Kimbell Royalty Partners 10K/A 2023 Annual report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment Number 1)


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

For the fiscal year ended: December 31, 2023

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

For the transition period from to

Commission file number: 001-38005

Kimbell Royalty Partners, LP

(Exact name of registrant as specified in its charter)


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

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945-9700

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of June 30, 2023, was $898.8 million, based on the closing price of such common units of $14.71 as reported on the New York Stock Exchange on June 30, 2023. As of February 16, 2024, the registrant had outstanding 73,851,458 common units representing limited partner interests and 20,847,295 Class B units representing limited partner units.

Documents Incorporated by Reference: None

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Explanatory Note

Kimbell Royalty Partners, LP (“our Partnership,” “we,” “our,” “us” or like terms) is filing this Amendment No. 1 on Form 10-K/A (this “Amendment”) to our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, which was filed on February 21, 2024 (the “Original Form 10-K”) to make certain changes described below.

Background

We are organized in a structure that is commonly referred to as an “Up-C” structure. Our direct subsidiary, Kimbell Royalty Operating, LLC (“OpCo”), is owned partially by us and partially by other investors. The other investors of OpCo are permitted to exchange their interest in OpCo, together with a Class B unit of the Partnership, into an equal number of our common units. The ownership interest by such other investors in OpCo is shown as a non-controlling interest in our consolidated financial statements.

In connection with the preparation of our unaudited interim consolidated financial statements for the three and nine months ended September 30, 2024, we identified an error in the application of accounting guidance related to the changes in ownership of OpCo. We previously accounted for the changes in ownership of OpCo by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should be accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted should be recognized in equity attributable to the parent.

We evaluated the error and determined that they did not result in a material misstatement of our previously issued consolidated financial statements. In making this determination, we noted that the error (i) only resulted in a reclass of amounts between components within unitholders’ equity (specifically, from Common Units to Non-Controlling Interest in OpCo) and (ii) did not have any impact on the total unitholders’ equity amount in our consolidated balance sheets, the total amount in our consolidated statement of changes in unitholders’ equity or any other portion of our financial statements. Moreover, the error had no impact on items in our consolidated statement of operations or statement of cash flows, including any information related to revenues, net income, net income attributable to common units, earnings per unit and other items. The error similarly did not have an impact on any of our key performance indicators and non-GAAP metrics, included Adjusted EBITDA and cash available for distribution, nor did it have any impact on compliance with our material financial covenants under debt instruments or other contractual arrangements.

However, in connection with the period-end close process, we identified a material weakness in our internal control over financial reporting and have concluded this material weakness was present as of December 31, 2023.

Description of Amendment

This Amendment amends the following items in our Original Form 10-K:

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Cautionary Statement Regarding Forward-Looking Statements: We are providing certain updates to the forward-looking statements section of our Original Form 10-K.

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Part II. Item 8. Financial Statements and Supplementary Data: We are updating the unitholders’ equity portion of our consolidated balance sheet, as well as our consolidated statements of changes in unitholders’ equity, to correct the error discussed above. In addition, we have added Note 18 (Correction of Immaterial Errors) to discuss the error. Our consolidated financial statements are included in this Amendment beginning on page F-1.

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Part II. Item 9A. Controls and Procedures: We are amending this item to disclose the material weakness that was identified as a result of the error discussed above, and to revise our assessment of the effectiveness of our internal control over financial reporting and our disclosure controls and procedures to indicate that they were not effective as of December 31, 2023 because of the material weakness. We are also including a revised audit report of Grant Thornton LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2023.

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Part IV. Item 15. Exhibits, Financial Statement Schedules: We are amending this item to include a new consent of Grant Thornton LLP and, as required by Rule 12b-15 under the Securities Act of 1934, as amended, to provide new currently dated certifications by our Chief Executive Officer and Chief Financial Officer pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. The new consent is attached to this Amendment as Exhibit 23.1 and the new certifications are attached to this Amendment as Exhibits 31.1, 31.2, 32.1 and 32.2. We are also including new inline XBRL tagging.

The only changes to the Original Form 10-K are those related to the matters described above. Except as described above, this Amendment does not amend, update or change any other item or disclosure in the Original Form 10-K and does not purport to reflect any information or event subsequent to the filing thereof. As such, this Amendment speaks only as of the date the Original Form 10-K was filed, and we have not undertaken to amend, update or change any information contained in the Original Form 10-K to give effect to any subsequent event, other than as expressly indicated in this Amendment. Accordingly, this Amendment should be read in conjunction with the Original Form 10-K and any subsequent filing with the SEC.

F-ii

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Kimbell Royalty Partners, LP

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PART II
Item 8. Financial Statements and Supplementary Data	6
Item 9A. Controls and Procedures	6

PART IV
Item 15. Exhibits, Financial Statement Schedules	11
Signatures	15

F-iii

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Cautionary Statement Regarding Forward-Looking Statements

Certain statements and information in this Amendment and the Original Form 10-K may constitute forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Amendment and the Original Form 10-K. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

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our ability to replace our reserves;

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

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our ability to execute our business strategies;

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

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the level of production on our properties;

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

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

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

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

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

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

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impacts of impairment expense on our financial statements;

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

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

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

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

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

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the availability of transportation facilities;

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

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

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

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our ability to remediate any material weakness in, or otherwise maintain effective internal controls over financial reporting and disclosure controls and procedures; and

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certain factors discussed elsewhere in this Amendment and in the Original Form 10-K, including but not limited to the items discussed in “Risk Factors” in Item 1A of Part I of the Original Form 10-K and that are otherwise described or updated from time to time in our other filings with the Securities and Exchange Commission (the “SEC”).

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

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Part II

Item 8. Financial Statements and Supplementary Data

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

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Based upon that evaluation, at the time that the Original Form 10-K was filed on February 21, 2024, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023.

Subsequent to this evaluation, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of December 31, 2023 due to the material weakness in our internal control over financial reporting described below.

Despite the material weakness described below, our General Partner’s principal executive officer and principal financial officer concluded that the consolidated financial statements included in this Amendment fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control Over Financial Reporting

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

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

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

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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

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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

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

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

As of December 31, 2023, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework (2013). Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. At the time that the Original Form 10-K was filed on February 21, 2024, management, including our General Partner’s principal executive officer and principal financial officer, concluded our internal control over financial reporting was effective as of December 31, 2023. In the third quarter of the fiscal year ending December 31, 2024, management identified a material weakness in its internal control over financial reporting (described below) that was determined to have existed as of December 31, 2023. As a result, management including our General Partner’s principal executive officer and principal financial officer, concluded our internal control over financial reporting was ineffective as of December 31, 2023.

In connection with the preparation of the Partnership’s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2024, the Partnership identified an error in its application of accounting guidance related to the changes in ownership of OpCo, which is a consolidated, less than wholly owned subsidiary. The Partnership previously accounted for the changes in ownership of OpCo by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should be accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted should be recognized in equity attributable to the parent. The Partnership evaluated the error and determined that the related impact was not material to its financial statements for any prior annual or interim period. However, we identified a material weakness in our control environment because of this error.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Partnership’s annual or interim financial statements will not be prevented or detected on a timely basis.

We failed to maintain an effective control environment because we lacked sufficient oversight of the application of accounting guidance related to the changes in ownership of OpCo. While this material weakness did not result in a material misstatement of our previously filed financial statements, there is a reasonable possibility that this control deficiency could have resulted in a material misstatement in our annual or interim consolidated financial statements that would not be detected. Accordingly, we have determined that this control deficiency constitutes a material weakness.

See the Report of Independent Registered Public Accounting Firm on our internal control over financial reporting in this Item 9, which is incorporated herein by reference.

Status of Remediation Efforts

Management is in the process of remediating the internal control weakness related to our accounting for changes in ownership of OpCo. Management has corrected the error and will implement a new control to ensure that changes in ownership of a consolidated subsidiary that is less than wholly owned are accounted for by adjusting the carrying value of non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of

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consideration received or paid and the amount by which the noncontrolling interest is adjusted will be recognized in equity attributable to the parent in accordance with ASC 810-10. While we have already taken steps to implement our remediation plan, the material weakness will not be considered remediated until the enhanced controls operate for a sufficient period of time and management has concluded, through testing, that the related controls are effective. The Partnership will monitor the effectiveness of its remediation plan and refine its remediation plan as appropriate.

Changes in Internal Control over Financial Reporting

As described above, we are taking steps to remediate the material weakness in our internal control over financial reporting. Other than in connection with the remediation process described above, there have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Kimbell Royalty Partners, LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Kimbell Royalty Partners, LP (a Delaware limited partnership) and subsidiaries (collectively, the “Partnership”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, because of the effect of the material weakness described in the following paragraphs on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment.

In our report dated February 21, 2024, we expressed an unqualified opinion that the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria. Management has subsequently identified a design deficiency involving the accounting for changes in ownership of its consolidated, less than wholly-owned subsidiaries. Management lacked sufficient oversight of the application of accounting guidance specific to these equity transactions related to changes in ownership of its consolidated, less than wholly-owned subsidiaries. As a result, management has revised its assessment, as presented in the accompanying Management’s Report on Internal Control Over Financial Reporting, to conclude that the Partnership’s internal control over financial reporting was not effective as of December 31, 2023. Accordingly, our present opinion on the effectiveness of internal control over financial reporting as of December 31, 2023, as expressed herein, is different from that expressed in our previous report.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2023. The material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2023 consolidated financial statements, and this report does not affect our report dated February 21, 2024, except for Note 1 and Note 18, as to which the date is November 8, 2024, which expressed an unqualified opinion on those financial statements.

Basis for opinion

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

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing

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the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

Definition and limitations of internal control over financial reporting

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

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

/s/ GRANT THORNTON LLP

Dallas, Texas

February 21, 2024 (except for the effect of the material weakness described in the third paragraph above, as to which the date is November 8, 2024)

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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-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

EXHIBIT INDEX

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.2	—	Fifth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 13, 2023)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty GP, LLC, dated as of February 8, 2017 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
3.5	—	Third Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
4.1	—	Amended and Restated Registration Rights Agreement, dated as of March 25, 2019, by and among Kimbell Royalty Partners, LP, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Haymaker Minerals & Royalties, LLC, AP KRP Holdings, L.P., ATCF SPV, L.P., Zeus Investments, L.P., Apollo Kings Alley Credit SPV, L.P., Apollo Thunder Partners, L.P., AIE III Investments, L.P., Apollo Union Street SPV, L.P., Apollo Lincoln Private Credit Fund, L.P., Apollo SPN Investments I (Credit), LLC, AA Direct, L.P., PEP I Holdings, LLC, PEP II Holdings, LLC, PEP III Holdings, LLC, Cupola Royalty Direct, LLC, Kimbell Art Foundation and Rivercrest Capital Partners LP (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on March 26, 2019)
4.2	—	Registration Rights Agreement, dated as of December 15, 2022, by and among Kimbell Royalty Partners, LP and Hatch Royalty LLC (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on December 15, 2022)
4.3	—	Registration Rights Agreement, dated as of May 17, 2023, by and among between Kimbell Royalty Partners, LP and MB Minerals, L.P. (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP Current Report on Form 8-K filed on May 18, 2023)
4.4	—	Registration Rights Agreement, dated as of September 13, 2023, by and among Kimbell Royalty Partners, LP and the parties listed on the signature page thereof (incorporated by reference to Exhibit 4.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)

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4.5	—	Description of Common Units Representing Limited Partnership Interests (incorporated by reference to Exhibit 4.5 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
10.1^†	—	Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 18, 2022)
10.2^†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Restricted Unit Agreement (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 11, 2017)
10.3^†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan Director Unit Agreement (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Form 10-Q filed on August 14, 2017)
10.4^†	—	Form of Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 2018 Restricted Unit Agreement (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.5	—	Amended and Restated Credit Agreement, dated as of June 13, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on June 20, 2023)
10.6	—	Amendment No. 1 to Amended and Restated Credit Agreement, dated as of July 24, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on July 28, 2023)
10.7	—	Amendment No. 2 to Amended and Restated Credit Agreement, dated as of December 8, 2023, by and among Kimbell Royalty Partners, LP, each of the guarantors party thereto, the several lenders from time to time parties thereto and Citibank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on December 11, 2023)
10.8^†	—	Management Services Agreement, dated February 8, 2017, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.9^†	—	Amendment No. 1 to Management Services Agreement, dated December 10, 2018, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.10 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)
10.10^†	—	Amendment No. 2 to Management Services Agreement, dated December 16, 2019, by and among Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC, Kimbell Royalty Holdings, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.13 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.11^†	—	Management Services Agreement, dated February 8, 2017, by and between BJF Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.12^†	—	Management Services Agreement, dated February 8, 2017, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.4 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on February 14, 2017)
10.13^†	—	Amendment No. 1 to Management Services Agreement, dated March 7, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.11 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 9, 2018)
10.14^†	—	Amendment No. 2 to Management Services Agreement, dated December 10, 2018, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.17 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on March 12, 2019)

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10.15^†	—	Amendment No. 3 to Management Services Agreement, dated December 16, 2019, by and between K3 Royalties, LLC and Kimbell Operating Company, LLC (incorporated by reference to Exhibit 10.18 to Kimbell Royalty Partners, LP’s Form 10-K filed on February 28, 2020)
10.16	—	Exchange Agreement, dated as of September 23, 2018, by and among Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC, Kimbell Art Foundation, Kimbell Royalty Partners, LP, Kimbell Royalty GP, LLC and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 25, 2018)
10.17	—	Purchase and Sale Agreement, dated as of April 11, 2023, by and among MB Minerals, L.P., Kimbell Royalty Partners, LP and Kimbell Royalty Operating, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on April 12, 2023)
10.18	—	Securities Purchase Agreement, dated as of August 2, 2023, by and between LongPoint Minerals II, LLC and Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)
10.19	—	Preferred Units Purchase Agreement, dated as of August 2, 2023, by and among Kimbell Royalty Partners, LP and the several purchasers party thereto (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on August 2, 2023)
10.20	—	Board Representation and Observation Agreement, dated as of September 13, 2023, by and among Kimbell Royalty Partners, LP, Kimbell GP Holdings, LLC, Apollo Accord+ Aggregator A, L.P., Apollo Accord V Aggregator A, L.P., Apollo Defined Return Aggregator A, L.P., Apollo Calliope Fund, L.P., Apollo Excelsior, L.P., Apollo Credit Strategies Master Fund Ltd., Apollo Atlas Master Fund, LLC, Apollo Union Street SPV, L.P., Host Plus PTY Limited - Accord, Apollo Delphi Fund, L.P., Apollo Royalties Fund I, L.P., AHVF (AIV), L.P., AHVF Intermediate Holdings, L.P., AHVF TE/892/QFPF (AIV), L.P. and ACMP Holdings, LLC (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
10.21	—	Transition Services Agreement, by and between Kimbell Royalty Operating, LLC and FourPoint Energy, LLC (incorporated by reference to Exhibit 10.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on September 13, 2023)
21.1	—	List of Subsidiaries of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 21.1 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024
23.1*	—	Consent of Grant Thornton LLP
23.2	—	Consent of Ryder Scott Company, L.P. (incorporated by reference to Exhibit 23.2 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
23.3	—	Consent of KPMG LLP (incorporated by reference to Exhibit 23.3 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
23.4	—	Report of Independent Registered Public Accounting Firm—KPMG LLP Opinion on the Consolidated Financial Statements on Kimbell Tiger Acquisition Corporation (incorporated by reference to Exhibit 23.4 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18. U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18. U.S.C. Section 1350
97.1	—	Kimbell Royalty Partners, LP Policy for the Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97.1 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
99.1	—	Report of Ryder Scott Company, L.P. as of December 31, 2023 (incorporated by reference to Exhibit 99.1 to Kimbell Royalty Partners, LP’s Annual Report on Form 10-K filed on February 21, 2024)
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

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101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* —Filed herewith.

** —Furnished herewith.

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

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

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SIGNATURES

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


	Kimbell Royalty Partners, LP

	By:	Kimbell Royalty GP, LLC
		its general partner

Date: November 8, 2024	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman

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INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	F-2

Consolidated Balance Sheets at December 31, 2023 and 2022	F-5

Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	F-6

Consolidated Statements of Changes in Unitholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021	F-7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	F-8

Notes to Consolidated Financial Statements	F-10

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Kimbell Royalty Partners, LP

Opinion on the financial statements

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

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 21, 2024, except for the effect of the material weakness described in the third paragraph of that report, as to which the date is November 8, 2024, expressed an adverse opinion thereon.

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

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

Critical audit matters

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

F-2

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

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

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

•

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

•

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

•

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

•

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

•

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

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

As described further in Notes 2 and 6 to the financial statements, the Partnership accounts for its oil and natural gas properties using the full cost method of accounting, which requires management to make estimates of proved reserves to measure depletion expense and to determine if any impairment exists for its proved oil and natural gas properties. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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

F-3

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

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

•

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

•

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

•

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

•

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

•

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

•

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

/s/ GRANT THORNTON LLP

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

Dallas, Texas

February 21, 2024 (except for Note 1 and Note 18, as to which the date is November 8, 2024)

F-4

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS


	December 31,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	30,992,670	$	24,635,718
Oil, natural gas and NGL receivables		59,020,471		46,993,711
Derivative assets		11,427,735		—
Accounts receivable and other current assets		1,699,536		3,562,912
Total current assets		103,140,412		75,192,341
Property and equipment, net		589,895		953,781
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($222,712,844 and $207,695,343 excluded from depletion at December 31, 2023 and 2022, respectively)		2,048,690,088		1,465,985,718
Less: accumulated depreciation, depletion and impairment		(827,033,944)		(712,716,951)
Total oil and natural gas properties, net		1,221,656,144		753,268,767
Right-of-use assets, net		2,189,243		2,525,323
Derivative assets		2,888,051		754,786
Loan origination costs, net		7,325,471		3,004,104
Assets of consolidated variable interest entities:
Cash		—		390,850
Investments held in trust		—		240,621,146
Prepaid expenses		—		35,201
Total assets	$	1,337,789,216	$	1,076,746,299

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	6,594,736	$	1,210,337
Other current liabilities		6,173,314		4,909,510
Derivative liabilities		208,710		12,646,720
Total current liabilities		12,976,760		18,766,567
Operating lease liabilities, excluding current portion		1,887,693		2,236,361
Derivative liabilities		60,094		432,142
Long-term debt		294,200,000		233,015,911
Other liabilities		197,917		322,917
Liabilities of consolidated variable interest entities:
Other current liabilities		—		512,725
Deferred underwriting commissions		—		8,050,000
Total liabilities		309,322,464		263,336,623
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units and zero units issued and outstanding as of December 31, 2023 and 2022, respectively)		314,423,572		—
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		236,900,000
Kimbell Royalty Partners, LP unitholders' equity:
Common units (73,851,458 units and 64,231,833 units issued and outstanding as of December 31, 2023 and 2022, respectively)		555,809,000		463,751,910
Class B units (20,847,295 and 15,484,400 units issued and outstanding as of December 31, 2023 and 2022, respectively)		1,042,365		774,220
Total Kimbell Royalty Partners, LP unitholders' equity		556,851,365		464,526,130
Non-controlling interest in OpCo		157,191,815		111,983,546
Total unitholders' equity		714,043,180		576,509,676
Total liabilities, mezzanine equity and unitholders' equity	$	1,337,789,216	$	1,076,746,299

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

F-5

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS


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

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51
Weighted average number of common units outstanding
Basic		66,595,273		54,112,595		40,400,907
Diluted		93,057,731		65,837,017		60,957,824

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

F-6

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY


									Non-controlling		Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Interest in TGR		Total
Balance at January 1, 2021		38,918,689	$	217,768,360		20,779,781	$	1,038,989	$	116,827,389	$	—	$	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		17,005,271		(3,168,202)		(158,410)		(17,005,271)		—		(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)
Change in ownership of consolidated subsidiaries, net		—		(12,295,407)		—		—		12,295,407		—		—
Net income		—		30,647,893		—		—		11,789,981		—		42,437,874
Balance at December 31, 2021		47,162,773		253,120,002		17,611,579		880,579		94,849,200		—		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		50,598,886		(9,400,000)		(470,000)		(50,598,886)		—		(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)
Change in ownership of consolidated subsidiaries, net		—		49,056,142		—		—		(49,056,142)		—		—
Net income		—		111,971,734		—		—		18,822,552		—		130,794,286
Balance at December 31, 2022		64,231,833		463,751,910		15,484,400		774,220		111,983,546		—		576,509,676
Common units issued for equity offering		8,337,500		110,711,383		—		—		—		—		110,711,383
Units issued for acquisition		557,302		8,654,900		5,369,218		268,461		83,383,956		—		92,307,317
Conversion of Class B units to common units		6,323		47,733		(6,323)		(316)		(47,733)		—		(316)
Restricted units repurchased for tax withholding		(279,662)		(4,851,962)		—		—		—		—		(4,851,962)
Unit-based compensation		998,162		13,111,522		—		—		—		—		13,111,522
Distributions to unitholders		—		(120,372,624)		—		—		(31,551,122)		—		(151,923,746)
Distribution and accretion on Series A preferred units		—		(4,921,063)		—		—		(1,389,152)		—		(6,310,215)
Distribution on Class B units		—		(88,786)		—		—		—		—		(88,786)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		1,192,969		—		—		379,768		—		1,572,737
Change in ownership of consolidated subsidiaries, net		—		23,421,490		—		—		(23,421,490)		—		—
Net income		—		65,151,528		—		—		17,854,042		—		83,005,570
Balance at December 31, 2023		73,851,458	$	555,809,000		20,847,295	$	1,042,365	$	157,191,815	$	—	$	714,043,180

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)


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


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

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

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. The Partnership has elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated natural gas liquids (“NGL”) from the acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest.

Basis of Presentation

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

Correction of Immaterial Errors

Subsequent to the initial issuance of the consolidated financial statements for the year ended December 31, 2023, the Partnership identified an error in its application of accounting guidance related to the changes in ownership of OpCo.

The Partnership previously accounted for the changes in ownership of OpCo (which occurred as a result of unit issuances by OpCo or the exchange by OpCo investors into common units) by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the non-controlling interest is adjusted should be recognized in equity attributable to the parent.

The Partnership has corrected these errors and determined that the related impact was not material to its previously issued financial statements. The Partnership has corrected these errors in the Consolidated Financial Statements for all prior periods presented herein. See Note 18, “Correction of Immaterial Errors”.

Use of Estimates

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

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Segment Reporting

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

Global Conflicts

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

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management Estimates

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

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

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

Cash and Cash Equivalents

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

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

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Oil, Natural Gas and NGL Receivables

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

Derivative Financial Instruments

Commodity Derivatives

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

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statements of operations within gain (loss) on commodity derivative instruments.

Interest Rate Swaps

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

Property and Equipment

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

Loan Origination Costs

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

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

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

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

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

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

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

Other Current Liabilities

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

Earnings Per Unit

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

Income Taxes

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

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

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

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

Concentration of Credit Risk

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

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

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

Non-controlling Interest

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

Revenue from Contracts with Customers

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

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

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


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

Transaction Price Allocated to Remaining Performance Obligations

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

Contract Balances

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

Prior-Period Performance Obligations

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

Fair Value Measurements

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

Consolidation

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

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

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s

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economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

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

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR (as defined in Note 3), a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 3). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities were included in other income (expense)—interest earned on marketable securities in trust account on the accompanying consolidated statements of operations. The estimated fair values of investments held in the trust account were determined using quoted prices in an active market and therefore classified in Level 1 of the fair value hierarchy, as described in Note 5— Fair Value Measurements.

Redeemable Non-Controlling Interest

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

Recently Issued Accounting Pronouncements

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

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

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

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

Acquisitions

2023 Activity

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

On May 17, 2023, the Partnership completed the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”). The aggregate consideration for the MB Minerals Acquisition consisted of (i) approximately $48.8 million in cash and (ii) the issuance of (a) 5,369,218 OpCo Common Units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and (b) 557,302 common units. The Partnership funded the cash payment of the purchase price with borrowings under its secured revolving credit facility. The assets acquired in the MB Minerals Acquisition are located in Howard and Borden Counties, Texas. The MB Minerals Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $60.8 million to proved properties and $74.9 million to unevaluated properties.

2022 Activity

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

2021 Activity

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

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

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

Joint Ventures

On June 19, 2019, the Partnership entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP, a related party. The Partnership’s ownership in the Joint Venture was

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49.3%. During the year ended December 31, 2022, the Joint Venture completed the sale of its royalty, mineral and overriding interests and similar non-cost bearing interests in oil and gas properties for a total purchase price of $15.0 million. Net proceeds distributed to the Partnership were $6.5 million during the year ended December 31, 2022, the majority of which was used to repay debt on the Partnership’s secured revolving credit facility. On November 1, 2022, the Joint Venture was dissolved.

Special Purpose Acquisition Company

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

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

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

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

NOTE 4—DERIVATIVES

Commodity Derivatives

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

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

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

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Interest Rate Swaps

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

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


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

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


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

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

Oil Price Swaps


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

Natural Gas Price Swaps


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

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NOTE 5—FAIR VALUE MEASUREMENTS

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

●

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

●

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

●

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

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

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

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


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

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NOTE 6—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


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

The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The Partnership assesses all unevaluated properties on a periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved developed reserves is able to be made. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and to the full cost ceiling test.

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

NOTE 7—LEASES

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

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

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

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

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


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

NOTE 8—LONG-TERM DEBT

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

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

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

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

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

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

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

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The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of not more than 3.5 to 1.0 and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0.

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

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

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

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

NOTE 9—PREFERRED UNITS

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

Until the conversion of the Series A preferred units into common units or their redemption, holders of the Series A preferred units are entitled to receive cumulative quarterly distributions equal to 6.0% per annum plus accrued and unpaid distributions. The Partnership has the right, in any four non-consecutive quarters, to elect not to pay such quarterly distribution in cash and instead have the unpaid distribution amount added to the liquidation preference at the rate of 10.0% per annum. If the Partnership makes such an election in consecutive quarters or if the Partnership fails to pay in full, in cash and when due, any distribution owed to the Series A preferred units or otherwise materially breaches its obligations to the holders of the Series A preferred units, the distribution rate will increase to 20.0% per annum until the accumulated distributions are paid in full in cash, or any such material breach is cured, as applicable. Each holder of Series A preferred units has the right to share in any special distributions by the Partnership of cash, securities or other property pro rata with the common units on an as-converted basis, subject to customary adjustments. The Partnership cannot declare or make any distributions, redemptions, or repurchases on any junior securities, including any of their common units, prior to paying the quarterly distribution payable to the Series A preferred units, including any previously accrued and unpaid distributions.

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

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

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

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

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

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

The terms of the Series A preferred units contain covenants preventing the Partnership from taking certain actions without the approval of the holders of 66²/₃% of the outstanding Series A preferred units, voting separately as a class.

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

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

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

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

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

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


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

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

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


	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2023	$	0.35	May 3, 2023	May 15, 2023	May 22, 2023
Q2 2023	$	0.39	August 2, 2023	August 14, 2023	August 21, 2023
Q3 2023	$	0.51	November 2, 2023	November 13, 2023	November 20, 2023
Q4 2023	$	0.43	February 21, 2024	March 13, 2024	March 20, 2024

Q1 2022	$	0.47	April 22, 2022	May 2, 2022	May 9, 2022
Q2 2022	$	0.55	August 3, 2022	August 15, 2022	August 22, 2022
Q3 2022	$	0.49	November 3, 2022	November 14, 2022	November 21, 2022
Q4 2022	$	0.48	February 23, 2023	March 9, 2023	March 16, 2023

Q1 2021	$	0.27	April 23, 2021	May 3, 2021	May 10, 2021
Q2 2021	$	0.31	July 23, 2021	August 2, 2021	August 9, 2021
Q3 2021	$	0.37	October 22, 2021	November 1, 2021	November 8, 2021
Q4 2021	$	0.37	January 21, 2022	January 31, 2022	February 7, 2022

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


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

For each Class B unit issued, five cents have been paid to the Partnership as additional consideration (the “Class B Contribution”). Holders of the Class B units are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A preferred units but prior to distributions on the common units and OpCo common units.

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

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

NOTE 11—EARNINGS PER COMMON UNIT

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

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


	Year Ended December 31,
	2023		2022		2021
Net income attributable to common units of Kimbell Royalty Partners, LP	$	60,141,679	$	111,929,491	$	22,615,021
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		1,572,737		(17,412,732)		—
Net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		61,714,416		94,516,759		22,615,021
Distribution and accretion on Series A preferred units		6,310,215		—
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		16,553,676		18,864,795		8,496,104
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	84,578,307	$	113,381,554	$	31,111,125

Weighted average number of common units outstanding:
Basic		66,595,273		54,112,595		40,400,907
Effect of dilutive securities:
Series A preferred units		6,499,350		—		—
Class B units		18,851,387		10,819,266		18,839,607
Restricted units		1,111,721		905,156		1,717,310
Diluted		93,057,731		65,837,017		60,957,824

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.93	$	1.75	$	0.56
Diluted	$	0.91	$	1.72	$	0.51

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

NOTE 12—UNIT-BASED COMPENSATION

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

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

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


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

NOTE 13—INCOME TAXES

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

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

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


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

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


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

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


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

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

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

NOTE 14—RELATED PARTY TRANSACTIONS

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

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

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

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

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

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

NOTE 15—ADMINISTRATIVE SERVICES

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

NOTE 16—COMMITMENTS AND CONTINGENCIES

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

NOTE 17—SUBSEQUENT EVENTS

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

Distributions

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

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

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

Executive Bonus and LTIP Issuance

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

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NOTE 18—CORRECTION OF IMMATERIAL ERRORS

The Partnership has identified an error in its application of accounting guidance related to the changes in ownership of OpCo. The Partnership previously accounted for changes in ownership of OpCo by reallocating the non-controlling interest associated with such changes at fair value. Under ASC 810-10, changes in ownership of a consolidated subsidiary that is less than wholly owned (such as OpCo) should be accounted for by adjusting the carrying value of such non-controlling interests to reflect the change in ownership interest in the subsidiary. Any difference between fair value of consideration received or paid and the amount by which the noncontrolling interest is adjusted should be recognized in equity attributable to the parent.

The Partnership evaluated the impact of this error on the previously issued financial statements and determined that it was not material to any periods. The error (i) resulted only in a reclass of amounts between components in unitholders’ equity (specifically, from Common Units to Non-Controlling Interest in OpCo) and (ii) did not have any impact on the Total Unitholders’ Equity amount in the Partnership’s consolidated balance sheets, the Total amount in the Partnership’s consolidated statement of changes in unitholders’ equity or any other portion of the Partnership’s financial statements. Moreover, the error had no impact on items in the Partnership’s consolidated statement of operations or statement of cash flows, including any information related to revenues, net income, net income attributable to common units, earnings per unit and other items. Further, the error did not have any impact on compliance with its material financial covenants under debt instruments or other contractual arrangements.

The Partnership has adjusted its consolidated balance sheet at December 31, 2023 and 2022 and its consolidated statement of changes in unitholders’ equity for the years ended December 31, 2023, 2022 and 2021.

The effects of the adjustments on the individual line items within the Partnership’s consolidated balance sheets and consolidated statement of changes in unitholders’ equity for the periods indicated are as follows:


	December 31, 2021
	As Reported		Adjustments		As Adjusted
Common units	$	328,717,841	$	(75,597,839)	$	253,120,002
Class B units		880,579		—		880,579
Non-controlling interest in OpCo		19,251,361		75,597,839		94,849,200
Total unitholders' equity	$	348,849,781	$	—	$	348,849,781

	December 31, 2022
	As Reported		Adjustments		As Adjusted
Common units	$	601,841,776	$	(138,089,866)	$	463,751,910
Class B units		774,220		—		774,220
Non-controlling interest in OpCo		(26,106,320)		138,089,866		111,983,546
Total unitholders' equity	$	576,509,676	$	—	$	576,509,676

	December 31, 2023
	As Reported		Adjustments		As Adjusted
Common units	$	670,530,748	$	(114,721,748)	$	555,809,000
Class B units		1,042,365		—		1,042,365
Non-controlling interest in OpCo		42,470,067		114,721,748		157,191,815
Total unitholders' equity	$	714,043,180	$	—	$	714,043,180

Change in Ownership of Consolidated Subsidiaries

In addition to the error noted above related to the changes in ownership of OpCo, the Partnership added a new line item to its consolidated statement of changes in unitholders’ equity “Changes in ownership of consolidated subsidiaries, net.” This adjustment is included in the adjustment balances noted above.

Non-controlling interest in the accompanying consolidated financial statements represents the non-controlling interest in the net assets of the Operating Company. The Partnership’s relative ownership interest in OpCo can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, conversion

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of Class B to common units, repurchases of common units and distribution rights paid on the Partnership’s units. These changes in ownership percentage result in adjustments to non-controlling interest and common unitholders' equity.

The following table summarizes the changes in common unitholders' equity due to changes in ownership interest during the period:


	Year Ended December 31,
	2023		2022		2021
Net income attributable to the Partnership	$	65,151,528	$	111,971,734	$	30,647,893
Changes in ownership of consolidated subsidiaries, net		23,421,490		49,056,142		(12,295,407)
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$	88,573,018	$	161,027,876		18,352,486

NOTE 19—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

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

Capitalized Oil and Natural Gas Costs

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


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

Costs Incurred in Oil and Natural Gas Activities

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


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

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

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


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

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

Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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

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


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

Net proved developed reserves
December 31, 2021	12,511	157,764	6,669	45,474
December 31, 2022	12,355	160,298	7,388	46,459
December 31, 2023	19,800	204,542	11,519	65,409

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

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

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

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

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

Standardized Measure

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


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

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

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

Changes in Standardized Measure

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


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

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Kimbell Royalty Partners (KRP) 10-K/A2023 FY Annual report (amended)

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