​

​

10,632,725

​

​

9,261,756

(Gain) loss on derivative instruments, net of settlements

​

​

(14,300,570)

​

​

20,343,783

​

​

7,085,364

Changes in operating assets and liabilities:

​

​

​

​

​

​

​

​

​

Oil, natural gas and NGL receivables

​

​

(11,846,567)

​

​

(17,594,389)

​

​

1,618,006

Accounts receivable and other current assets

​

​

(511,319)

​

​

(2,077,637)

​

​

(897,088)

Accounts payable

​

​

399,318

​

​

(77,716)

​

​

(319,001)

Other current liabilities

​

​

1,590,016

​

​

(463,828)

​

​

533,582

Operating lease liabilities

​

​

(324,913)

​

​

(306,814)

​

​

(275,964)

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Interest earned on marketable securities in trust account

​

​

(3,721,145)

​

​

—

​

​

—

Other assets and liabilities

​

​

88,966

​

​

—

​

​

—

Net cash provided by operating activities

​

​

166,636,493

​

​

91,442,481

​

​

62,245,341

CASH FLOWS FROM INVESTING ACTIVITIES

​

​

​

​

​

​

​

​

​

Purchases of property and equipment

​

​

(163,140)

​

​

(772,688)

​

​

(996,102)

Purchase of oil and natural gas properties

​

​

(141,297,776)

​

​

(55,300,252)

​

​

(87,600,123)

Investment in affiliate

​

​

—

​

​

—

​

​

(2,231,509)

Cash distribution from affiliate

​

​

3,637,015

​

​

500,389

​

​

—

Consolidated variable interest entities related:

​

​

​

​

​

​

​

​

​

Investments in marketable securities

​

​

(236,900,000)

​

​

—

​

​

—

Net cash used in investing activities

​

​

(374,723,901)

​

​

(55,572,551)

​

​

(90,827,734)

CASH FLOWS FROM FINANCING ACTIVITIES

​

​

​

​

​

​

​

​

​

Proceeds from equity offering

​

​

116,119,417

​

​

57,522,440

​

​

73,601,668

Contributions from Class B unitholders

​

​

363,641

​

​

—

​

​

—

Redemption of Class B contributions on converted units

​

​

(470,000)

​

​

(158,410)

​

​

(363,748)

Redemption on Series A preferred units

​

​

—

​

​

(67,081,680)

​

​

(61,089,600)

Distributions to common unitholders

​

​

(107,402,294)

​

​

(47,309,785)

​

​

(29,513,612)

Distribution to OpCo unitholders

​

​

(19,323,523)

​

​

(21,534,575)

​

​

(20,507,481)

Distribution and accretion on Series A preferred units

​

​

—

​

​

(2,800,012)

​

​

(4,812,509)

Distribution on Class B units

​

​

(42,243)

​

​

(76,780)

​

​

(91,869)

Borrowings on long-term debt

​

​

199,200,000

​

​

136,565,769

​

​

162,614,665

Repayments on long-term debt

​

​

(183,300,000)

​

​

(91,000,000)

​

​

(91,200,000)

Payment of loan origination costs

​

​

(662,320)

​

​

(684,767)

​

​

(4,454,394)

Restricted units repurchased for tax withholding

​

​

(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)

​

​

—

​

​

—

Net cash provided by (used in) financing activities

​

​

226,061,562

​

​

(38,622,493)

​

​

24,183,120

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

​

​

17,974,154

​

​

(2,752,563)

​

​

(4,399,273)

CASH AND CASH EQUIVALENTS, beginning of period

​

​

7,052,414

​

​

9,804,977

​

​

14,204,250

CASH AND CASH EQUIVALENTS, end of period

​

$

25,026,568

​

$

7,052,414

​

$

9,804,977

​

​

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

  

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

  

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

   

2017

  

 

2017

  

2016

  

2015

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

  

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

1,715,740

  

  

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

  

  

 

 

 

 

 

 

 

 

Depreciation, depletion and accretion expense

 

 

15,546,341

  

  

 

113,639

 

 

1,604,208

 

 

4,008,730

Impairment of oil and natural gas properties

 

 

 —

  

  

 

 —

 

 

4,992,897

 

 

28,673,166

Amortization of loan origination costs

 

 

57,292

  

  

 

4,241

 

 

46,969

 

 

40,965

Amortization of tenant improvement allowance

 

 

 —

  

  

 

(2,864)

 

 

(34,369)

 

 

(14,321)

Unit-based compensation

 

 

798,413

  

  

 

50,422

 

 

605,059

 

 

605,059

Loss on commodity derivative instruments

 

 

318,829

 

 

 

 —

 

 

 —

 

 

 —

Changes in operating assets and liabilities:

 

 

 

  

  

 

 

 

 

 

 

 

 

Oil, natural gas and NGL receivables

 

 

(1,689,609)

  

  

 

14,551

 

 

(66,455)

 

 

464,877

Accounts receivable and other current assets

 

 

(236,673)

  

  

 

333,056

 

 

1,027,172

 

 

(1,365,099)

Accounts payable

 

 

316,486

  

  

 

247,972

 

 

(952,800)

 

 

1,604,999

Other current liabilities

 

 

1,746,662

  

  

 

(77,442)

 

 

76,541

 

 

8,683

Net cash provided by operating activities

 

 

18,573,481

  

  

 

186,719

 

 

1,086,603

 

 

2,713,133

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

  

  

 

 

 

 

 

 

 

 

Purchases of property and equipment

 

 

(61,932)

  

  

 

 —

 

 

(19,305)

 

 

(31,960)

Purchase of oil and natural gas properties

 

 

(125,848,776)

  

  

 

(523)

 

 

(78,159)

 

 

(506,680)

Net cash used in investing activities

 

 

(125,910,708)

  

  

 

(523)

 

 

(97,464)

 

 

(538,640)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

  

  

 

 

 

 

 

 

 

 

Proceeds from initial public offering

 

 

96,255,000

  

  

 

 —

 

 

 —

 

 

 —

Distributions to unitholders / members

 

 

(13,823,371)

  

  

 

 —

 

 

 —

 

 

(4,507,818)

Borrowings on long-term debt

 

 

30,843,593

  

  

 

 —

 

 

 —

 

 

3,050,000

Repayments on long-term debt

 

 

 —

  

  

 

 —

 

 

(850,000)

 

 

(605,000)

Payment of loan origination costs

 

 

(312,500)

  

  

 

 —

 

 

(13,000)

 

 

 —

Net cash provided by (used in) financing activities

 

 

112,962,722

  

  

 

 —

 

 

(863,000)

 

 

(2,062,818)

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

 

5,625,495

  

  

 

186,196

 

 

126,139

 

 

111,675

CASH AND CASH EQUIVALENTS, beginning of period

 

 

 —

  

  

 

505,880

 

 

379,741

 

 

268,066

CASH AND CASH EQUIVALENTS, end of period

 

$

5,625,495

  

  

$

692,076

 

$

505,880

 

$

379,741

Supplemental cash flow information:

 

 

 

  

  

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

455,228

  

  

$

34,505

 

$

373,513

 

$

333,289

Cash paid for taxes

 

$

 —

  

  

$

5,355

 

$

25,892

 

$

7,358

Non-cash investing and financing activities:

 

 

 

  

  

 

 

 

 

 

 

 

 

Capital expenditures and consideration payable included in accounts payable and other liabilities

 

$

 —

  

  

$

 —

 

$

(37)

 

$

151,558

Capital expenditures through tenant improvement allowance

 

$

 —

  

  

$

 —

 

$

 —

 

$

171,848

F-8

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

   

2021

​

2020

Supplemental cash flow information:

​

​

​

​

​

​

​

​

​

Cash paid for interest

​

$

11,207,530

​

$

7,538,814

​

$

5,346,892

Cash paid for taxes

​

$

3,082,245

​

$

—

​

$

—

Non-cash investing and financing activities:

​

​

​

​

​

​

​

​

​

Class B units issued in exchange for oil and natural gas properties

​

$

120,292,459

​

$

—

​

$

28,140,092

Noncash effect of Series A preferred unit redemption

​

$

—

​

$

14,893,784

​

$

25,847,891

Noncash deemed distribution to Series A preferred units

​

$

—

​

$

9,431,794

​

​

2,998,079

Recognition of tenant improvement asset

​

$

125,001

​

$

447,917

​

$

—

Right-of-use assets obtained in exchange for operating lease liabilities

​

$

—

​

$

19,636

​

​

—

Consolidated variable interest entities related:

​

​

​

​

​

​

​

$

​

Deferred underwriting commissions

​

$

8,050,000

​

$

—

​

​

—

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

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

​

$

24,635,718

​

$

7,052,414

Cash held at consolidated variable interest entities

​

​

390,850

​

​

—

​

​

$

25,026,568

​

$

7,052,414

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

​

F-6F-9

​

​

Table

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” 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 Contentsthe 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.

KIMBELL ROYALTY PARNTERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP (the “Partnership”) is a Delaware limited partnership formed on October 30, 2015. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC, its general partner. The Partnership has adopted a fiscal year-end of December 31.

On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGLs”) production revenues of the Predecessor represented approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016.

The Predecessor is a Delaware limited liability company formed on October 25, 20132015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership elected to be taxed as a corporation for United States federal income tax purposes. As an owner of America (‘‘United States’’). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referredPartnership is entitled to as ‘‘mineral and royalty interests.’’ The Predecessor also had non-operated working interests in certaina portion of the revenues received from the production of oil, and natural gas properties. Priorand 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 IPO,primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Predecessor assignedContributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

On February 8, 2022, the Partnership announced the $230 million initial public offering of its non-operated workingspecial purpose acquisition company, Kimbell Tiger Acquisition Corporation (NYSE: TGR).

Kimbell Tiger Acquisition Corporation (“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 is a subsidiary of the Partnership, was created to assist TGR in sourcing, analyzing and consummating acquisition opportunities for that initial business combination.

TGR Sponsor and TGR have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021. This resulted in the consolidation of $241.0 million of assets, $8.6 million of liabilities, $236.9 million of redeemable non-controlling interests and associated asset retirement obligations (“ARO”)$17.4 million of common equity and $3.0 million of non-controlling interests related to an affiliated entity that was not contributed toTGR and TGR Sponsor as of December 31, 2022. Further details on the Partnership.impact of the consolidation of TGR and TGR Sponsor can be found in Note 3—Acquisitions, Joint Venture and Special Purpose Acquisition Company.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

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.

COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas

Coronavirus (“COVID-19”) remains a global health crisis and there continues to be considerable uncertainty regarding the ultimate impact of COVID-19 and its variants. Despite improvements in global economic activity levels and

F-10

Table of Contents

higher energy demand compared to 2021 and 2020, the impact of COVID-19 continues to be unpredictable, including the impact of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. The Partnership is unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact the Partnership’s business, results of operations, financial condition or cash flows. Commodity prices have risen from 2020; however, further negative impact from COVID-19 may require the Partnership to adjust its business plan.

The ultimate impact of COVID-19 and the volatility in the oil and natural gas markets on the Partnership’s business, cash flows, liquidity, financial condition and results of operations remain dependent on a number of factors, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, the ability of the Organization of Petroleum Exporting Countries, Russia and other crude oil producing nations to manage the global crude oil supply, additional actions by businesses and governments in response to the pandemic, the economic downturn and the decrease in crude oil demand, the speed and effectiveness of responses to combat the virus and the time necessary to balance crude oil supply and demand to restore crude oil pricing. Although prices have recovered, the ongoing impact of COVID-19 on our business, employees and operations, including supply chain concerns, among others still continues to affect our industry.

Russia / Ukraine Conflict

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. The conflict and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices.

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 equity‑basedthe fair value of equity-based compensation.

F-7

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

Reclassification of Prior Period Presentation

Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.

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.

Accounts ReceivableF-11

Table of Contents

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 Receivables

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. The Partnership estimates and records an allowance for doubtful accountsexpected 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, 2017,2022 and 2016,2021, no allowance for doubtful accountsexpected 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 statementstatements of operations within lossgain (loss) on commodity derivative instruments.

Interest Rate Swaps

The Partnership uses an interest rate swap for the management of interest rate risk exposure, as the interest rate swap effectively converts 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 are 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-

F-8

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

linestraight-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.

Oil and Natural Gas Properties

The Partnership follows the full costfull-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. The Partnership has not assigned any valueCosts associated with unevaluated properties are excluded from the full-cost pool until a determination as to unproved properties in which it holds an interest. The full cost ceilingthe existence of proved reserves is evaluated at the end of each period.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

F-12

Table of Contents

calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month12-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.

The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based For discussion regarding impairment on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with SEC guidance, management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017.

No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016see Note 6—Oil and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline in commodity prices and other factors.

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

F-9

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 20162022, 2021 or 2020.

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 2015.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 and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015.2022, 2021 or 2020.

Other Current Liabilities

At December 31, 2017Other current liabilities consist primarily of Series A preferred unit and 2016,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 Predecessor’s other current liabilities consistedBasis of the following:

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

December 31, 

 

 

December 31, 

 

 

2017

 

 

2016

Accrued ad valorem taxes

 

$

531,664

 

 

$

 -

Revenue payable

 

 

509,125

 

 

 

 -

Accrued revenue processing fees

 

 

344,314

 

 

 

 -

Accrued interest expense

 

 

278,925

 

 

 

 -

Other current liabilities

 

 

82,634

 

 

 

112,508

Total current liabilities

 

$

1,746,662

 

 

$

112,508

Asset Retirement Obligations

Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties.

Fair values of legal obligations to retire and remove long-lived assets were recorded when the obligation was incurred. When the liability was initially recorded,Presentation, the Partnership capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost in oil and natural gas properties was depleted based on units of production consistent with the related asset.

Other Long-Term Liabilities

The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reductionelected to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.

Income Taxes

The Partnership is a master limited partnership and isbe taxed as a partnership under the Internal Revenue Code whereby the Partnership’s partners are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provisioncorporation for United States federal income taxes.tax purposes, which became effective on September 24, 2018.

Texas imposes a franchiseDeferred tax commonly referredassets and liabilities are recognized for the future tax consequences attributable to astemporary differences between the Texas marginfinancial statement carrying amounts of existing assets and liabilities and their respective tax which is considered anbases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas marginyears in which those temporary differences are expected to be recovered or settled. The effect on deferred tax statute. The Partnershipassets and liabilities of a change in tax rates is recognized in income in the Predecessor incurred de minimis amountsperiod of state income taxes during 2017 and 2016.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 and the Predecessor had no uncertain tax positions at December 31, 20172022, 2021 and 2016.2020.

The Partnership and Predecessor recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the years ended December 31, 20162022, 2021 and 2015,2020, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions.

The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.F-13

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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.

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.

During the period from February 8, 2017 toyears ended December 31, 2017, one2022, 2021 and 2020, the Partnership’s top purchaser accounted for approximately 14% of oil, natural gas11.3%, 6.0% and NGL sales revenue. During the year ended December 31, 2016, three purchasers accounted for approximately 20%7.1%, 13% and 10%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. See Note 4—Derivatives for further discussion.

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 Recognitionfrom Contracts with Customers

The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s priceright to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

As an owner of mineral and royalty interests, the Partnership is entitled to a portion of thereceive revenues received from the production of oil, natural gas and associated NGLs fromNGL sales obtained by the underlying acreage, netoperator of post-production expensesthe 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 taxes. The pricingNGL 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 salesproduction 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.

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 propertiesproducer once production has occurred, at which point payment is primarily determined by supply and demandunconditional. 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 marketplacemonth production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and can fluctuate considerably.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

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revenue received historically have not been significant. For the year ended December 31, 2022, 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 and NGLssales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumevolumes and prices for thesethose properties are estimated and recorded within oil, natural gas, and NGL receivables in the accompanying consolidated balance sheets. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.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 55—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, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds are held in an actively-traded money market fund, which invests in U.S. Treasury securities. Investments held in trust are classified as trading securities and are presented on the balance

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Recently Issued Accounting Pronouncements

In January 2017,sheets at fair value at the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifyingend of each reporting period. Gains and losses resulting from the Definitionchange in fair value of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals)these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of assets or businesses.operations. The update requires that when substantially allestimated 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, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 3) sold in the gross assets acquired (or disposed of) is concentratedTGR IPO that are redeemable for cash by the public TGR shareholders concurrently with TGR’s initial business combination or in the event of TGR’s failure to complete a single identifiable assetbusiness combination or a grouptender offer. The redeemable non-controlling interests are initially recorded at their original issue price, net of similar identifiable assets,issuance costs and the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning afterinitial fair value of separately traded warrants. The carrying amount remains accreted to its full redemption value at December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that 2022.

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

Acquisitions

2022 Activity

On December 15, 2022, the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact oncompleted the Partnership’s financial statements or resultsacquisition of operations.

In June 2016,certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”). The aggregate consideration for the FASB issued ASU 2016‑13, "MeasurementHatch Acquisition consisted of Credit Losses on Financial Instruments." ASU 2016‑13 changes the impairment model for most financial assets(i) approximately $150.4 million in cash and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements.

In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers—Identifying Performance Obligations and Licensing.” This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity.

In March 2016, the FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at(ii) the issuance of its restricted7,272,821 OpCo common units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a resultand an equal number of adopting this standard.

In February 2016, the FASB issued ASU 2016‑02, "Leases." ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers’ (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either ‘‘full retrospective’’ adoption, meaning that the standard is applied to all of the periods presented with a cumulative

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

catch-up as of the earliest period presented, or ‘‘modified retrospective’’ adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures for any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures.  The Partnership has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. Additionally, the Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams. The Partnership intends to use the full retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018 and does not anticipate recording or disclosing any material transition adjustments upon adoption.

NOTE 3—ACQUISITIONS

In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million.Class B units. The Partnership funded these acquisitionsthe 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 October 9, 2017,March 10, 2021, the Partnership acquiredcompleted 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 underlying 8,460 gross acres, 983 net royalty acres, in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates (the “Cornerstone Acquisition”) for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah.$54.6 million. The Partnership funded this acquisitionthe 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.

2020 Activity

On November 8, 2017,April 17, 2020, the Partnership completed the acquisition of all of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”). The aggregate consideration for the Springbok Acquisition consisted of (i) approximately $95.0 million in cash, (ii) the issuance of 2,224,358 common units representing limited partner interests in the Partnership (“common units”) and (iii) the issuance of 2,497,134 newly issued common units of the Operating Company (“OpCo common units”) and an equal number of newly issued Class B common units representing limited partner interests of the Partnership (“Class B units”). At the time of the Springbok Acquisition, the acreage acquired mineral and royalty interests underlying 71,410 gross acres, 2,757had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins. The Springbok acquisition was accounted for as an aggregateasset

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acquisition and the allocation of the purchase price was $41.5 million to proved properties and $74.3 million to unevaluated 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 approximately $7.3$15.0 million. Net proceeds distributed to the Partnership were $6.5 million, in various counties in Arkansas. The Partnership funded this acquisition with borrowings under itsthe 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 December 13, 2017,July 29, 2021, TGR, the Partnership’s special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (“SEC”). On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of approximately $230,000,000 and incurring offering costs of approximately $12,650,000, inclusive of $8,050,000 in deferred underwriting commissions. Each unit consists of one share of Class A common stock, par value $0.0001 (the “TGR Class A common stock”), and one-half of one redeemable warrant. Each whole warrant may be exercised for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors are members of the sponsor of TGR, TGR Sponsor. 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 (the “Business Combination”). Under the terms of TGR’s governing documents, TGR has until May 8, 2023 (15 months from the closing of the TGR IPO) to complete the Business Combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

In connection with the closing of the TGR IPO, completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor, which is a subsidiary of the Partnership, acquiredfor a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3$1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant is exercisable to purchase for $11.50 one share of TGR Class A common stock.

In addition, TGR incurred $12.7 million of fees and expenses, of which $8.1 million were deferred underwriting commissions that will become payable to the underwriters solely in the event that TGR completes the Business Combination, which were included in deferred underwriting commissions on the accompanying consolidated balance sheet at December 31, 2022.

In May 2021, prior to TGR’s IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR Class A common stock. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The core positionsshares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are locatedcollectively referred to as the “Founders Shares.” The Founders Shares will be exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco are substantially similar, other than certain distribution rights, and are entitled to vote together as a single class on all matters submitted for stockholder vote.

In determining the accounting treatment of the Partnership’s equity interest in CaliforniaTGR, management concluded that TGR is a VIE as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor is the primary beneficiary of TGR as it has, through

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its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impact TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR is consolidated into the Partnership’s financial statements through TGR Sponsor.

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 Wyomingcertain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. A minimum balance of $236.9 million, representing the number of TGR units sold at a redemption value of $10.30 per unit, is required by the underwriting agreement to be maintained in the trust account. The proceeds held in the trust account are only permitted to be invested in U.S. government treasury obligations with a maturity of 185 days or less or in money market funds meeting certain conditions under Rule 2a-7 of the Investment Company Act that invest only in direct U.S. government treasury obligations. In connection with the trust account, the Partnership reported investments held in trust of $240.6 million on the accompanying consolidated balance sheet as of December 31, 2022.

The public unitholders’ ownership of TGR Class A common stock represents a redeemable non-controlling interest to the Partnership, which is classified outside of permanent unitholders’ equity as the TGR Class A common stock is redeemable at the option of the public unitholders in connection with the Business Combination. The carrying amount of the redeemable non-controlling interest is equal to the greater of (i) the initial carrying amount, increased or decreased for the redeemable non-controlling interest’s share of TGR’s net income or loss and distributions or (ii) the redemption value. The public unitholders of TGR Class A common stock will be entitled in certain circumstances to redeem their shares of TGR Class A common stock for a pro rata portion of the amount in the trust account at $10.30 per share of TGR Class A common stock held, plus any pro rata interest earned on the funds held in the trust account. As of December 31, 2022, the carrying amount of the redeemable non-controlling interest was recorded at its redemption value of $236.9 million. Remeasurements to the redemption value of the redeemable non-controlling interest are recognized as a deemed dividend and are recorded directly to unitholders’ equity on the accompanying consolidated balance sheets.

If TGR has not completed the Business Combination within such 15-month period (or 18-month or 21-month period, as applicable, if TGR Sponsor exercises its extension options), TGR will: (1) cease all operations except for the purpose of winding up; (2) as promptly as reasonably possible but not more than 10 business days thereafter, redeem the public shares, at a per-share price, payable in cash, equal to the aggregate amount then on deposit in the trust account, including interest (less an amount required to satisfy taxes of TGR and TGR Opco and up to $100,000 of interest to pay dissolution expenses), divided by the number of then outstanding public shares and Class A units of Opco (other than those held by TGR), which redemption will completely extinguish the public stockholders’ rights as stockholders (including the right to receive further liquidating distributions, if any); and (3) as promptly as reasonably possible following such redemption, subject to the approval of TGR’s remaining stockholders and board of directors, dissolve and liquidate, subject in each case to TGR’s obligations under Delaware law to provide for claims of creditors and the package also includes small interests locatedrequirements of other applicable law. There will be no redemption rights or liquidating distributions with respect to TGR’s warrants, which will expire worthless if TGR fails to complete the Business Combination within such 15-month period (or 18-month or 21-month period, as applicable, if the TGR Sponsor exercises its extension options).

As of December 31, 2022, the Partnership owned approximately 20% of the common stock of TGR and the net loss and net assets of TGR were consolidated with the Partnership’s financial statements. The remaining approximately 80% of the consolidated net loss and net assets of TGR, representing the percentage of economic interest in Kansas, Arkansas, TexasTGR held by public shareholders of TGR through their ownership of TGR common stock, were allocated to redeemable non-controlling interest. The total assets of TGR are $241.0 million and Utah.total liabilities are $8.6 million as of December 31, 2022. The assets of TGR held outside of trust can only be used to settle obligations of TGR and there is no recourse to the Partnership funded this acquisition with borrowings under its secured revolving credit facility.for TGR’s liabilities. All warrants and TGR Class B common stock held by the Partnership are eliminated in consolidation. Also, all transactions between TGR and the Partnership, as well as related financial statement impact, are eliminated in consolidation.

F-18

Table of Contents

NOTE 4—DERIVATIVES

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To reducemitigate the impact of fluctuations ininherent commodity price risk associated with its operations, the Partnership uses oil and natural gas prices on revenues, the Partnership entered into commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively, with a trade date of December 12, 2017, as to reduce its exposure to price volatility of oil and natural gas.other contractual arrangements. The Partnership enteredenters into oil and natural gas derivative instrument contracts that contain netting arrangements. The counterparty to the contracts is an unrelated third party.arrangements with each counterparty.

F-13

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are presented on a net basis in the accompanying consolidated statement of operations and consisted of the following:

Period from February 8, 2017 to December 31, 

2017

Beginning fair value of commodity derivative instruments

$

 —

Loss on commodity derivative instruments

(318,829)

Ending fair value of commodity derivative instruments

$

(318,829)

At December 31, 2017,2022, 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 hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of December 31, 2022, these economic hedges constituted approximately 21% of daily oil and natural gas production.

OurThe Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and ourits natural gas fixed price swap transactions are settled based upon the last scheduled trading day settlement of the first nearby month futures contract ofcorresponding 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, 

​

​

2022

​

2021

​

2020

Beginning fair value of derivative instruments

​

$

(26,624,646)

​

$

(6,280,863)

​

$

804,501

Loss on derivative instruments

​

​

(32,240,915)

​

​

(41,240,942)

​

​

(2,450,541)

Net cash paid (received) on settlements of derivative instruments

​

​

46,541,485

​

​

20,897,159

​

​

(4,634,823)

Ending fair value of derivative instruments

​

$

(12,324,076)

​

$

(26,624,646)

​

$

(6,280,863)

​

F-19

Table of Contents

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

​

2022

​

2021

Assets:

​

​

​

​

​

​

​

​

Current assets

​

Derivative assets

​

$

—

​

$

166,307

Long-term assets

​

Derivative assets

​

​

754,786

​

​

1,590,501

Liabilities:

​

​

​

​

​

​

​

​

Current liabilities

​

Derivative liabilities

​

​

(12,646,720)

​

​

(24,190,678)

Long-term liabilities

​

Derivative liabilities

​

​

(432,142)

​

​

(4,190,776)

​

​

​

​

$

(12,324,076)

​

$

(26,624,646)

​

At December 31, 2017,2022, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

 

 

 

 

 

 

 

 

Notional

 

Weighted Average

 

 

Volumes (MBbls)

 

Fixed Price (per Bbl)

January 2018 - December 2018

 

43,070

 

$

56.00

January 2019 - December 2019

 

43,070

 

$

53.07

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Notional

​

Weighted Average

​

Range (per Bbl)

​

​

Volumes (Bbl)

​

Fixed Price (per Bbl)

​

Low

​

High

January 2023 - December 2023

​

303,411

​

$

59.35

​

$

53.38

​

$

63.00

January 2024 - December 2024

​

228,044

​

$

74.44

​

$

69.30

​

$

82.40

Natural Gas Price Swaps

 

 

 

 

 

 

 

 

Notional

 

Weighted Average

 

 

Volumes (MMBtu)

 

Fixed Price (per MMBtu)

January 2018 - December 2018

 

352,590

 

$

2.71

January 2019 - December 2019

 

352,590

 

$

2.76

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Notional

​

Weighted Average

​

Range (per MMBtu)

​

​

Volumes (MMBtu)

​

Fixed Price (per MMBtu)

​

Low

​

High

January 2023 - December 2023

​

4,245,899

​

$

2.90

​

$

2.52

​

$

3.28

January 2024 - December 2024

​

3,229,292

​

$

4.34

​

$

4.15

​

$

4.48

​

​

NOTE 5—FAIR VALUE MEASUREMENTS

FairThe Partnership measures and reports certain assets and liabilities on a fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fairbasis and has classified and disclosed its fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based onusing the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input 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, 2022 and 2021 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 as follows:not discussed below.

·

●

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

·

●

Level 2—quoted marketQuoted prices for similar assets or liabilities in active markets; quoted prices for identicalnon-active markets, or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally fromeither directly or corroborated by observable market data by correlation or other means.

·

Level 3—unobservable inputsindirectly, 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).

F-14

TableAssets and liabilities that are measured at fair value are classified based on the lowest level of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2022 and 2021.

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. Both the Partnership’s commodity derivative instruments and interest rate swap 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.

F-20

Table of Contents

The Predecessor’s ARO is classified within Level 3 asfollowing tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value is estimated using discounted cash flow projections using numerous estimates, assumptionshierarchy:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Fair Value Measurements Using

​

​

​

​

​

​

​

​

Level 1

​

Level 2

​

Level 3

​

Effect of
Counterparty Netting

​

Total

December 31, 2022

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Assets

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Commodity derivative contracts

​

$

—

​

$

754,786

​

$

—

​

$

—

​

$

754,786

Investments held in trust

​

$

240,621,146

​

$

—

​

$

—

​

$

—

​

$

240,621,146

Liabilities

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Commodity derivative contracts

​

$

—

​

$

(13,078,862)

​

$

—

​

$

—

​

$

(13,078,862)

December 31, 2021

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Assets

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Interest rate swap contracts

​

$

—

​

$

1,756,808

​

$

—

​

$

—

​

$

1,756,808

Liabilities

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Commodity derivative contracts

​

$

—

​

$

(28,381,454)

​

$

—

​

$

—

​

$

(28,381,454)

​

​

NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and judgments regarding suchnatural gas properties consist of the following:

​

​

​

​

​

​

​

​

​

    

December 31, 

​

December 31, 

​

​

2022

​

2021

Oil and natural gas properties

​

​

​

​

​

​

Proved properties

​

$

1,258,290,375

​

$

1,051,111,311

Unevaluated properties

​

​

207,695,343

​

​

153,284,173

Less: accumulated depreciation, depletion and impairment

​

​

(712,716,951)

​

​

(663,603,142)

Total oil and natural gas properties

​

$

753,268,767

​

$

540,792,342

​

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 reserves is able to be made. During any period in which these factors indicate an impairment, all or a legal obligationportion 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.

After evaluating certain external factors in the first quarter of 2020, including a significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks, in each case related to reduced demand for an ARO,oil and natural gas as a result of COVID-19, the announcement of price reductions and production increases in March 2020 by members of OPEC and other foreign, oil-exporting countries, and other supply factors, the Partnership determined in 2020 that significant drilling uncertainty existed regarding its proved undeveloped (“PUD”) reserves that were included in its total estimated amountsproved reserves as of December 31, 2019, as well as its unevaluated oil and natural gas properties. Specifically, with respect to the Partnership’s PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), the Partnership determined that it did not have reasonable certainty as to the timing of settlements, the credit-adjusted risk-free rate to be useddevelopment of the PUD reserves and, inflation rates. See Note 10therefore, recorded an impairment on such properties in the first quarter of 2020. The Partnership did not book PUD reserves in its total estimated proved reserves as of December 31, 2022, 2021 or 2020.

The Partnership did not record an impairment on its oil and natural gas properties for the summary of changesyears ended December 31, 2022 and 2021 due to the increase in the fairtwelve-month average oil and gas index prices, calculated as the unweighted average for first-day-of-the-month price for each month. As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $251.6 million during the year ended December 31, 2020, including

F-21

Table of Contents

the $48.6 million in unevaluated properties transferred to the full cost pool. The impairment can primarily be attributed to the decline in the 12-month average price of oil and natural gas during the year ended December 31, 2020.

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, 2022 is 6.37 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the Predecessor’s AROremaining 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 Predecessor 2017 Period.operating lease was 6.75% for the year ended December 31, 2022.

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 for the years ended December 31, 2022, 2021 and 2020. The total operating lease expense recorded for the years ended December 31, 2022, 2021 and 2020 was $0.5 million, $0.4 million and $0.5 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, 2022 are as follows:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

​

2023

​

2024

​

2025

​

2026

​

2027

​

Thereafter

Operating leases

​

$

3,200,460

​

$

487,787

​

$

488,725

​

$

497,033

​

$

507,648

​

$

511,917

​

$

707,350

Less: Imputed Interest

​

 

(639,147)

​

 

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

​

$

2,561,313

​

 

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

NOTE 6—8—LONG-TERM DEBT

In connection with its IPO,On December 15, 2022, the Partnership entered into a $50.0 millionAmendment No. 4 (the “Fourth Credit Agreement Amendment”) to the Partnership’s existing Credit Agreement, dated as of January 11, 2017 (as amended by that certain Amendment No. 1 to Credit Agreement, dated as of July 12, 2018, and that certain Amendment No. 2 to Credit Agreement, dated as of December 8, 2020, and that certain Amendment No. 3 to Credit Agreement, dated as of June 7, 2022, and as otherwise amended or modified prior to such date, the “Credit Agreement” and the Credit Agreement, as amended by the Fourth Credit Agreement Amendment, the “Amended Credit Agreement”), with certain subsidiaries of the Partnership, as guarantors, the lenders party thereto and Citibank as administrative agent.

The Fourth Credit Agreement Amendment amended the Credit Agreement to, among other things, (i) increase the aggregate elected commitments under the Amended Credit Agreement’s senior secured revolving credit facility that is secured by substantially all of its assets(the “Credit Facility”) and (ii) the assets of its wholly owned subsidiaries. Availabilityborrowing base under the secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base.Credit Facility, in each case, from $300.0 million to $350.0 million. The borrowing base will be re-determinedredetermined semi-annually on Februaryor about May 1 and AugustNovember 1 of each year, beginning May 1, 2023, based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of itsthe Partnership’s wholly owned subsidiaries. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility

F-22

Table of $50.0 million. The secured revolving credit facility permits aggregate commitments to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The secured revolving credit facility matures on February 8, 2022.Contents

The secured revolving credit facilityAmended Credit Agreement contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’sour ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units and OpCo common units, 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. The secured revolving credit facilityAmended Credit Agreement also contains covenants requiring the Partnershipus to maintain the following financial ratios or to reduce the Partnership’sour indebtedness if the Partnership iswe 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 4.03.5 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facilityAmended Credit Agreement also contains customary events of default, including non‑payment,non-payment, breach of covenants, materially incorrect representations, cross‑cross default, bankruptcy and change of control.

During the year ended December 31, 2022, the Partnership borrowed an additional $199.2 million under the secured revolving credit facility and repaid approximately $183.3 million of the outstanding borrowings. As of December 31, 2017,2022, the Partnership’s outstanding balance was $30.8$233.0 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2017.2022.

During the period from February 8, 2017 toAs of December 31, 2017,2022, borrowings under the secured revolving credit facility bore interest at LIBORSOFR plus a margin of 2.25% and Prime Rate3.50% or the ABR (as defined in the secured revolving credit facility)Amended Credit Agreement) plus a margin of 1.25%2.50%. For the period from February 8, 2017 toyear ended December 31, 2017,2022, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.94%5.28%.

The 1-week and 2-month U.S. dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K. Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S. dollar settings after September 30, 2023. In response, our secured revolving credit facility has transitioned to the use of the SOFR published by the Federal Reserve Bank of New York in replacement of LIBOR.

NOTE 9—PREFERRED UNITS

In July 2018, the Partnership completed the private placement of 110,000 Series A preferred units (the “Series A preferred units”) to certain affiliates of Apollo Capital Management, L.P. for $1,000 per Series A preferred unit, resulting in gross proceeds to the Partnership of $110.0 million.

On January 31, 2014,February 12, 2020, the Predecessor entered into a credit agreement with Frost Bank for up to a $50.0 million revolving credit facility. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base onPartnership completed the Predecessor’s credit facility was $20.0 million with interest payable monthly on Alternate Base Rate loans or at the endredemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than 50% of the carrying value of the Series A preferred units as of the redemption date and 50% of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $5.7 million was recognized in unitholders’ equity and non-controlling interest period on any Eurodollar loans,during the year ended December 31, 2020.

On July 7, 2021, the Partnership completed the redemption of 30,000 Series A preferred units, representing 55% of the then-outstanding Series A preferred units, with all principal25,000 Series A preferred units still outstanding. The Series A preferred units were redeemed at a price of $1,202.51 per Series A preferred unit for an aggregate redemption price of $36.1 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and unpaidthe redeemed portion of the original intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.8 million was recognized in unitholders’ equity and non-controlling interest dueduring the year ended December 31, 2021.

On December 7, 2021, the Partnership completed the redemption of the remaining 25,000 Series A preferred units. The Series A preferred units were redeemed at maturity on January 15, 2018. a price of $1,240.25 per Series A preferred unit for an aggregate redemption price of $31.0 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date and the remaining intrinsic value of the beneficial conversion feature, a deemed dividend distribution of $3.6 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2021.

F-23

Table of Contents

As of December 31, 2016, the Predecessor had outstanding advances on long-term debt totaling $10.6 million. On February 8, 2017, the Predecessor repaid the entire outstanding principal2022 and interest balance on the credit facility with cash proceeds from the sale of the Predecessor’s mineral and royalty interests to the Partnership.2021, no Series A preferred units remain outstanding.

F-15

Table of Contents​

KIMBELL ROYALTY PARTNERS, LP​

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 7—COMMON UNITS

On February 8, 2017, theThe Partnership completed its IPO of 5,750,000 commonhas issued units representing limited partner interests, which includedinterests. As of December 31, 2022, the Partnership had a total of 64,231,833 common units issued and outstanding and 15,484,400 Class B units outstanding.

In January 2020, the Partnership completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). The Partnership used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under the Partnership’s secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units issued pursuant to the exercise of the underwriters’ option to purchase additional common units. The mineral and royalty interests making upPartnership did not receive any proceeds from the initial assets were contributed tosale of the common units by the selling unitholders.

In November 2021, the Partnership bycompleted 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 Contributing Parties atnet proceeds from the time2021 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $56.0 million of the IPO. On May 12, 2017,outstanding borrowings under the Partnership’s secured revolving credit facility.

In November 2022, the Partnership issued 163,324 restrictedcompleted an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 2022 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $116.0 million of the outstanding borrowings under the LTIP.Partnership’s secured revolving credit facility.

On May 2,The following table summarizes the changes in the number of the Partnership’s common units:

​

​

​

​

​

​

Common Units

Balance at December 31, 2021

​

47,162,773

Conversion of Class B units

​

9,400,000

Common units issued for equity offering

​

6,900,000

Common units issued under the A&R LTIP (1)

​

963,835

Restricted units repurchased for tax withholding

​

(193,604)

Forfeiture of restricted units

​

(1,171)

Balance at December 31, 2022

​

64,231,833

(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 24, 2022.

The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. periods presented:

​

​

​

​

​

​

​

​

​

​

​

​

​

Amount per

​

Date

​

Unitholder

​

Payment

​

​

Common Unit

​

Declared

​

Record Date

​

Date

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

​

​

​

​

​

​

​

​

​

​

Q1 2020

​

$

0.17

​

April 24, 2020

​

May 4, 2020

​

May 11, 2020

Q2 2020

​

$

0.13

​

July 24, 2020

​

August 3, 2020

​

August 10, 2020

Q3 2020

​

$

0.19

​

October 23, 2020

​

November 2, 2020

​

November 9, 2020

Q4 2020

​

$

0.19

​

January 22, 2021

​

February 1, 2021

​

February 8, 2021

​

F-24

Table of Contents

The distribution was paid on May 15, 2017 to unitholders of record as offollowing table summarizes the close of business on May 8, 2017. The amount ofchanges in the first quarter 2017 distribution was adjusted for the period from the date of the closingnumber of the Partnership’s IPO through March 31, 2017.Class B units:

On July 28, 2017,​

​

​

​

​

​

Class B Units

Balance at December 31, 2021

​

17,611,579

Conversion of Class B units

​

(9,400,000)

Class B units issued for acquisition

​

7,272,821

Balance at December 31, 2022

​

15,484,400

​

For each Class B unit issued, five cents has been paid to the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution was paid on August 14, 2017 to unitholders of recordPartnership as additional consideration (the “Class B Contribution”). Holders of the close of businessClass B units are entitled to receive cash distributions equal to 2.0% per quarter on August 7, 2017.

On August 9, 2017,their respective Class B Contribution prior to distributions on the Board of Directors, upon the advicecommon units and recommendationOpCo common units. Holders of the Conflicts and Compensation CommitteeClass B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the Board of Directors, approved the grant of (i) common units inand 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 amount equal to $30,000 each to certain non-employee directorsnumber of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017.

On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution was paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017.

As of December 31, 2017, 16,509,799 common units of the Partnership were outstanding.Partnership.

During the year ended December 31, 2015, the Predecessor made distributions to members totaling $3.2 million. The Predecessor made no distributions during the year ended December 31, 2016.

NOTE 8—11—EARNINGS (LOSS) PER COMMON UNIT

Basic earnings (loss) per common unit (“EPU”) is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested commonrestricted units granted under the Partnership’s A&R LTIP (as defined in Note 12) for its employees, directors and consultants and unvested optionspotential conversion of Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding 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 Predecessor’s long-term incentive plan as described in Note 9—Unit-Based Compensation. ForPartnership’s LTIP. The Partnership does not use the Predecessor 2017 periodtwo-class method because the Class B units and the years ended December 31, 2016 and 2015, the effect of the 110,000 options issuedunvested restricted units granted under the Predecessor’s long-term incentive plan were anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statements of operations for those periods.

Partnership’s A&R LTIP are nonparticipating securities.

F-16F-25

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

    

2016

 

2015

Net income (loss)

 

$

1,715,740

 

 

$

(496,856)

 

$

(6,212,619)

 

$

(31,313,926)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.11

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

Diluted

 

$

0.10

 

 

$

(0.82)

 

$

(10.28)

 

$

(51.83)

Weighted average number of common units outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

16,336,871

 

 

 

604,137

 

 

604,137

 

 

604,137

Diluted

 

 

16,455,602

 

 

 

604,137

 

 

604,137

 

 

604,137

common unit:

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Net income (loss) attributable to common units of Kimbell Royalty Partners, LP

​

$

111,929,491

​

$

22,615,021

​

$

(167,350,893)

Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

​

​

(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

​

​

94,516,759

​

​

22,615,021

​

​

(167,350,893)

Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests in OpCo

​

​

18,864,795

​

​

8,496,104

​

​

—

Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation

​

​

113,381,554

​

​

31,111,125

​

​

​

​

​

​

​

​

​

​

​

​

​

Weighted average number of common units outstanding:

​

​

​

​

​

​

​

​

​

Basic

​

​

54,112,595

​

​

40,400,907

​

​

34,530,398

Effect of dilutive securities:

​

​

​

​

​

​

​

​

​

Class B units

​

​

10,819,266

​

​

18,839,607

​

​

—

Restricted units

​

​

905,156

​

​

1,717,310

​

​

—

Diluted

​

​

65,837,017

​

​

60,957,824

​

​

34,530,398

​

​

​

​

​

​

​

​

​

​

Net income per unit attributable to common units of Kimbell Royalty Partners, LP

​

​

​

​

​

​

​

​

​

Basic

​

$

1.75

​

$

0.56

​

$

(4.85)

Diluted

​

$

1.72

​

$

0.51

​

$

(4.85)

NOTE 9—UNIT-BASED COMPENSATION​

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. The calculation of diluted net loss per share for the year ended December 31, 2020 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and 1,276,546 units of unvested restricted units because their inclusion in the calculation would be anti-dilutive.

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 of up to 2,041,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under ourthe Partnership’s A&R LTIP generally vest in one-thirdone-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 will be accrued for services provided duringis treated in the intervening periods betweensame manner as that of the grantemployees and vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs.directors.

F-26

Table of Contents

Distributions related to the restricted units are paid concurrently with ourthe Partnership’s distributions for common units. The fair value of ourthe Partnership’s restricted units issued under ourthe A&R LTIP to ourthe Partnership’s employees, directors and directorsconsultants is determined by utilizing the market value of ourthe Partnership’s common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested commonrestricted units.

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

Weighted

    

Weighted

    

Weighted

 

 

 

 

Average

 

Average

 

Average

 

 

 

 

Grant-Date

 

Market-Date

 

Remaining

 

 

 

 

Fair Value

 

Fair Value

 

Contractual

 

 

Units

 

per Unit

 

per Unit

 

Term

Unvested at February 8, 2017

 

—

 

$

—

 

$

—

 

—

Granted - service condition employees

 

143,318

 

 

18.655

 

 

—

 

—

Granted - service condition consultants

 

24,253

 

 

—

 

 

16.250

 

—

Granted - non-employee directors

 

9,520

 

 

 

 

 

16.250

 

 

Vested

 

(9,520)

 

 

—

 

 

—

 

—

Forfeited

 

—

 

 

—

 

 

—

 

—

Exercised

 

—

 

 

—

 

 

—

 

—

Unvested at December 31, 2017

 

167,571

 

$

18.655

 

$

16.250

 

1.364 years

​

​

​

​

​

​

​

​

​

​

​

​

​

Weighted

    

Weighted

​

​

​

​

Average

​

Average

​

​

​

​

Grant-Date

​

Remaining

​

​

​

​

Fair Value

​

Contractual

​

​

Units

​

per Unit

​

Term

Unvested at December 31, 2021

​

1,560,899

​

$

11.108

 

1.775 years

Awarded

​

963,835

​

​

15.820

​

—

Vested

​

(626,371)

​

​

10.944

​

—

Forfeited

​

(1,171)

​

​

15.820

​

—

Unvested at December 31, 2022

​

1,897,192

​

$

13.553

 

1.517 years

​

Prior​

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. Texas imposes a franchise tax, commonly referred to as the IPO,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 Predecessor had a long-term incentive plan that providedTexas margin tax statute. The Partnership incurred $2.7 million of income taxes for the issuanceyear ended December 31, 2022 and de minimis amounts of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units.

F-17

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A summary of the Predecessor’s option activity as of February 7, 2017 is as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted

 

 

 

 

Weighted

 

Average

 

 

 

 

Average

 

Remaining

 

 

 

 

Exercise

 

Contractual

 

 

Units

 

Price

 

Term

Outstanding, December 31, 2016

 

110,000

 

$

100

 

8.00 years

Granted

 

—

 

 

—

 

—

Forfeited

 

—

 

 

—

 

—

Exercised

 

—

 

 

—

 

—

Outstanding, February 7, 2017

 

110,000

 

$

100

 

7.92 years

Exercisable, February 7, 2017

 

—

 

$

—

 

—

For the Predecessor 2017 Period andincome taxes during the years ended December 31, 20162021 and 2015, total compensation expense2020.

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

On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) was enacted. The CARES Act is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses that under previous law were only available to be carried forward.

​

The Partnership’s effective income tax rate was 2.05% for awards under the long-term incentive plan was $0.05 million, $0.6 million and $0.6 million respectively,year ended December 31, 2022. The Partnership earned book income for the current year and is included generalrecording a current income tax expense of $2.7 million primarily related to unsheltered taxable income.

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Current

​

​

​

​

​

​

​

​

Federal

​

$

2,412,702

​

$

69,067

​

$

(812,913)

State

​

​

326,000

​

​

5,033

​

​

(72,280)

Total Current

​

​

2,738,702

​

​

74,100

​

​

(885,193)

Deferred

​

​

​

​

​

​

​

​

​

Federal

​

​

—

​

​

—

​

​

—

State

​

​

—

​

​

—

​

​

—

Total Deferred

​

​

—

​

​

—

​

​

—

Provision for (benefit from) income taxes

​

$

2,738,702

​

$

74,100

​

$

(885,193)

​

F-27

Table of Contents

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

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Net income (loss) before taxes

​

$

133,532,988

​

​

$

42,511,974

​

​

$

(256,975,963)

​

Statutory rate

​

​

21

%

​

​

21

%

​

​

21

%

Income tax provision (benefit) computed at statutory rate

​

​

28,041,927

​

​

​

8,927,515

​

​

​

(53,964,952)

​

Reconciling items:

​

​

​

​

​

​

​

​

​

​

​

​

State income taxes

​

​

326,000

​

​

​

5,033

​

​

​

(72,280)

​

Non-controlling interest

​

​

(3,988,366)

​

​

​

(1,788,347)

​

​

​

20,294,890

​

(Income) loss at OpCo

​

​

(24,053,561)

​

​

​

(7,139,168)

​

​

​

33,670,062

​

Change in valuation allowance - federal

​

​

2,202,314

​

​

​

(363,132)

​

​

​

(749,866)

​

Change in valuation allowance - state

​

​

(1,307,605)

​

​

​

(40,626)

​

​

​

168,393

​

Other, net

​

​

1,517,993

​

​

​

472,825

​

​

​

(231,440)

​

Provision for (benefit from) income taxes

​

$

2,738,702

​

​

$

74,100

​

​

$

(885,193)

​

​

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and administrative expenses inliabilities for financial reporting purposes and the consolidated statements of operations. In connection with the transactions that were completed at the closingamounts used for income tax purposes. The components of the Partnership’s IPO,deferred taxes are detailed in the outstanding options table below.

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Deferred tax asset

​

​

​

​

​

​

Outside basis in OpCo

​

$

18,494,572

​

$

6,641,452

​

$

17,624,909

Federal tax loss carryforwards

​

​

2,645,475

​

​

12,296,282

​

​

1,675,957

State tax loss carryforwards

​

​

482,356

​

​

1,789,961

​

​

238,559

Deferred tax asset

​

​

21,622,403

​

​

20,727,695

​

​

19,539,425

Valuation allowance

​

​

(21,622,403)

​

​

(20,727,695)

​

​

(19,539,425)

Net deferred tax asset

​

$

—

​

$

—

​

$

—

Deferred tax liability

​

​

​

​

​

​

​

​

​

Derivative instruments and other

​

​

—

​

​

—

​

​

—

Net deferred tax liability

​

$

—

​

$

—

​

$

—

Reflected in the accompanying balance sheets as:

​

​

​

​

​

​

​

​

​

Net deferred tax asset

​

$

—

​

$

—

​

$

—

Net deferred tax liability

​

$

—

​

$

—

​

$

—

​

The tax years ended December 31, 2019 through 2022 remain open to purchase membership unitsexamination under the Predecessor’s long-term incentive plan expired and were not converted to unitsapplicable statute of limitations in the Partnership.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 $21.6 million on the deferred tax assets.

NOTE 10—ASSET RETIREMENT OBLIGATIONS

Prior to the transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Annual Report,December 31, 2022, the Partnership did has not own recorded a reserve for any working interests and did not have any ARO or any lease operating expenses as a working interest owner.uncertain tax positions.

NOTE 11—14—RELATED PARTY TRANSACTIONS

In connection with the IPO, theThe Partnership entered intocurrently has a management services agreement with Kimbell Operating, which entered intohas separate services agreements with Stewardeach of BJF Royalties, LLC (“StewardBJF Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) 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.

F-28

Table of Contents

Kimbell Operating previously had services agreements with Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”). Effective as of February 18, 2022, Kimbell Operating and each of Nail Bay Royalties and Duncan Management entered into an agreement to terminate the services agreements of such service providers.

During the period from February 8, 2017 toyear ended December 31, 2017,2022, no monthly services fee was paid to BJF Royalties. During the year ended December 31, 2022, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $297,917, $366,667, $110,000, $461,576$120,000, $41,251 and $603,590,$75,090, respectively. Certain consultants who provide services under the above mentioned management services agreements wereare also granted restricted units under the Partnership’s LTIP on May 12, 2017. AsA&R LTIP.

John Wynne, the son of December 31, 2017,Mitch S. Wynne, acts as the Partnership had an outstanding receivable from certain employeesPartnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of $12,550, which is included in accounts receivableapproximately $24,450, $22,160 and other current assets in the accompanying audited consolidated balance sheet. 

During the Predecessor 2017 Period and$20,160 for the years ended December 31, 20162022, 2021 and 2015,2020, respectively, for the Predecessor had certain related party receivablesplacement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $611,204, $555,640 and payables; however, such amounts are de minimis at$440,160 for the years ended December 31, 20162022, 2021 and 2015.

NOTE 12—ADMINISTRATIVE SERVICES2020, respectively.

The Partnership reliesreceived $232,750 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the year ended December 31, 2022.

Special Purpose Acquisition Company

On February 8, 2022, TGR’s initial public offering was completed with 23,000,000 units offered, including 3,000,000 units upon the underwriter’s exercise of its officers, directors, Sponsorsover-allotment option in full, at a price of $10.00 per unit. During the year ended December 31, 2021, the Partnership paid $930,824 in formation and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individualsoffering costs on the Boardbehalf of Directors and their affiliated entities. See Note 11―Related Party Transactions.

F-18

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 13—COMMITMENTS AND CONTINGENCIES

Leases

The Partnership leases certain office space under non-cancelable operating leases that end at various dates through 2022. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expenseTGR. This amount is included in general and administrative expense and was de minimis for all periods presentedother current assets on the consolidated statements of operations.

Future minimum lease commitments under non-cancelable leases are as followsbalance sheets as of December 31, 2017:

 

 

 

 

Years Ending December 31,

    

 

 

2018

 

$

127,506

2019

 

 

130,180

2020

 

 

91,126

2021

 

 

50,784

2022

 

 

29,624

Thereafter

 

 

 -

Total

 

$

429,220

Litigation2021. See Note 3—Acquisitions, Joint Ventures and Special Purpose Acquisition Company for further discussion.

NOTE 15—COMMITMENTS AND CONTINGENCIES

Litigation

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.liquidity as of December 31, 2022.

NOTE 14—16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to December 31, 20172022 in the preparation of its consolidated financial statements.

Distributions

On January 26, 2018,February 23, 2023, the Board of Directors declared a quarterly cash distribution of $0.36$0.48 per common unit and $0.480265 per OpCo common unit for the quarter ended December 31, 2017.2022. The Partnership intends to pay this distribution was paid on February 14, 2018March 16, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on February 7, 2018.March 9, 2023.

As to the Partnership, $0.000265 of the OpCo common unit distribution corresponds to a tax payment made by the Partnership in the fourth quarter of 2022. 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.

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Table of Contents

Executive Bonus and LTIP Issuance

On January 26, 2018, the Board of Directors, upon the advice and recommendation ofFebruary 21, 2023, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of $2.0 million and the grantissuance of a total of 326,654998,162 restricted units to certainits employees directors and consultants under the LTIP.  Such grants were made on January 29, 2018.directors.

NOTE 15—17—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.

F-19

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Capitalized oilOil and natural gas costsNatural Gas Costs

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

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

December 31, 

 

 

December 31, 

 

  

2017

 

 

2016

Oil, natural gas and NGL interests

 

 

 

 

 

 

 

Proved

 

$

297,609,797

 

 

$

70,888,121

Total oil, natural gas and NGL interests

 

 

297,609,797

 

 

 

70,888,121

Accumulated depreciation, depletion, accretion and impairment

 

 

(15,394,238)

 

 

 

(51,948,355)

Net oil, natural gas and NGL interests capitalized

 

$

282,215,559

 

 

$

18,939,766

​

​

​

​

​

​

​

​

​

​

December 31, 

​

December 31, 

​

  

2022

​

2021

Oil, natural gas and NGL interests

​

​

​

​

​

​

Proved properties

​

$

1,258,290,375

​

$

1,051,111,311

Unevaluated properties

​

​

207,695,343

​

​

153,284,173

Total oil, natural gas and NGL interests

​

 

1,465,985,718

​

 

1,204,395,484

Accumulated depreciation, depletion, accretion and impairment

​

 

(712,716,951)

​

 

(663,603,142)

Net oil, natural gas and NGL interests capitalized

​

$

753,268,767

​

$

540,792,342

​

Costs incurredIncurred in oilOil and natural gas activitiesNatural Gas Activities

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

 

2017

 

 

2017

 

2016

 

2015

Acquisition costs

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

$

297,609,797

 

 

$

 —

 

$

 —

 

$

42,000

Total

 

 

297,609,797

 

 

 

 —

 

 

 —

 

 

42,000

Development costs

 

 

  

 

 

 

  

 

 

  

 

 

 

Proved properties

 

 

 —

 

 

 

 —

 

 

78,159

 

 

464,680

Total

 

 

 —

 

 

 

 —

 

 

78,159

 

 

464,680

Total costs incurred on oil, natural gas and NGL activities

 

$

297,609,797

 

 

$

 —

 

$

78,159

 

$

506,680

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Acquisition costs

​

​

​

​

​

​

​

​

​

Proved properties

​

$

56,848,235

​

$

55,300,252

​

$

41,476,734

Unevaluated properties

​

​

204,742,000

​

​

—

​

​

74,263,481

Total

​

 

261,590,235

​

 

55,300,252

​

 

115,740,215

Development costs

​

 

  

​

 

  

​

 

  

Proved properties

​

 

—

​

 

—

​

 

—

Total

​

 

—

​

 

—

​

 

—

Total costs incurred on oil, natural gas and NGL activities

​

$

261,590,235

​

$

55,300,252

​

$

115,740,215

​

Results of Operations from Oil, Natural Gas and Natural Gas LiquidsNGL 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 or Predecessor’sPartnership’s oil, natural gas and NGL operations.

​

​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2022

​

2021

​

2020

Oil, natural gas and NGL revenues

​

$

281,964,126

​

$

175,088,021

​

$

92,586,685

Lease bonus and other income

​

​

3,073,609

​

​

3,319,104

​

​

345,771

Production and ad valorem taxes

​

 

(16,238,814)

​

 

(10,480,481)

​

 

(6,389,231)

Depreciation and depletion expense

​

 

(50,086,414)

​

 

(36,797,881)

​

 

(47,988,796)

Impairment of oil and natural gas properties

​

 

—

​

 

—

​

 

(251,558,557)

Marketing and other deductions

​

 

(13,383,074)

​

 

(12,048,643)

​

 

(9,376,375)

Results of operations from oil, natural gas and NGLs

​

$

205,329,433

​

$

119,080,120

​

$

(222,380,503)

​

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partnership

 

 

Predecessor

 

 

Period from February 8, 2017 to December 31, 

 

 

Period from January 1, 2017 to February 7,

 

Year Ended December 31, 

 

    

2017

 

 

2017

 

2016

 

2015

Oil, natural gas and NGL revenues

 

$

30,665,092

 

 

$

318,310

 

$

3,606,659

 

$

4,684,923

Production and ad valorem taxes

 

 

(2,452,058)

 

 

 

(19,651)

 

 

(280,474)

 

 

(426,885)

Depreciation, depletion and accretion expense

 

 

(15,394,238)

 

 

 

(113,639)

 

 

(1,604,208)

 

 

(4,008,730)

Impairment of oil and natural gas properties

 

 

 -

 

 

 

 -

 

 

(4,992,897)

 

 

(28,673,166)

Marketing and other deductions

 

 

(1,648,895)

 

 

 

(110,534)

 

 

(750,792)

 

 

(747,264)

Results of operations from oil, natural gas and NGLs

 

$

11,169,901

 

 

$

74,486

 

$

(4,021,712)

 

$

(29,171,122)

F-30

Table of Contents

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, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 20172022, 2021 and 2016. The standardized measure presented here excludes income taxes, as the tax basis for the

F-20

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

properties is not applicable on a go-forward basis.2020. 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 Natural Gas LiquidsNGL 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. Proved undevelopedPUD reserves are 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.

A barrel of equivalent (‘‘Boe’’)Boe conversion ratio of six thousand cubic feet per barrel (6mcf/bbl)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 valueprice 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.

F-31

Table of Contents

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, 2020

​

12,318

​

148,742

​

6,455

​

43,563

Revisions of previous estimates (1)

​

18

​

(2,256)

​

(2)

​

(359)

Purchase of minerals in place (2)

​

1,367

​

15,637

​

313

​

4,286

Production

​

(1,409)

​

(17,890)

​

(681)

​

(5,072)

Net proved reserves at December 31, 2020

​

12,294

​

144,233

​

6,085

​

42,418

Revisions of previous estimates (1)

​

251

​

24,079

​

780

​

5,044

Purchase of minerals in place (3)

​

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 (4)

​

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

​

​

​

​

​

​

​

​

​

Net proved developed reserves

​

​

​

​

​

​

​

​

December 31, 2020

​

12,294

​

144,233

​

6,085

​

42,418

December 31, 2021

​

12,511

​

157,764

​

6,669

​

45,474

December 31, 2022

​

12,355

​

160,298

​

7,388

​

46,459

​

​

​

​

​

​

​

​

​

 

 

 

 

 

 

 

 

 

 

 

Crude Oil and

 

 

 

Natural Gas

 

 

 

 

Condensate

 

Natural Gas

 

Liquids

 

Total

 

    

(MBbls)

    

(MMcf)

    

(MBbls)

    

(MBOE)

Net proved reserves at January 1, 2016

 

6,827

 

51,734

 

1,647

 

17,096

Revisions of previous estimates (1)

 

131

 

(852)

 

335

 

324

Purchase of minerals in place (2)

 

45

 

90

 

 9

 

69

Extensions, discoveries and other additions (3)

 

637

 

2,851

 

115

 

1,227

Production

 

(430)

 

(3,433)

 

(124)

 

(1,126)

Net proved reserves at December 31, 2016

 

7,210

 

50,390

 

1,982

 

17,590

Revisions of previous estimates (1)

 

(193)

 

(1,535)

 

666

 

217

Purchase of minerals in place (4)

 

362

 

16,312

 

274

 

3,355

Extensions, discoveries and other additions (5)

 

505

 

2,261

 

91

 

973

Production

 

(421)

 

(3,512)

 

(175)

 

(1,181)

Net proved reserves at December 31, 2017

 

7,463

 

63,916

 

2,838

 

20,954

 

 

 

 

 

 

 

 

 

Net Proved Developed Reserves

 

 

 

 

 

 

 

 

December 31, 2016

 

4,879

 

35,172

 

1,416

 

12,157

December 31, 2017

 

5,284

 

47,501

 

2,202

 

15,403

 

 

 

 

 

 

 

 

 

Net Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

December 31, 2016

 

2,331

 

15,218

 

566

 

5,433

December 31, 2017

 

2,179

 

16,415

 

636

 

5,551

(1)

(1)

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

(2)

(2)

Includes the acquisition of three contiguous Eagle Ford drilling units in Karnes County, Texas.

(3)

Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin.

(4)

Includes the acquisition of $29.3 million of mineral and royalty interests the largestfor a total of which being a package$41.5 million. The acquisition consists of mineral and royalty interests primarily in the AnadarkoDelaware Basin, DJ Basin, Haynesville, STACK and also includes additionalEagle Ford.

(3)Includes the acquisition of mineral and royalty interests for a total of $55.3 million, primarily consisting of mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas,the Permian Basin, Mid-Continent, Haynesville and Kansas.

other leading U.S. basins.

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Table of Contents

KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(4)

(5)

Includes discoveriesthe acquisition of mineral and additionsroyalty interests for a total of $56.8 million, primarily related to active drilling on our acreage primarilyconsisting of mineral and royalty interests in the Permian Basin, Eagle Ford Shale.

Basin.

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 natural gas liquidsNGL reserves of the properties is as follows (in thousands):

 

 

 

 

 

 

Year Ended December 31,

    

2017

 

2016

​

​

​

​

​

​

​

​

​

​

Year Ended December 31,

​

    

2022

​

2021

​

2020

Future cash inflows

 

$

562,967

 

$

414,004

​

$

2,253,273

​

$

1,335,917

​

$

705,356

Future production costs

 

 

(45,652)

 

(32,034)

​

​

(161,676)

​

(100,947)

​

(55,897)

Future state margin taxes

 

 

(2,790)

 

 

(2,051)

​

​

(76,322)

​

(42,965)

​

(22,688)

Future income tax expense

​

​

—

​

​

—

​

​

—

Future net cash flows

 

 

514,525

 

379,919

​

​

2,015,275

​

1,192,005

​

626,771

Less 10% annual discount to reflect timing of cash flows

 

 

(298,973)

 

 

(220,643)

​

​

(1,110,980)

​

​

(665,390)

​

​

(341,775)

Standard measure of discounted future net cash flows

 

$

215,552

 

$

159,276

​

$

904,295

​

$

526,615

​

$

284,996

​

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 2017

F-32

Table of Contents

2022, 2021 and 20162020 were $51.34$93.67, $66.56 and $42.75$39.57 per barrel for crude oil and $2.98$6.36, $3.60 and $2.49$1.99 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 developing and 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. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the properties is not applicable on a go-forward basis. 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,

 

2017

 

2016

​

​

​

​

​

​

​

​

​

Year Ended December 31,

​

​

2022

​

2021

​

2020

Standardized measure - beginning of year

 

$

159,275

 

$

180,083

​

$

526,615

​

$

284,996

​

$

399,971

Sales, net of production costs

 

(29,288)

 

(24,280)

​

(252,597)

​

(152,751)

​

(76,821)

Net changes of prices and production costs related to future production

 

21,946

 

(23,321)

​

365,427

​

225,868

​

(127,838)

Extensions, discoveries and improved recovery, net of future production costs

 

10,064

 

11,253

Revisions of previous quantity estimates, net of related costs

 

2,248

 

2,974

​

71,776

​

60,517

​

(2,501)

Net changes in state margin taxes

 

301

 

(112)

​

(15,266)

​

(8,665)

​

4,314

Net changes in income taxes

​

—

​

—

​

13,480

Accretion of discount

 

15,928

 

18,008

​

44,280

​

25,743

​

38,927

Purchases of reserves in place

 

23,309

 

1,097

​

77,719

​

40,545

​

46,007

Timing differences and other

 

 

11,769

 

 

(6,426)

​

​

86,341

​

​

50,362

​

​

(10,543)

Standardized measure - end of year

 

$

215,552

 

$

159,276

​

$

904,295

​

$

526,615

​

$

284,996

​

​

F-22F-33

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Predecessor

 

Partnership

 

  

First Quarter

    

First Quarter

    

Second Quarter

    

Third Quarter

    

Fourth Quarter

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue

 

$

318,310

 

$

4,553,344

 

$

7,751,998

 

$

8,351,399

 

$

10,008,351

Net (loss) income

 

$

(496,856)

 

$

283,218

 

$

251,651

 

$

119,029

 

$

1,061,842

Net income attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.82)

 

$

0.02

 

$

0.02

 

$

0.01

 

$

0.06

Diluted

 

$

(0.82)

 

$

0.02

 

$

0.02

 

$

0.01

 

$

0.06

Cash distributions declared and paid

 

$

*

 

$

0.23

 

$

0.30

 

$

0.31

 

$

0.36

Total assets

 

$

*

 

$

279,419,440

 

$

289,918,996

 

$

290,406,599

 

$

295,291,004

Long-term debt

 

$

*

 

$

3,877,500

 

$

18,265,090

 

$

22,214,090

 

$

30,843,593

Partners' capital

 

$

*

 

$

273,657,870

 

$

270,288,690

 

$

265,893,106

 

$

262,065,434

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Predecessor

 

 

 

 

 

First Quarter

    

Second Quarter

    

Third Quarter

    

Fourth Quarter

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue

 

 

 

 

$

755,653

 

$

847,740

 

$

969,084

 

$

1,034,182

Net loss

 

 

 

 

$

(4,049,563)

 

$

(1,199,285)

 

$

(769,166)

 

$

(194,605)

Net loss attributable to common units

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

$

(6.70)

 

$

(1.99)

 

$

(1.27)

 

$

(0.32)

Diluted

 

 

 

 

$

(6.70)

 

$

(1.99)

 

$

(1.27)

 

$

(0.32)

Cash distributions declared and paid

 

 

 

 

$

*

 

$

*

 

$

*

 

$

*

Total assets

 

 

 

 

$

22,387,175

 

$

21,404,751

 

$

20,784,733

 

$

20,538,731

Long-term debt

 

 

 

 

$

11,298,860

 

$

11,198,860

 

$

10,898,860

 

$

10,598,860

Predecessor members' equity

 

 

 

 

$

10,341,124

 

$

9,293,104

 

$

8,675,203

 

$

8,631,862

* Information is not applicable for the periods prior to the initial public offering.

F-23