10-Q - KRP - Equibles

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2023<br><br>OR

☐	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<br>(State or other jurisdiction of<br>incorporation or organization)	1311<br>(Primary Standard Industrial<br>Classification Code Number)	47-5505475<br>(I.R.S. Employer<br>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 Act:

<br><br><br><br>
Title of each class:	Trading symbol(s)	Name of exchange on which registered:
Common Units Representing Limited Partner Interests	KRP	New York Stock Exchange

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 (§232.405 of this chapter) 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, 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of July 28, 2023, the registrant had outstanding 65,507,635 common units representing limited partner interests and 20,853,618 Class B units representing limited partner interests.

Table of Contents KIMBELL ROYALTY PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION<br><br>
Item 1. Consolidated Financial Statements (Unaudited):	1
Consolidated Balance Sheets	1
Consolidated Statements of Operations	2
Consolidated Statements of Changes in Unitholders’ Equity	3
Consolidated Statements of Cash Flows	5
Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3. Quantitative and Qualitative Disclosures About Market Risk	38
Item 4. Controls and Procedures	39


PART II – OTHER INFORMATION<br><br>
Item 1. Legal Proceedings	39
Item 1A. Risk Factors	39
Item 5. Other Information	40
Item 6. Exhibits	40
Signatures	42

Table of Contents PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	20,779,119	$	24,635,718
Oil, natural gas and NGL receivables		45,006,388		46,993,711
Derivative assets		1,794,888		—
Accounts receivable and other current assets		3,135,807		3,562,912
Total current assets		70,716,202		75,192,341
Property and equipment, net		771,872		953,781
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($125,601,085 and $207,695,343 excluded from depletion at June 30, 2023 and December 31, 2022, respectively)		1,602,199,705		1,465,985,718
Less: accumulated depreciation, depletion and impairment		(749,745,922)		(712,716,951)
Total oil and natural gas properties, net		852,453,783		753,268,767
Right-of-use assets, net		2,357,665		2,525,323
Derivative assets		1,580,439		754,786
Loan origination costs, net		6,308,398		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	$	934,188,359	$	1,076,746,299

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	1,369,894	$	1,210,337
Other current liabilities		8,340,805		4,909,510
Derivative liabilities		428,560		12,646,720
Total current liabilities		10,139,259		18,766,567
Operating lease liabilities, excluding current portion		2,066,030		2,236,361
Derivative liabilities		170,529		432,142
Long-term debt		269,600,000		233,015,911
Other liabilities		260,417		322,917
Liabilities of consolidated variable interest entities:
Other current liabilities		—		512,725
Deferred underwriting commissions		—		8,050,000
Total liabilities		282,236,235		263,336,623
Commitments and contingencies (Note 15)
Mezzanine equity:
Redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		—		236,900,000
Kimbell Royalty Partners, LP unitholders' equity:
Common units (65,507,635 units and 64,231,833 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively)		596,177,270		601,841,776
Class B units (20,853,618 and 15,484,400 units issued and outstanding as of June 30, 2023 and December 31, 2022, respectively)		1,042,681		774,220
Total Kimbell Royalty Partners, LP unitholders' equity		597,219,951		602,615,996
Non-controlling interest (deficit) in OpCo		54,732,173		(26,106,320)
Total equity		651,952,124		576,509,676
Total liabilities, mezzanine equity and unitholders' equity	$	934,188,359	$	1,076,746,299

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

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenue
Oil, natural gas and NGL revenues	$	56,981,614	$	78,591,469	$	114,398,373	$	143,675,372
Lease bonus and other income		2,041,189		1,213,322		2,478,526		1,867,452
Gain (Loss) on commodity derivative instruments, net		1,729,459		(7,094,127)		10,791,835		(39,077,647)
Total revenues		60,752,262		72,710,664		127,668,734		106,465,177
Costs and expenses
Production and ad valorem taxes		5,404,955		5,002,794		9,682,159		9,023,705
Depreciation and depletion expense		19,656,855		11,273,960		37,220,503		22,033,124
Marketing and other deductions		2,907,459		4,063,004		5,669,498		7,571,070
General and administrative expense		7,925,159		7,866,176		16,203,426		14,455,435
Consolidated variable interest entities related:
General and administrative expense		219,473		590,500		927,699		1,329,959
Total costs and expenses		36,113,901		28,796,434		69,703,285		54,413,293
Operating income		24,638,361		43,914,230		57,965,449		52,051,884
Other income (expense)
Equity income in affiliate		—		3,385,325		—		3,634,733
Interest expense		(6,341,118)		(3,323,290)		(11,804,522)		(6,201,145)
Loss on extinguishment of debt		(480,244)		—		(480,244)		—
Other (expense) income		(180,765)		898,207		(180,765)		3,966,657
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		1,069,854		223,135		3,508,691		324,521
Net income before income taxes		18,706,088		45,097,607		49,008,609		53,776,650
Income tax expense		909,057		1,803,441		2,312,040		2,075,240
Net income		17,797,031		43,294,166		46,696,569		51,701,410
Net income attributable to non-controlling interests in OpCo		(4,297,442)		(5,424,092)		(9,860,860)		(6,482,769)
Distribution on Class B units		(31,601)		(8,211)		(47,085)		(25,821)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	13,467,988	$	37,861,863	$	36,788,624	$	45,192,820

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.24	$	0.66	$	0.61	$	0.54
Diluted	$	0.23	$	0.55	$	0.59	$	0.42
Weighted average number of common units outstanding
Basic		63,274,492		55,424,930		62,910,053		50,710,073
Diluted		82,959,981		65,543,669		81,263,101		65,323,279

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

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


		Six Months Ended June 30, 2023
													Non-controlling
	****	Common Units		****	Amount		****	Class B Units		****	Amount		Interest in OpCo		Total
Balance at January 1, 2023			64,231,833		$	601,841,776			15,484,400		$	774,220	$	(26,106,320)	$	576,509,676
Restricted units repurchased for tax withholding			(279,662)			(4,851,962)			—			—		—		(4,851,962)
Unit-based compensation			998,162			3,170,000			—			—		—		3,170,000
Distributions to unitholders			—			(31,176,160)			—			—		(7,436,615)		(38,612,775)
Distribution on Class B units			—			(15,484)			—			—		—		(15,484)
Net income			—			23,336,120			—			—		5,563,418		28,899,538
Balance at March 31, 2023			64,950,333			592,304,290			15,484,400			774,220		(27,979,517)		565,098,993
Units issued for acquisition			557,302			8,654,900			5,369,218			268,461		83,383,956		92,307,317
Unit-based compensation			—			3,289,740			—			—		—		3,289,740
Distributions to unitholders			—			(22,732,617)			—			—		(5,349,476)		(28,082,093)
Distribution on Class B units			—			(31,601)			—			—		—		(31,601)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions			—			1,192,969			—			—		379,768		1,572,737
Net income			—			13,499,589			—			—		4,297,442		17,797,031
Balance at June 30, 2023			65,507,635		$	596,177,270			20,853,618		$	1,042,681	$	54,732,173	$	651,952,124

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY — (Continued)

(Unaudited)


		Six Months Ended June 30, 2022
													Non-controlling		Non-controlling
	****	Common Units		****	Amount		****	Class B Units		****	Amount		Interest in OpCo		Interest in TGR		Total
Balance at January 1, 2022			47,162,773		$	328,717,841			17,611,579		$	880,579	$	19,251,361	$	—	$	348,849,781
Costs associated with equity offering			—			(325,508)			—			—		—		—		(325,508)
Conversion of Class B units to common units			9,357,919			161,424,103			(9,357,919)			(467,896)		(161,424,103)		—		(467,896)
Restricted units repurchased for tax withholding			(193,604)			(3,344,828)			—			—		—		—		(3,344,828)
Unit-based compensation			963,835			2,194,342			—			—		—		—		2,194,342
Distributions to unitholders			—			(17,450,226)			—			—		(6,516,284)		—		(23,966,510)
Distribution on Class B units			—			(17,610)			—			—		—		—		(17,610)
Proceeds from issuance of TGR public warrants			—			—			—			—		—		11,500,000		11,500,000
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation			—			(16,325,799)			—			—		(2,351,988)		(11,500,000)		(30,177,787)
Net income			—			7,348,567			—			—		1,058,677		—		8,407,244
Balance at March 31, 2022			57,290,923			462,220,882			8,253,660			412,683		(149,982,337)		—		312,651,228
Conversion of Class B units to common units			42,081			722,952			(42,081)			(2,104)		(722,952)		—		(2,104)
Forfeitures of restricted units			(1,171)			(19,813)			—			—		—		—		(19,813)
Unit-based compensation			—			2,949,491			—			—		—		—		2,949,491
Distributions to unitholders			—			(26,945,962)			—			—		(3,859,442)		—		(30,805,404)
Distribution on Class B units			—			(8,211)			—			—		—		—		(8,211)
Accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation			—			(1,519,432)			—			—		(217,627)		—		(1,737,059)
Net income			—			37,870,074			—			—		5,424,092		—		43,294,166
Balance at June 30, 2022			57,331,833		$	475,269,981			8,211,579		$	410,579	$	(149,358,266)	$	—	$	326,322,294

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

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2023		2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	46,696,569	$	51,701,410
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		37,220,503		22,033,124
Amortization of right-of-use assets		167,658		157,298
Amortization of loan origination costs		1,008,830		901,660
Loss on extinguishment of debt		480,244		—
Equity income in affiliate		—		(3,634,733)
Cash distribution from affiliate		—		3,770,651
Forfeiture of restricted units		—		(19,813)
Unit-based compensation		6,459,740		5,143,833
(Gain) loss on derivative instruments, net of settlements		(15,100,314)		12,116,997
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		1,987,323		(18,448,369)
Accounts receivable and other current assets		427,105		906,119
Accounts payable		159,557		741,972
Other current liabilities		3,431,295		1,859,036
Operating lease liabilities		(170,331)		(159,717)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(3,508,691)		(324,521)
Other assets and liabilities		(687,353)		(289,307)
Net cash provided by operating activities		78,572,135		76,455,640
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(72,123)		(75,398)
Purchase of oil and natural gas properties		(44,175,131)		(443,977)
Proceeds from trust of variable interest entity		930,850		—
Cash distribution from affiliate		—		3,465,376
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 provided by (used in) investing activities		199,882,583		(233,953,999)
CASH FLOWS FROM FINANCING ACTIVITIES
Costs associated with equity offering		—		(325,508)
Contributions from Class B unitholders		268,461		—
Redemption of Class B contributions on converted units		—		(470,000)
Distributions to common unitholders		(53,908,777)		(44,396,188)
Distribution to OpCo unitholders		(12,786,091)		(10,375,726)
Distribution on Class B units		(47,085)		(25,821)
Borrowings on long-term debt		59,084,089		36,200,000
Repayments on long-term debt		(22,500,000)		(37,200,000)
Payment of loan origination costs		(4,793,368)		(435,142)
Restricted units repurchased for tax withholding		(4,851,962)		(3,344,828)
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 (used in) provided by financing activities		(282,702,167)		164,550,499
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(4,247,449)		7,052,140
CASH AND CASH EQUIVALENTS, beginning of period		25,026,568		7,052,414
CASH AND CASH EQUIVALENTS, end of period	$	20,779,119	$	14,104,554
Supplemental cash flow information:
Cash paid for interest	$	10,963,296	$	5,032,259
Cash paid for taxes	$	—	$	2,043,374
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	92,038,856	$	—
Recognition of tenant improvement asset	$	62,500	$	62,501
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

Table of Contents KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(Unaudited)


	Six Months Ended June 30,
	2023		2022
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	$	20,779,119	$	13,317,833
Cash held at consolidated variable interest entities		—		786,721
	$	20,779,119	$	14,104,554

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

Table of Contents Unless the context otherwise requi res, 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.

On February 8, 2022, the Partnership announced the $230 million initial public offering of its special purpose acquisition company, Kimbell Tiger Acquisition Corporation (NYSE: TGR).

Kimbell Tiger Acquisition Corporation (“TGR”) was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. Kimbell Tiger Acquisition Sponsor, LLC (“TGR Sponsor”), which 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 have been consolidated in the financial statements of the Partnership beginning in the year ended December 31, 2021.

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 (as defined in Note 4) included as part of the units issued in its initial public offering. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. Further details can be found in Note 4—Acquisitions, Joint Venture and Special Purpose Acquisition Company.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”). As a result, the accompanying unaudited interim consolidated financial statements do not include all disclosures required for complete annual financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Form 10-K”), which contains a summary of the Partnership’s significant accounting policies and other disclosures. In the opinion of management of the General Partner, the unaudited interim consolidated financial statements contain all adjustments necessary to fairly present the financial position and results of operations for the interim periods in accordance with GAAP and all adjustments are of a normal recurring nature. The accompanying unaudited interim consolidated financial statements include the accounts of the Partnership and its consolidated subsidiaries. All material intercompany balances 7

Table of Contents and transactions are eliminated in consolidation. The results of operations for any interim period are not necessarily indicative of the results to be expected for the full year.

Use of Estimates

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

Segment Reporting

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

Russia / Ukraine Conflict

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

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s 2022 Form 10-K, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three and six months ended June 30, 2023*.*

Consolidation

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

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

For entities determined to be VIEs, the Partnership must then evaluate whether it is the primary beneficiary of such VIEs. To make this determination, the Partnership evaluates its economic interests in the entity specifically determining if the Partnership has both the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits that could potentially be 8

Table of Contents significant to the VIE (the “benefits”). When making the determination on whether the benefits received from an entity are significant, the Partnership considers the total economics of the entity, and analyzes whether the Partnership’s share of the economics is significant. The Partnership utilizes qualitative factors, and, where applicable, quantitative factors, while performing the analysis.

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

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represent funds raised by TGR, a consolidated special purpose acquisition company, through the TGR IPO (as defined in Note 4). These funds were held in an actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust are classified as trading securities and are presented on the balance sheet at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in other income (expense)—interest earned on marketable securities in trust account on the accompanying unaudited interim consolidated statements of operations. 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, as described in Note 6— Fair Value Measurements.

Redeemable Non-Controlling Interest

Redeemable non-controlling interests represent the shares of TGR Class A common stock (as defined in Note 4) 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.

New 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.

NOTE 3—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. 9

Table of Contents 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:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Oil revenue	$	39,809,883	$	34,567,049	$	72,810,169	$	68,340,181
Natural gas revenue		11,539,982		35,876,768		31,188,764		58,894,902
NGL revenue		5,631,749		8,147,652		10,399,440		16,440,289
Total Oil, natural gas and NGL revenues	$	56,981,614	$	78,591,469	$	114,398,373	$	143,675,372

NOTE 4 — ACQUISITIONS, JOINT VENTURE AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

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.

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.

Joint Venture

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

Special Purpose Acquisition Company

On July 29, 2021, TGR, the Partnership’s recently dissolved special purpose acquisition company and subsidiary, filed a registration statement on Form S-1 with the SEC. On February 8, 2022, TGR consummated its initial public offering (the “TGR IPO”) of 23,000,000 units (each a “unit” and, collectively, the “units”), including 3,000,000 additional units issued pursuant to the underwriter’s exercise in full of its over-allotment option, at $10.00 per unit, generating proceeds of approximately $230,000,000 and incurring offering costs of approximately $12,650,000, inclusive of $8,050,000 in deferred underwriting commissions. Each unit consisted of one share of Class A common stock, par value $0.0001 (the 10

Table of Contents “TGR Class A common stock”), and one-half of one redeemable warrant. Each whole warrant was exercisable for one share of Class A common stock at a price of $11.50 per share. Certain members of our management and members of the Board of Directors were members of the sponsor of TGR, TGR Sponsor. TGR was formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses (the “Business Combination”). Under the terms of TGR’s governing documents, TGR had until May 8, 2023 (15 months from the closing of the TGR IPO) to complete the Business Combination, subject to TGR Sponsor’s option to extend such deadline by three months up to two times.

In connection with the closing of the TGR IPO, TGR completed the sale of 14.1 million private placement warrants (the “private placement warrants”) to TGR Sponsor, which was a subsidiary of the Partnership, for a purchase price of $1.00 per private placement warrant, generating gross proceeds of $14.1 million. Each private placement warrant was exercisable to purchase for $11.50 one share of TGR Class A common stock.

In addition, TGR incurred $12.7 million of fees and expenses, of which $8.1 million were deferred underwriting commissions that became payable to the underwriters solely in the event that TGR completed the Business Combination, which were included in deferred underwriting commissions on the accompanying unaudited interim consolidated balance sheet at December 31, 2022.

In May 2021, prior to TGR’s IPO, TGR Sponsor paid $25,000 in exchange for the issuance of (i) 5,750,100 shares of TGR’s Class B common stock, par value $0.0001 per share (the “TGR Class B common stock”), and (ii) 2,500 shares of TGR Class A common stock. Additionally, in May 2021, TGR paid $25,000 to Kimbell Tiger Operating Company (“TGR Opco”) in exchange for the issuance of 2,500 Class A units of TGR Opco. Also in May 2021, TGR Sponsor received 100 Class A units of TGR Opco in exchange for $1,000 and 5,750,000 Class B units of TGR Opco. The shares of TGR Class B common stock and corresponding number of Class B units of TGR Opco (or the Class A units of TGR Opco into which such Class B units will convert) are collectively referred to as the “Founders Shares.” The Founders Shares would have been exchangeable for shares of TGR Class A common stock upon completion of the Business Combination on a one-for-one basis, subject to certain adjustments. Class A units and Class B units of TGR Opco were substantially similar, other than certain distribution rights, and were entitled to vote together as a single class on all matters submitted for stockholder vote.

In determining the accounting treatment of the Partnership’s equity interest in TGR, management concluded that TGR was a VIE as defined by Accounting Standards Codification Topic 810, “Consolidation.” A VIE is an entity in which equity investors at risk lack the characteristics of a controlling financial interest. VIEs are consolidated by the primary beneficiary, the party who has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, as well as the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the entity. TGR Sponsor was the primary beneficiary of TGR as it had, through its equity interest, the right to receive benefits or the obligation to absorb losses from TGR, as well as the power to direct a majority of the activities that significantly impacted TGR’s economic performance, including identification of a target for its Business Combination. As such, TGR was consolidated into the Partnership’s financial statements through TGR Sponsor.

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 per-share redemption price for the TGR public shares was $10.57 and the Partnership remeasured and accreted through equity the redeemable non- 11

Table of Contents controlling interest in TGR to its redemption value of $243.0 million and wrote off the deferred underwriting commissions through equity. The public shares of TGR ceased trading as of the close of business on May 8, 2023. As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR on June 30, 2023. The net non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying unaudited interim consolidated balance sheet as of June 30, 2023.

NOTE 5 — 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.

As of June 30, 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 hedges its production based on the amount of debt and/or preferred equity as a percent of its enterprise value. As of June 30, 2023, these economic hedges constituted approximately 15% of daily oil and natural gas production.

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 for 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 unaudited interim consolidated statements of operations.

Interest Rate Swaps

On January 27, 2021, the Partnership entered into an interest rate swap with Citibank, N.A., New York (“Citibank”), which fixed the interest rate on $150.0 million of the notional balance on our secured revolving credit facility. On May 17, 2022, the Partnership entered into a partial termination agreement with Citibank to unwind 50% of the interest rate swap. On August 8, 2022, the Partnership entered into a termination agreement with Citibank to unwind the remaining 50% of the interest rate swap. The May 2022 termination resulted in a $3.0 million gain, which is included in other income (expense) in the accompanying unaudited interim consolidated statements of operations for the three and six months ended June 30, 2022. 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 unaudited interim consolidated statements of operations. As of June 30, 2022, the interest rate swap had a total notional amount of $75.0 million and a fair value of $3.3 million. 12

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Beginning fair value of derivative instruments	$	175,525	$	(45,305,641)	$	(12,324,076)	$	(26,624,646)
Gain (loss) on derivative instruments		1,729,459		(6,195,920)		10,791,835		(34,434,335)
Net cash paid on settlements of derivative instruments		871,254		12,759,918		4,308,479		22,317,338
Ending fair value of derivative instruments	$	2,776,238	$	(38,741,643)	$	2,776,238	$	(38,741,643)

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


		June 30,		December 31,
Classification	Balance Sheet Location	2023		2022
Assets:
Current assets	Derivative assets	$	1,794,888	$	—
Long-term assets	Derivative assets		1,580,439		754,786
Liabilities:
Current liabilities	Derivative liabilities		(428,560)		(12,646,720)
Long-term liabilities	Derivative liabilities		(170,529)		(432,142)
		$	2,776,238	$	(12,324,076)

As of June 30, 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
July 2023 - December 2023	140,668	$	62.33	$	61.70	$	63.00
January 2024 - December 2024	228,044	$	74.44	$	69.30	$	82.40
January 2025 - June 2025	171,558	$	65.17	$	64.35	$	66.31

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
July 2023 - December 2023	2,043,412	$	3.18	$	3.09	$	3.28
January 2024 - December 2024	3,229,292	$	4.34	$	4.15	$	4.48
January 2025 - June 2025	1,765,168	$	3.93	$	3.53	$	4.37

NOTE 6—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 unaudited interim consolidated balance sheets approximated fair value as of June 30, 2023 and December 31, 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).
---	---

Table of Contents 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 three and six months ended June 30, 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
June 30, 2023
Assets
Commodity derivative contracts	$	—	$	3,375,327	$	—	$	—	$	3,375,327
Liabilities
Commodity derivative contracts	$	—	$	(599,089)	$	—	$	—	$	(599,089)
December 31, 2022
Assets
Commodity derivative contracts	$	—	$	754,786	$	—	$	—	$	754,786
Investments held in trust	$	240,621,146	$	—	$	—	$	—	$	240,621,146
Liabilities
Commodity derivative contracts	$	—	$	(13,078,862)	$	—	$	—	$	(13,078,862)

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


	June 30,		December 31,
	2023		2022
Oil and natural gas properties
Proved properties	$	1,476,598,620	$	1,258,290,375
Unevaluated properties		125,601,085		207,695,343
Less: accumulated depreciation, depletion and impairment		(749,745,922)		(712,716,951)
Total oil and natural gas properties	$	852,453,783	$	753,268,767

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 producing 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. The Partnership did not record an impairment on its oil and natural gas properties for the three or six months ended June 30, 2023 or 2022. 14

Table of Contents NOTE 8—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 unaudited interim consolidated balance sheets. Short term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of June 30, 2023 is 5.88 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 leases was 6.75% for the six months ended June 30, 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 unaudited interim consolidated statements of operations for the three and six months ended June 30, 2023 and 2022. The total operating lease expense recorded for both the three months ended June 30, 2023 and 2022 was $0.1 million and $0.3 million and $0.2 million for the six months ended June 30, 2023 and 2022, respectively.

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

Future minimum lease commitments as of June 30, 2023 were as follows:


	Total		2023		2024		2025		2026		2027		Thereafter
Operating leases	$	2,956,414	$	243,741	$	488,725	$	497,033	$	507,648	$	511,917	$	707,350
Less: Imputed Interest		(554,818)
Total	$	2,401,596

NOTE 9—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 $750,000,000, 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 $10,000,000, and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027.

The 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 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 15

Table of Contents Lenders between scheduled redeterminations during each calendar year. The first scheduled redetermination will be on or around November 1, 2023.

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 A&R Credit Agreement) above $30.0 million is required to be applied weekly to prepay loans (without a commitment reduction) if not otherwise reduced to zero in a manner permitted by the A&R Credit Agreement.

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

The A&R Credit Agreement requires the Partnership to maintain as of the last day of each fiscal quarter: (i) a Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of not more than

3.5

to 1.0 and (ii) a ratio of current assets to current liabilities of not less than

1.0

to 1.0, each beginning with the fiscal quarter ending June 30, 2023. 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.

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 amends the A&R Credit Agreement to, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit the Partnership to issue certain preferred equity interests.

During the six months ended June 30, 2023, the Partnership borrowed an additional $59.1 million under the secured revolving credit facility and repaid approximately $22.5 million of the outstanding borrowings. As of June 30, 2023, the Partnership’s outstanding balance was $269.6 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2023.

As of June 30, 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 three and six months ended June 30, 2023, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.76% and 8.52%, respectively.

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of June 30, 2023, the Partnership had a total of 65,507,635 common units issued and outstanding and 20,853,618 Class B units outstanding.

In November 2022, the Partnership completed an underwritten public offering of 6,900,000 common units for net proceeds of approximately $117.0 million (the “2022 Equity Offering”). The Partnership used the net proceeds from the 16

Table of Contents 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.

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
Balance at June 30, 2023		65,507,635
(1)	Includes restricted units granted to certain employees and directors under the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan 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

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

For each Class B unit issued, five cents has 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 prior to distributions on the common units and OpCo common units.

The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

NOTE 11—EARNINGS (LOSS) PER COMMON UNI T

Basic earnings (loss) per common unit is calculated by dividing net income (loss) attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested 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 Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the 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. 17

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income attributable to common units of Kimbell Royalty Partners, LP	$	13,467,988	$	37,861,863	$	36,788,624	$	45,192,820
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		1,572,737		(1,519,432)		1,572,737		(17,845,231)
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		15,040,725		36,342,431		38,361,361		27,347,589
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		4,329,043		—		9,907,945		—
Diluted net income attributable to common units of Kimbell Royalty Partners, LP after accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation		19,369,768		36,342,431		48,269,306		27,347,589

Weighted average number of common units outstanding:
Basic		63,274,492		55,424,930		62,910,053		50,710,073
Effect of dilutive securities:
Class B units		18,139,508		8,221,290		16,819,289		12,787,092
Restricted units		1,545,981		1,897,449		1,533,759		1,826,114
Diluted		82,959,981		65,543,669		81,263,101		65,323,279

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.24	$	0.66	$	0.61	$	0.54
Diluted	$	0.23	$	0.55	$	0.59	$	0.42

The calculation of diluted net income per share for the three and six months ended June 30, 2023 and 2022 includes the conversion of all Class B units to common units calculated using the “if-converted” method and units of 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-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. 18

Table of Contents 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 June 30, 2023	1,951,430	$	14.763		2.029 years

NOTE 13—INCOME TAXES

The Partnership’s provision for income taxes is based on the estimated annual effective tax rate plus discrete items. The Partnership recorded an income tax expense of $0.9 million and $1.8 million for the three months ended June 30, 2023 and 2022, respectively, and an income tax expense of $2.3 million and $2.1 million for the six months ended June 30, 2023 and 2022, respectively.

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”) and 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 may 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 three and six months ended June 30, 2023, no monthly services fee was paid to BJF Royalties. During the three and six months ended June 30, 2023, the Partnership made payments to K3 Royalties in the amount of $30,000 and $60,000, respectively. Certain consultants who provide services under management services agreements are granted restricted units under the Partnership’s A&R LTIP.

The Partnership received $48,853 and $105,095 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three and six months ended June 30, 2023, respectively.

Commencing on the date of the TGR IPO, TGR agreed to pay the Partnership a total of $25,000 per month for office space utilities, secretarial support and administrative services provided to members of the management team. During the three and six months ended June 30, 2023, TGR incurred $25,000 and $50,000, respectively, as part of this service agreement. Such fees are eliminated in consolidation. Upon TGR’s liquidation, TGR ceased paying these monthly fees.

NOTE 15—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 June 30, 2023.

NOTE 16—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2023 in the preparation of its unaudited interim consolidated financial statements. 19

Table of Contents Distributions

On August 2, 2023, the Board of Directors declared a quarterly cash distribution of $0.39 per common unit and OpCo common unit for the quarter ended June 30, 2023. The Partnership intends to pay this distribution on August 21, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on August 14, 2023.

Acquisition

On August 2, 2023, the Partnership announced that it has agreed to acquire mineral and royalty interests held by LongPoint Minerals II, LLC in a cash transaction valued at approximately $455.0 million, subject to purchase price adjustments and other customary closing adjustments. The Partnership intends to fund the purchase price through a private placement of 6.00% Series A Cumulative Convertible Preferred Units to funds managed by affiliates of Apollo Global Management, LLC and borrowings under its revolving credit facility. The final mix of funding will be determined at closing.

Long-Term Debt

On July 28, 2023, the Partnership drew down $47.0 million on the senior secured revolving credit facility to fund the deposit on the LongPoint Acquisition.

Table of Contents Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of f inancial conditio n and results of operations should be read in conjunction with our unaudited interim consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Form 10-K”).

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” 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 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.

Cautionary Statement Regarding Forward-Looking Statements

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

●	our ability to replace our reserves;
●	our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;
---	---
●	our ability to execute our business strategies;
---	---
●	the volatility of realized prices for oil, natural gas and natural gas liquids (“NGLs”), including as a result of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries;
---	---
●	the level of production on our properties;
---	---
●	the level of drilling and completion activity by the operators of our properties;
---	---
●	our ability to forecast identified drilling locations, gross horizontal wells, drilling inventory and estimates of reserves on our properties and on properties we seek to acquire;
---	---
●	regional supply and demand factors, delays or interruptions of production;
---	---
●	industry, economic, business or political conditions, including the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies;
---	---
●	the continued threat of terrorism and the impact of military and other action and armed conflict, such as the current conflict between Russia and Ukraine;
---	---
●	revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
---	---

Table of Contents

●	impact of impairment expense on our financial statements;
●	competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
---	---
●	the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
---	---
●	title defects in the properties in which we acquire an interest;
---	---
●	the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;
---	---
●	restrictions on or the availability of the use of water in the business of the operators of our properties;
---	---
●	the availability of transportation facilities;
---	---
●	the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
---	---
●	federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry, including the Biden administration’s proposals and recent executive orders focused on addressing climate change;
---	---
●	future operating results;
---	---
●	exploration and development drilling prospects, inventories, projects and programs;
---	---
●	operating hazards faced by the operators of our properties;
---	---
●	the ability of the operators of our properties to keep pace with technological advancements;
---	---
●	uncertainties regarding United States federal income tax law, including the treatment of our future earnings and distributions; and
---	---
●	our ability to maintain effective internal controls over financial reporting and disclosure controls and procedures.
---	---

These factors are discussed in further detail in the 2022 Form 10-K under “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II and elsewhere in this Quarterly Report. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

Overview

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

As of June 30, 2023, we owned mineral and royalty interests in approximately 11.6 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 52% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2023, over 99% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were 22

Table of Contents held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 125,000 gross wells, including over 48,000 wells in the Permian Basin.

The following table summarizes our ownership in United States basins and producing regions and information about the wells in which we have a mineral or royalty interest as June 30, 2023:


				Average Daily
				Production
Basin or Producing Region		Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	Well Count
Permian Basin		3,176,076	25,245	6,070	48,766
Mid‑Continent		5,369,358	44,310	1,897	19,205
Terryville/Cotton Valley/Haynesville		1,428,907	7,919	3,692	16,175
Appalachian Basin		741,354	23,203	1,821	3,871
Bakken/Williston Basin		1,640,077	6,138	894	5,278
Eagle Ford		624,148	6,730	1,797	4,088
DJ Basin/Rockies/Niobrara		74,152	1,036	720	12,540
Other		3,232,560	36,693	1,254	15,413
Total		16,286,632	151,274	18,145	125,336
(1)	“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our 2022 Form 10-K.
---	---

The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of June 30, 2023:


Basin or Producing Region(1)		Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin		462	388	2.27	1.47
Mid‑Continent		76	49	0.14	0.10
Terryville/Cotton Valley/Haynesville		105	27	0.81	0.49
Appalachian Basin		5	12	0.01	0.03
Bakken/Williston Basin		68	175	0.23	0.20
Eagle Ford		43	61	0.39	0.47
DJ Basin/Rockies/Niobrara		8	22	0.04	0.21
Total		767	734	3.89	2.97
(1)	The above table represents DUCs and permitted locations only, and there is no guarantee that the DUCs or permitted locations will be developed into producing wells in the future.
---	---

Kimbell Tiger Acquisition Corporation

In April 2021, we formed Kimbell Tiger Acquisition Corporation (“TGR”) as a special purpose acquisition company, or SPAC, for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses. The sponsor of TGR was Kimbell Tiger Acquisition Sponsor, LLC (the “TGR Sponsor”), which was a wholly owned subsidiary of the Operating Company. The Sponsor owned a combination of equity securities in TGR and TGR’s operating company, Kimbell Tiger Operating Company, LLC (“TGR Opco”), that represented 20% of the total outstanding shares of common stock of TGR.

On February 8, 2022, TGR completed its initial public offering (the “TGR IPO”) of 23,000,000 units, including 3,000,000 units that were issued pursuant to the underwriter’s exercise in full of its over-allotment option. Each unit had an offering price of $10.00 and consisted of one share of Class A common stock of TGR, par value $0.0001 per share (the “Class A common stock”), and one-half of one redeemable warrant of TGR (each such whole warrant, a “Public Warrant”). Each Public Warrant entitled the holder thereof to purchase one share of Class A common stock at a price of $11.50 per share. 23

Table of Contents On February 8, 2022, simultaneously with the closing of the TGR IPO and pursuant to a separate private placement warrants purchase agreement dated February 3, 2022, TGR completed the private sale of 14.1 million private placement warrants (the “Private Placement Warrants”) to the TGR Sponsor at a purchase price of $1.00 per Private Placement Warrant, generating gross proceeds of $14,100,000. Each Private Placement Warrant was exercisable to purchase for $11.50 one share of Class A common stock.

Proceeds of $236.9 million were deposited in a trust account established for the benefit of TGR’s public unitholders consisting of certain proceeds from the TGR IPO and certain proceeds from the sale of the private placement warrants, net of underwriters’ discounts and commissions and other costs and expenses. The proceeds held in the trust account were not available to be used by us at any time. On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock included as part of the units issued in its initial public offering. The per-share redemption price for the TGR public shares was $10.57. The public shares of TGR ceased trading as of the close of business on May 8, 2023. As of the close of business on May 9, 2023, the public shares were deemed cancelled and represented only the right to receive the redemption amount. Following such redemption, TGR (along with TGR Sponsor) was dissolved in accordance with the terms of its organizational documents. There were no redemption rights or liquidating distributions with respect to TGR’s warrants, including the Private Placement Warrants held by TGR Sponsor, which expired worthless. TGR Sponsor waived its redemption rights with respect to TGR’s outstanding common stock issued before TGR’s initial public offering. The non-cash impact of the deconsolidation of TGR was $1.6 million, which is included in the accompanying unaudited interim consolidated balance sheet as of June 30, 2023.

Recent Developments

Acquisition

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

On August 2, 2023, we announced that we have agreed to acquire mineral and royalty interests held by LongPoint Minerals II, LLC in a cash transaction valued at approximately $455.0 million, subject to purchase price adjustments and other customary closing adjustments. We intend to fund the purchase price through a private placement of 6.00% Series A Cumulative Convertible Preferred Units to funds managed by an affiliate of Apollo Global Management, LLC and borrowings under our revolving credit facility. The final mix of funding will be determined at closing.

Long-Term Debt

On July 28, 2023, we drew down $47.0 million on our senior secured revolving credit facility to fund the deposit on the LongPoint Acquisition. 24

Table of Contents Quarterly Distributions

On August 2, 2023, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.39 per common unit and OpCo common unit for the quarter ended June 30, 2023. We intend to pay the distributions on August 21, 2023 to common unitholders and OpCo common unitholders of record as of the close of business on August 14, 2023.

Business Environment

Russia / Ukraine Conflict

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

Commodity Prices and Demand

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


	Six Months Ended June 30, 2023				Six Months Ended June 30, 2022
	High		Low		High		Low
Oil ($/Bbl)	$	83.26	$	66.61	$	123.64	$	75.99
Natural gas ($/MMBtu)	$	3.78	$	1.74	$	9.44	$	3.73

On July 24, 2023, the West Texas Intermediate posted price for crude oil was $78.81 per Bbl and the Henry Hub spot market price of natural gas was $2.68 per MMBtu.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Oil ($/Bbl)	$	73.54	$	108.83	$	74.73	$	102.01
Natural gas ($/MMBtu)	$	2.16	$	7.50	$	2.40	$	6.08

Rig Count

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

The Baker Hughes United States Rotary Rig count decreased by 10.5% to 653 active land rigs at June 30, 2023 compared to 730 active land rigs at June 30, 2022. The 653 active land rigs at June 30, 2023 decreased by 11.3% from 736 active land rigs at March 31, 2023. The overall decrease in rig count at June 30, 2023 compared June 30, 2022 is primarily attributable to the volatility and decrease in the average daily prices for oil and natural gas. 25

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


	June 30,
Basin or Producing Region	2023	2022
Permian Basin	50	38
Mid‑Continent	12	14
Terryville/Cotton Valley/Haynesville	17	11
Appalachian Basin	—	3
Bakken/Williston Basin	4	3
Eagle Ford	5	4
DJ Basin/Rockies/Niobrara	1	1
Other	1	—
Total	90	74

Sources of Our Revenue

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenue
Oil revenue	70	%	44	%	64	%	48	%
Natural gas revenue	20	%	46	%	27	%	41	%
NGL revenue	10	%	10	%	9	%	11	%
	100	%	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through June 2025, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. 26

Table of Contents Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

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

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, non cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments, cash distribution from affiliate, equity income (loss) in affiliate, gains and losses on sales of assets and operational impacts of VIEs, which include general and administrative expense and interest income. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

Adjusted EBITDA and cash available for distribution on common units should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution on common units may not be comparable to other similarly titled measures of other companies. 27

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	17,797,031	$	43,294,166	$	46,696,569	$	51,701,410
Depreciation and depletion expense		19,656,855		11,273,960		37,220,503		22,033,124
Interest expense		6,341,118		3,323,290		11,804,522		6,201,145
Cash distribution from affiliate		—		—		—		385,326
Income tax expense		909,057		1,803,441		2,312,040		2,075,240
EBITDA		44,704,061		59,694,857		98,033,634		82,396,245
Unit-based compensation		3,289,740		2,949,491		6,459,740		5,143,833
Loss on extinguishment of debt		480,244		—		480,244		—
(Gain) loss on derivative instruments, net of settlements		(2,600,713)		(6,563,998)		(15,100,314)		12,116,997
Cash distribution from affiliate		—		431,268		—		473,812
Equity income in affiliate		—		(3,385,325)		—		(3,634,733)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		(1,069,854)		(223,135)		(3,508,691)		(324,521)
General and administrative expenses		219,473		590,500		927,699		1,329,959
Consolidated Adjusted EBITDA		45,022,951		53,493,658		87,292,312		97,501,592
Adjusted EBITDA attributable to non-controlling interest		(10,871,674)		(6,701,931)		(19,008,901)		(12,233,681)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		34,151,277		46,791,727		68,283,411		85,267,911
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		4,442,318		2,441,582		8,566,027		4,400,361
Cash income tax (refund) expense		—		2,043,374		(639,325)		2,043,374
Distributions on Class B units		31,601		8,211		47,085		25,821
Cash available for distribution on common units	$	29,677,358	$	42,298,560	$	60,309,624	$	78,798,355

Table of Contents


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Reconciliation of net cash provided by operating activities to Adjusted EBITDA and cash available for distribution on common units:
Net cash provided by operating activities	$	31,518,529	$	40,423,167	$	78,572,135	$	76,455,640
Interest expense		6,341,118		3,323,290		11,804,522		6,201,145
Income tax expense		909,057		1,803,441		2,312,040		2,075,240
Amortization of right-of-use assets		(84,501)		(79,273)		(167,658)		(157,298)
Amortization of loan origination costs		(492,732)		(459,261)		(1,008,830)		(901,660)
Loss on extinguishment of debt		(480,244)		—		(480,244)		—
Equity income in affiliate, net		—		—		—		249,408
Forfeiture of restricted units		—		19,813		—		19,813
Unit-based compensation		(3,289,740)		(2,949,491)		(6,459,740)		(5,143,833)
Gain (loss) on derivative instruments, net of settlements		2,600,713		6,563,998		15,100,314		(12,116,997)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		9,070,691		12,039,342		(1,987,323)		18,448,369
Accounts receivable and other current assets		86,707		(175,459)		(427,105)		(906,119)
Accounts payable		(450,078)		340,681		(159,557)		(741,972)
Other current liabilities		(3,175,769)		(1,395,863)		(3,431,295)		(1,859,036)
Operating lease liabilities		85,313		80,471		170,331		159,717
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		1,069,854		223,135		3,508,691		324,521
Other assets and liabilities		995,143		(63,134)		687,353		289,307
EBITDA		44,704,061		59,694,857		98,033,634		82,396,245
Add:
Unit-based compensation		3,289,740		2,949,491		6,459,740		5,143,833
Loss on extinguishment of debt		480,244		—		480,244		—
(Gain) loss on derivative instruments, net of settlements		(2,600,713)		(6,563,998)		(15,100,314)		12,116,997
Cash distribution from affiliate		—		431,268		—		473,812
Equity income in affiliate		—		(3,385,325)		—		(3,634,733)
Consolidated variable interest entities related:
Interest earned on marketable securities in Trust Account		(1,069,854)		(223,135)		(3,508,691)		(324,521)
General and administrative expenses		219,473		590,500		927,699		1,329,959
Consolidated Adjusted EBITDA		45,022,951		53,493,658		87,292,312		97,501,592
Adjusted EBITDA attributable to non-controlling interest		(10,871,674)		(6,701,931)		(19,008,901)		(12,233,681)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		34,151,277		46,791,727		68,283,411		85,267,911
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		4,442,318		2,441,582		8,566,027		4,400,361
Cash income tax expense		—		2,043,374		(639,325)		2,043,374
Distributions on Class B units		31,601		8,211		47,085		25,821
Cash available for distribution on common units	$	29,677,358	$	42,298,560	$	60,309,624	$	78,798,355

Table of Contents Factors Affecting the Comparability of Our Results to Our Historical Results

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

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three and six months ended June 30, 2023 and 2022 include the acquisition of certain mineral and royalty assets held by Hatch Royalty LLC (the “Hatch Acquisition”) and the MB Minerals Acquisition.

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

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

Impairment of Oil and Natural Gas Properties

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience significant downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2023 and 2022.

Because we do not intend to book proved undeveloped reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. 30

Table of Contents Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	56,981,614	$	78,591,469	$	114,398,373	$	143,675,372
Lease bonus and other income		2,041,189		1,213,322		2,478,526		1,867,452
Gain (Loss) on commodity derivative instruments, net		1,729,459		(7,094,127)		10,791,835		(39,077,647)
Total revenues		60,752,262		72,710,664		127,668,734		106,465,177
Costs and expenses
Production and ad valorem taxes		5,404,955		5,002,794		9,682,159		9,023,705
Depreciation and depletion expense		19,656,855		11,273,960		37,220,503		22,033,124
Marketing and other deductions		2,907,459		4,063,004		5,669,498		7,571,070
General and administrative expenses		7,925,159		7,866,176		16,203,426		14,455,435
Consolidated variable interest entities related:
General and administrative expense		219,473		590,500		927,699		1,329,959
Total costs and expenses		36,113,901		28,796,434		69,703,285		54,413,293
Operating income		24,638,361		43,914,230		57,965,449		52,051,884
Other income (expense)
Equity income in affiliate		—		3,385,325		—		3,634,733
Interest expense		(6,341,118)		(3,323,290)		(11,804,522)		(6,201,145)
Loss on extinguishment of debt		(480,244)		—		(480,244)		—
Other (expense) income		(180,765)		898,207		(180,765)		3,966,657
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		1,069,854		223,135		3,508,691		324,521
Net income before income taxes		18,706,088		45,097,607		49,008,609		53,776,650
Income tax expense		909,057		1,803,441		2,312,040		2,075,240
Net income		17,797,031		43,294,166		46,696,569		51,701,410
Net income attributable to non-controlling interests in OpCo		(4,297,442)		(5,424,092)		(9,860,860)		(6,482,769)
Distribution on Class B units		(31,601)		(8,211)		(47,085)		(25,821)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	13,467,988	$	37,861,863	$	36,788,624	$	45,192,820
Production Data:
Oil (Bbls)		553,588		320,195		999,601		712,556
Natural gas (Mcf)		5,203,964		5,180,033		10,794,157		10,015,882
Natural gas liquids (Bbls)		230,241		176,730		432,946		381,155
Combined volumes (Boe) (6:1)		1,651,156		1,360,264		3,231,573		2,763,025

Comparison of the Three Months Ended June 30, 2023 to the Three Months Ended June 30, 2022

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2023, our oil, natural gas and NGL revenues were $57.0 million, a decrease of $21.6 million from $78.6 million for the three months ended June 30, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the three months ended June 30, 2023 as discussed below.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,651,156 Boe or 18,145 Boe/d, for the three months ended June 30, 2023, an increase of 290,892 Boe or 3,197 Boe/d, from 1,360,264 Boe or 14,948 Boe/d, for the three months ended June 30, 2022. The increase in production for the three months ended June 30, 2023 was primarily attributable to production associated with the Hatch Acquisition, and to a lesser extent, production associated with the MB Minerals Acquisition. 31

Table of Contents Our operators received an average of $71.91 per Bbl of oil, $2.22 per Mcf of natural gas and $24.46 per Bbl of NGL for the volumes sold during the three months ended June 30, 2023 compared to $107.96 per Bbl of oil, $6.93 per Mcf of natural gas and $46.10 per Bbl of NGL for the volumes sold during the three months ended June 30, 2022. These average prices received during the three months ended June 30, 2023 decreased 33.4% or $36.05 per Bbl of oil and 68.0% or $4.71 per Mcf of natural gas as compared to the three months ended June 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 32.4% or $35.29 per Bbl of oil and 71.2% or $5.34 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income was $2.0 million for the three months ended June 30, 2023 compared to $1.2 million for the three months ended June 30, 2022. The $0.8 million increase in lease bonus and other income was primarily related to a $0.9 million legal settlement received during the three months ended June 30, 2023.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the three months ended June 30, 2023 included $2.6 million of mark-to-market gains and $0.9 million of losses on the settlement of commodity derivative instruments compared to $8.8 million of mark-to-market gains and $15.9 million of losses on the settlement of commodity derivative instruments for the three months ended June 30, 2022. We recorded a mark-to-market gain for the three months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market gain for the three months ended June 30, 2022 as a result of the maturity of derivative contracts with lower strike pricing, offset by realized losses on the settlement of commodity derivative instruments.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended June 30, 2023 were $5.4 million, an increase of $0.4 million from $5.0 million for the three months ended June 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition, and to a lesser extent, the MB Minerals Acquisition, partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2023 was $19.7 million, an increase of $8.4 million from $11.3 million for the three months ended June 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.85 for the three months ended June 30, 2023, an increase of $3.78 per barrel from the $8.07 average depletion rate per barrel for the three months ended June 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties. 32

Table of Contents

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended June 30, 2023 were $2.9 million, a decrease of $1.2 million from $4.1 million for the three months ended June 30, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the three months ended June 30, 2023, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition.

General and Administrative Expenses

General and administrative expenses remained flat at $7.9 million for both the three months ended June 30, 2023 and 2022.

Interest Expense

Interest expense for the three months ended June 30, 2023 was $6.3 million compared to $3.3 million for the three months ended June 30, 2022. The increase in interest expense was primarily due to a 4.01% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the three months ended June 30, 2023 and also due to an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition and the MB Minerals Acquisition.

Income Tax Expense

We recorded an income tax expense of $0.9 million for the three months ended June 30, 2023. The income tax expense recorded during the three months ended June 30, 2023 was due to a change in the estimated income tax expense for the year ended December 31, 2023. We recorded an income tax expense of $1.8 million for the three months ended June 30, 2022. The income tax expense recorded during the three months ended June 30, 2022 was due to the significant increase in commodity prices which generated forecasted taxable net income for the year ended December 31, 2022.

Comparison of the Six Months Ended June 30, 2023 to the Six Months Ended June 30, 2022

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2023, our oil, natural gas and NGL revenues were $114.4 million, a decrease of $29.3 million from $143.7 million for the six months ended June 30, 2022. The decrease in oil, natural gas and NGL revenues was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production, partially offset by an increase in production volumes for the six months ended June 30, 2023 as discussed below.

Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 3,231,573 Boe or 17,783 Boe/d, for the six months ended June 30, 2023, an increase of 468,548 Boe or 3,020 Boe/d, from 2,763,025 Boe or 14,763 Boe/d, for the six months ended June 30, 2022. The increase in production for the six months ended June 30, 2023 was primarily attributable to production associated with the Hatch Acquisition, and to a lesser extent, production associated with the MB Minerals Acquisition.

Our operators received an average of $72.84 per Bbl of oil, $2.89 per Mcf of natural gas and $24.02 per Bbl of NGL for the volumes sold during the six months ended June 30, 2023 compared to $95.91 per Bbl of oil, $5.88 per Mcf of natural gas and $43.13 per Bbl of NGL for the volumes sold during the six months ended June 30, 2022. These average prices received during the six months ended June 30, 2023 decreased 24.1% or $23.07 per Bbl of oil and 50.9% or $2.99 per Mcf of natural gas as compared to the six months ended June 30, 2022. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 26.7% or $27.28 per Bbl of oil and 60.5% or $3.68 per Mcf of natural gas for the comparable periods. 33

Table of Contents

Lease Bonus and Other Income

Lease bonus and other income was $2.5 million for the six months ended June 30, 2023 compared to $1.9 million for the six months ended June 30, 2022. The increase in lease bonus and other income is primarily related to a $0.9 million legal settlement received during the six months ended June 30, 2023.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the six months ended June 30, 2023 included $15.1 million of mark-to-market gains and $4.3 million of losses on the settlement of commodity derivative instruments compared to $13.7 million of mark-to-market losses and $25.3 million of losses on the settlement of commodity derivative instruments for the six months ended June 30, 2022. We recorded a mark-to-market gain for the six months ended June 30, 2023 as a result of the maturity of derivative contracts with lower strike pricing. This gain was offset by the realized losses on the settlement of commodity derivative instruments. We recorded a mark-to-market loss for the six months ended June 30, 2022 as a result of the increase in the strip pricing of oil and natural gas from the year ended December 31, 2021 to the six months ended June 30, 2022.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the six months ended June 30, 2023 were $9.7 million, an increase of $0.7 million from $9.0 million for the six months ended June 30, 2022. The increase in production and ad valorem taxes was primarily attributable to the Hatch Acquisition, and to a lesser extent, the MB Minerals Acquisition, partially offset by the decrease in the average prices we received for oil, natural gas and NGL production.

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2023 was $37.2 million, an increase of $15.2 million from $22.0 million for the six months ended June 30, 2022. The increase in depreciation and depletion expense was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $11.46 for the six months ended June 30, 2023, an increase of $3.73 per barrel from the $7.73 average depletion rate per barrel for the six months ended June 30, 2022. The increase in the depletion rate was due to the Hatch Acquisition and the MB Minerals Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the six months ended June 30, 2023 were $5.7 million, a decrease of $1.9 million from $7.6 million for the six months ended June 30, 2022. The decrease in marketing and other deductions was primarily related to the decrease in the average prices we received for oil, natural gas and NGL production for the six months ended June 30, 2022, partially offset by marketing and other deductions associated with the Hatch Acquisition and the MB Minerals Acquisition.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2023 were $16.2 million, an increase of $1.7 million from $14.5 million for the six months ended June 30, 2022. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $1.3 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth. 34

Table of Contents

Interest Expense

Interest expense for the six months ended June 30, 2023 was $11.8 million compared to $6.2 million for the six months ended June 30, 2022. The increase in interest expense was primarily due to a 4.09% increase in the weighted average interest rate on the Partnership’s outstanding borrowings for the six months ended June 30, 2023 and also due to an increase in the overall long-term debt balance as a result of borrowings associated with the Hatch Acquisition and the MB Minerals Acquisition.

Income Tax Expense

We recorded an income tax expense of $2.3 million for the six months ended June 30, 2023. The income tax expense recorded during the six months ended June 30, 2023 was due to a change in the estimated income tax expense for the year ended December 31, 2023. We recorded an income tax expense of $2.1 million for the six months ended June 30, 2022. The income tax expense recorded during the six months ended June 30, 2022 was due to the significant increase in commodity prices which generated forecasted taxable net income for the year ended December 31, 2022.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. See “Indebtedness” below for further discussion of our secured revolving credit facility.

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the second quarter of 2023 for the repayment of $11.2 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 2023. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

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

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we issued 7,272,821 OpCo common units and an equal number of Class B units as partial consideration in connection with the Hatch Acquisition and 5,369,218 OpCo common units and an 35

Table of Contents equal number of Class B units and 557,302 common units as partial consideration in connection with the MB Minerals Acquisition. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our second quarter 2023 distributions.

Cash Flows

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


	Six Months Ended June 30,
	2023		2022
Cash Flow Data:
Net cash provided by operating activities	$	78,572,135	$	76,455,640
Net cash provided by (used in) investing activities		199,882,583		(233,953,999)
Net cash (used in) provided by financing activities		(282,702,167)		164,550,499
Net (decrease) increase in cash and cash equivalents	$	(4,247,449)	$	7,052,140

Operating Activities

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the six months ended June 30, 2023 were $78.6 million, an increase of $2.1 million compared to $76.5 million for the six months ended June 30, 2022.

Investing Activities

Cash flows provided by investing activities for the six months ended June 30, 2023 were $199.9 million compared to $234.0 million of cash flows used in investing activities for the six months ended June 30, 2022. For the six months ended June 30, 2023, cash flows provided by investing activities included $243.2 million of cash received from investment held in trust related to TGR and $0.9 million in cash received from the dissolution of TGR, partially offset by $44.2 million used primarily to fund costs associated with the MB Minerals Acquisition.

For the six months ended June 30, 2022, cash flows used in investing activities include $236.9 million of investments held in marketable securities related to TGR and $0.4 million used to fund costs associated with the acquisition of all of the equity interests in certain subsidiaries owned by Caritas Royalty Fund LLC and certain of its affiliates, partially offset by $3.5 million in cash distributions received in connection to the joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP.

Financing Activities

Cash flows used in financing activities were $282.7 million for the six months ended June 30, 2023 compared to $164.6 million of cash flows provided by financing activities for the six months June 30, 2022. Cash flows used in financing activities for the six months ended June 30, 2023 consists of $243.2 million of distributions to common unitholders of TGR, $66.7 million of distributions paid to holders common units, OpCo common units and Class B units, $22.5 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and a $4.8 million payment of loan origination costs, partially offset by $59.1 million of additional borrowings under our secured revolving credit facility and $0.3 million in Class B contributions.

Cash flows provided by financing activities for the six months ended June 30, 2022 consists of $227.6 million in proceeds from TGR IPO and $36.2 million of additional borrowings under our secured revolving credit facility, partially offset by $54.8 million of distributions paid to holders of common units, OpCo common units and Class B units, $37.2 million used to repay borrowings under our secured revolving credit facility, $3.3 million of restricted units repurchased 36

Table of Contents for tax withholding, $2.7 million used to pay underwriting commissions related to the equity offering of TGR, $0.5 million paid in connection with the redemption of Class B units, $0.3 million paid in connection with fees related to our 2021 equity offering and $0.4 million payment of loan origination costs.

Indebtedness

On June 13, 2023, we entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated our existing Credit Agreement, dated as of January 11, 2017 (as amended on July 12, 2018, December 8, 2020, June 7, 2022 and December 15, 2022).

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

As of June 30, 2023, we had outstanding borrowings of $269.6 million under the secured revolving credit facility and $130.4 million of available capacity. As of July 28, 2023, we had outstanding borrowings of $316.6 million under the secured revolving credit facility and $83.4 million of available capacity.

For additional information on our secured revolving credit facility, please read Note 9―Long-Term Debt to the unaudited interim consolidated financial statements included in this Quarterly Report.

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2023. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.

Distributions in excess of the amount taxable as dividend income will reduce a common unitholder's tax basis in its common units or produce capital gain to the extent they exceed a common unitholder's tax basis. Any reduced tax basis will increase a common unitholder's capital gain when it sells its common units. Our estimates are the result of certain non-cash expenses (principally depletion) substantially offsetting our taxable income and tax “earnings and profits.” Our estimates of the tax treatment of earnings and distributions are based upon assumptions regarding the capital structure and earnings of the Operating Company, our capital structure and the amount of the earnings of the Operating Company allocated to us. Many factors may impact these estimates, including changes in drilling and production activity, commodity prices, future acquisitions or changes in the business, economic, regulatory, legislative, competitive or political environment in which we operate. These estimates are based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service could disagree. These estimates are not fact and should not be relied upon as being necessarily indicative of future results, and no assurances can be made regarding these estimates. You are encouraged to consult with your tax advisor on this matter. 37

Table of Contents New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited interim consolidated financial statements included elsewhere in this Quarterly Report.

Critical Accounting Policies and Related Estimates

There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2022 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2022 Form 10-K. As of June 30, 2023, we did not have any off-balance sheet arrangements. See Note 8—Leases to the unaudited interim consolidated financial statements for additional information regarding our operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect commodity prices to be even more volatile in the future as a result of ongoing international supply and demand imbalances and limited international storage capacity. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.

Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.

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

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 5—Derivatives to the unaudited interim consolidated financial statements in Item 1 of this Quarterly Report for additional information regarding our commodity derivatives.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of June 30, 2023, we had four counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.

As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations. 38

Table of Contents Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of June 30,2023, we had total borrowings outstanding under our secured revolving credit facility of $269.6 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately $2.7 million annually, assuming that our indebtedness remained constant throughout the year.

Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2022 through June 30, 2023. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the 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 such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that as of June 30, 2023, our disclosure controls and procedures were effective in ensuring that all information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our General Partner’s management, including its principal executive officer and principal financial officer, in a manner that allows timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 15—Commitments and Contingencies to the unaudited interim consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.

Item 1A. Risk Factors

In addition to the risks and uncertainties discussed in this Quarterly Report, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2022 Form 10-K. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of the current pandemic and the volatility in the worldwide economy and oil and gas industry may make it more difficult to 39

Table of Contents identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 5. Other Information

During the period covered by this report, none of the Partnership’s directors or executive officers has adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement (each as defined in Item 408 of Regulation S-K under the Securities Exchange Act of 1934, as amended).

Item 6. Exhibits

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	—	Fourth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of May 18, 2022 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed May 18, 2022)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	Second Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of May 18, 2022 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on May 18, 2022)
3.5	—	First Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 23, 2018 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 25, 2018)
4.1	—	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)
10.1	—	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)
10.2	—	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)
10.3	—	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)
10.4	—	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)
10.5	—	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)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934

Table of Contents

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
101.INS*	—	Inline XBRL Instance Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
*	—filed herewith
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**	—furnished herewith
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Table of Contents 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: August 2, 2023	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer


Date: August 2, 2023	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert D. Ravnaas, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Kimbell Royalty Partners, LP;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
---	---
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
---	---
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
---	---
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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---	---	---


Date: August 2, 2023		/s/ Robert D. Ravnaas
		Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br><br>(Principal Executive Officer)

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, R. Davis Ravnaas, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Kimbell Royalty Partners, LP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
---	---
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
---	---
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
---	---
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
---	---

---	---

Date: August 2, 2023	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br>(Principal Financial Officer)

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended June 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
---	---

---	---



Date: August 2, 2023	/s/ Robert D. Ravnaas
	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP<br>(Principal Executive Officer)

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended June 30, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
---	---

---	---



Date: August 2, 2023	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP
	(Principal Financial Officer)