Kimbell Royalty Partners (KRP) 10-Q 2024 Q2 Quarterly report

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, 2024 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
(State or other jurisdiction of
incorporation or organization) 1311
(Primary Standard Industrial
Classification Code Number) 47-5505475
(I.R.S. Employer
Identification No.)

777 Taylor Street, Suite 810

Fort Worth, Texas 76102

(817) 945-9700

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

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

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 26, 2024, the registrant had outstanding 80,969,651 common units representing limited partner interests and 14,524,120 Class B units representing limited partner interests.

KIMBELL ROYALTY PARTNERS, LP

FORM 10-Q

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
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	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	35
Item 4. Controls and Procedures	36
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	36
Item 1A. Risk Factors	36
Item 5. Other Information	37
Item 6. Exhibits	37
Signatures	38

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PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,		December 31,
	2024		2023
ASSETS
Current assets
Cash and cash equivalents	$	30,945,157	$	30,992,670
Oil, natural gas and NGL receivables		53,218,203		59,020,471
Derivative assets		2,378,353		11,427,735
Accounts receivable and other current assets		2,389,179		1,699,536
Total current assets		88,930,892		103,140,412
Property and equipment, net		444,335		589,895
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($155,984,953 and $222,712,844 excluded from depletion at June 30, 2024 and December 31, 2023, respectively)		2,048,711,692		2,048,690,088
Less: accumulated depreciation, depletion and impairment		(903,995,713)		(827,033,944)
Total oil and natural gas properties, net		1,144,715,979		1,221,656,144
Right-of-use assets, net		2,016,364		2,189,243
Derivative assets		412,015		2,888,051
Loan origination costs, net		6,281,710		7,325,471
Total assets	$	1,242,801,295	$	1,337,789,216
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	6,501,900	$	6,594,736
Other current liabilities		8,976,730		6,173,314
Derivative liabilities		178,879		208,710
Total current liabilities		15,657,509		12,976,760
Operating lease liabilities, excluding current portion		1,701,904		1,887,693
Derivative liabilities		1,098,534		60,094
Long-term debt		265,759,776		294,200,000
Other liabilities		135,420		197,917
Total liabilities		284,353,143		309,322,464
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units issued and outstanding as of June 30, 2024 and December 31, 2023)		315,212,857		314,423,572
Kimbell Royalty Partners, LP unitholders' equity:
Common units (80,969,651 units and 73,851,458 units issued and outstanding as of June 30, 2024 and December 31, 2023, respectively)		722,151,755		670,530,748
Class B units (14,524,120 units and 20,847,295 units issued and outstanding as of June 30, 2024 and December 31, 2023, respectively)		726,206		1,042,365
Total Kimbell Royalty Partners, LP unitholders' equity		722,877,961		671,573,113
Non-controlling (deficit) interest in OpCo		(79,642,666)		42,470,067
Total unitholders' equity		643,235,295		714,043,180
Total liabilities, mezzanine equity and unitholders' equity	$	1,242,801,295	$	1,337,789,216

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

1

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenue
Oil, natural gas and NGL revenues	$	76,959,173	$	56,981,614	$	164,458,682	$	114,398,373
Lease bonus and other income		659,980		2,041,189		1,098,776		2,478,526
(Loss) gain on commodity derivative instruments, net		(1,046,261)		1,729,459		(6,750,622)		10,791,835
Total revenues		76,572,892		60,752,262		158,806,836		127,668,734
Costs and expenses
Production and ad valorem taxes		5,576,798		5,404,955		12,108,699		9,682,159
Depreciation and depletion expense		33,023,934		19,656,855		71,190,740		37,220,503
Impairment of oil and natural gas properties		—		—		5,963,575		—
Marketing and other deductions		3,827,646		2,907,459		8,390,590		5,669,498
General and administrative expense		10,252,123		7,925,159		19,700,004		16,203,426
Consolidated variable interest entities related:
General and administrative expense		—		219,473		—		927,699
Total costs and expenses		52,680,501		36,113,901		117,353,608		69,703,285
Operating income		23,892,391		24,638,361		41,453,228		57,965,449
Other (expense) income
Interest expense		(6,946,580)		(6,341,118)		(14,247,910)		(11,804,522)
Loss on extinguishment of debt		—		(480,244)		—		(480,244)
Other expense		—		(180,765)		—		(180,765)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		1,069,854		—		3,508,691
Net income before income taxes		16,945,811		18,706,088		27,205,318		49,008,609
Income tax expense		1,759,282		909,057		2,681,850		2,312,040
Net income		15,186,529		17,797,031		24,523,468		46,696,569
Distribution and accretion on Series A preferred units		(5,243,004)		—		(10,499,291)		—
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(1,512,360)		(4,297,442)		(2,403,209)		(9,860,860)
Distribution on Class B units		(20,847)		(31,601)		(41,694)		(47,085)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	8,410,318	$	13,467,988	$	11,579,274	$	36,788,624
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.11	$	0.24	$	0.16	$	0.61
Diluted	$	0.11	$	0.23	$	0.16	$	0.59
Weighted average number of common units outstanding
Basic		74,834,777		63,274,492		73,473,416		62,910,053
Diluted		116,593,560		82,959,981		116,395,698		81,263,101

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

2

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2024
									Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest (Deficit) in OpCo		Total
Balance at January 1, 2024		73,851,458	$	670,530,748		20,847,295	$	1,042,365	$	42,470,067	$	714,043,180
Restricted units repurchased for tax withholding		(292,484)		(4,914,149)		—		—		—		(4,914,149)
Unit-based compensation		1,087,502		3,684,080		—		—		—		3,684,080
Distributions to unitholders		—		(32,097,985)		—		—		(9,462,525)		(41,560,510)
Distribution and accretion on Series A preferred units		—		(4,108,784)		—		—		(1,147,503)		(5,256,287)
Distribution on Class B units		—		(20,847)		—		—		—		(20,847)
Net income		—		7,298,587		—		—		2,038,352		9,336,939
Balance at March 31, 2024		74,646,476		640,371,650		20,847,295		1,042,365		33,898,391		675,312,406
Conversion of Class B units to common units		6,323,175		104,838,242		(6,323,175)		(316,159)		(104,838,242)		(316,159)
Unit-based compensation		—		5,108,318		—		—		—		5,108,318
Distributions to unitholders		—		(36,576,773)		—		—		(10,215,175)		(46,791,948)
Distribution and accretion on Series A preferred units		—		(4,445,570)		—		—		(797,434)		(5,243,004)
Distribution on Class B units		—		(20,847)		—		—		—		(20,847)
Net income		—		12,876,735		—		—		2,309,794		15,186,529
Balance at June 30, 2024		80,969,651	$	722,151,755		14,524,120	$	726,206	$	(79,642,666)	$	643,235,295

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KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)

	Six Months Ended June 30, 2023
									Non-controlling
	Common Units		Amount		Class B Units		Amount		(Deficit) 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

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

4

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2024		2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	24,523,468	$	46,696,569
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		71,190,740		37,220,503
Impairment of oil and natural gas properties		5,963,575		—
Amortization of right-of-use assets		172,879		167,658
Amortization of loan origination costs		1,060,260		1,008,830
Loss on extinguishment of debt		—		480,244
Unit-based compensation		8,792,398		6,459,740
Loss (gain) on derivative instruments, net of settlements		12,534,027		(15,100,314)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		5,802,268		1,987,323
Accounts receivable and other current assets		(689,643)		427,105
Accounts payable		(39,409)		159,557
Other current liabilities		2,803,415		3,431,295
Operating lease liabilities		(185,789)		(170,331)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		(3,508,691)
Other assets and liabilities		—		(687,353)
Net cash provided by operating activities		131,928,189		78,572,135
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(109,484)		(72,123)
Purchase of oil and natural gas properties		(21,605)		(44,175,131)
Proceeds from trust of variable interest entity		—		930,850
Consolidated variable interest entities related:
Cash paid for transaction costs		—		31,553
Cash received from investments held in trust		—		243,167,434
Net cash (used in) provided by investing activities		(131,089)		199,882,583
CASH FLOWS FROM FINANCING ACTIVITIES
Contributions from Class B unitholders		—		268,461
Redemption of Class B contributions on converted units		(316,159)		—
Distribution to common unitholders		(68,674,758)		(53,908,777)
Distribution to OpCo unitholders		(19,677,700)		(12,786,091)
Distribution on Series A preferred units		(9,763,430)		—
Distribution on Class B units		(41,694)		(47,085)
Borrowings on long-term debt		4,959,776		59,084,089
Repayments on long-term debt		(33,400,000)		(22,500,000)
Payment of loan origination costs		(16,499)		(4,793,368)
Restricted units repurchased for tax withholding		(4,914,149)		(4,851,962)
Consolidated variable interest entities related:
Redemption of Kimbell Tiger Acquisition Corporation equity units		—		(243,167,434)
Net cash used in financing activities		(131,844,613)		(282,702,167)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(47,513)		(4,247,449)
CASH AND CASH EQUIVALENTS, beginning of period		30,992,670		25,026,568
CASH AND CASH EQUIVALENTS, end of period	$	30,945,157	$	20,779,119

5

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

(Unaudited)

	Six Months Ended June 30,
	2024		2023
Supplemental cash flow information:
Cash paid for interest	$	13,325,254	$	10,963,296
Non-cash investing and financing activities:
Units issued in exchange for oil and natural gas properties	$	—	$	92,038,856
Noncash deemed distribution to Series A preferred units	$	789,285	$	—
Distribution on Series A preferred units in accounts payable	$	4,848,361	$	—
Recognition of tenant improvement asset	$	62,500	$	62,500
Consolidated variable interest entities related:
Reduction of deferred underwriting commission associated with redemption of Kimbell Tiger Acquisition Corporation equity units	$	—	$	(8,050,000)

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

6

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

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION

Organization

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

Basis of Presentation

The 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 United States 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, 2023 (the “2023 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 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.

7

Global Conflicts

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. These conflicts and the sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, the Partnership has not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, the Partnership will continue to monitor for events that could materially impact them.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 2023 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, 2024.

Consolidation

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

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

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

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

Investments Held in Trust by Consolidated Variable Interest Entities

Investments held in trust represented funds raised by Kimbell Tiger Acquisition Corporation (“TGR”), a consolidated special purpose acquisition company, through TGR’s initial public offering. These funds were held in an

8

actively-traded money market fund, which invested in U.S. Treasury securities. Investments held in trust were classified as trading securities and were 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. Interest earned on marketable securities in trust account was $1.1 million and $3.5 million for the three and six months ended June 30, 2023, respectively. As discussed further in Note 4, the Partnership completed the dissolution and deconsolidation of TGR (along with related entities) on June 30, 2023.

Recently Issued Accounting Pronouncements

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

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. 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.

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,
	2024		2023		2024		2023
Oil revenue	$	53,405,154	$	39,809,883	$	115,033,027	$	72,810,169
Natural gas revenue		14,070,601		11,539,982		28,625,174		31,188,764
NGL revenue		9,483,418		5,631,749		20,800,481		10,399,440
Total Oil, natural gas and NGL revenues	$	76,959,173	$	56,981,614	$	164,458,682	$	114,398,373

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NOTE 4—ACQUISITIONS AND SPECIAL PURPOSE ACQUISITION COMPANY

Acquisitions

On September 13, 2023, the Partnership completed the acquisition of all issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in a cash transaction valued at approximately $455.0 million. The Partnership funded the cash transaction with borrowings under its secured revolving credit facility and net proceeds from the Preferred Unit Transaction (as defined in Note 10—Preferred Units). The adjusted purchase price of the LongPoint Acquisition includes the total cash consideration of $455.0 million, transactional costs of $7.4 million and less $16.6 million of post-effective net oil, natural gas and NGL revenues earned prior to the closing date. The LongPoint Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $198.2 million to proved properties and $247.6 million to unevaluated properties.

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

Special Purpose Acquisition Company

On February 8, 2022, the Partnership’s previously dissolved special purpose acquisition company and subsidiary, TGR, consummated its $230 million initial public offering. Under the terms of TGR’s governing documents, TGR had until May 8, 2023 to complete a business combination, subject to an option to extend such deadline.

On May 22, 2023, as a result of TGR’s inability to consummate an initial business combination on or prior to May 8, 2023, and pursuant to the terms of its organizational documents, TGR redeemed all of its outstanding shares of Class A common stock of TGR, par value $0.0001 per share (the “Class A common stock”), included as part of the units issued in its initial public offering. The Class A common stock was redeemed on June 22, 2023 and the Partnership completed the dissolution and deconsolidation of TGR (along with related entities) on June 30, 2023 in accordance with the terms of its organizational documents.

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, 2024, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last scheduled trading day 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

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current period and are presented on a net basis within revenue in the accompanying unaudited interim consolidated statements of operations.

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,
	2024		2023		2024		2023
Beginning fair value of derivative instruments	$	5,309,268	$	175,525	$	14,046,982	$	(12,324,076)
(Loss) gain on commodity derivative instruments, net		(1,046,261)		1,729,459		(6,750,622)		10,791,835
Net cash (received) paid on settlements of derivative instruments		(2,750,052)		871,254		(5,783,405)		4,308,479
Ending fair value of derivative instruments	$	1,512,955	$	2,776,238	$	1,512,955	$	2,776,238

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	2024		2023
Assets:
Current assets	Derivative assets	$	2,378,353	$	11,427,735
Long-term assets	Derivative assets		412,015		2,888,051
Liabilities:
Current liabilities	Derivative liabilities		(178,879)		(208,710)
Long-term liabilities	Derivative liabilities		(1,098,534)		(60,094)
		$	1,512,955	$	14,046,982

As of June 30, 2024, 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 2024 - December 2024	284,096	$	75.74	$	69.30	$	80.80
January 2025 - December 2025	563,526	$	70.36	$	64.35	$	77.01
January 2026 - June 2026	295,392	$	70.58	$	70.38	$	70.78

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
July 2024 - December 2024	2,661,652	$	4.08	$	3.27	$	4.48
January 2025 - December 2025	5,153,291	$	3.81	$	3.50	$	4.37
January 2026 - June 2026	2,606,400	$	3.70	$	3.33	$	4.07

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, 2024 and December 31, 2023 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.

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and six months ended June 30, 2024 and 2023.

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, 2024
Assets
Commodity derivative contracts	$	—	$	2,790,368	$	—	$	—	$	2,790,368
Liabilities
Commodity derivative contracts	$	—	$	(1,277,413)	$	—	$	—	$	(1,277,413)
December 31, 2023
Assets
Commodity derivative contracts	$	—	$	14,315,786	$	—	$	—	$	14,315,786
Liabilities
Commodity derivative contracts	$	—	$	(268,804)	$	—	$	—	$	(268,804)

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	June 30,		December 31,
	2024		2023
Oil and natural gas properties
Proved properties	$	1,892,726,739	$	1,825,977,244
Unevaluated properties		155,984,953		222,712,844
Less: accumulated depreciation, depletion and impairment		(903,995,713)		(827,033,944)
Total oil and natural gas properties	$	1,144,715,979	$	1,221,656,144

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

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

As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas properties of $6.0 million during the six months ended June 30, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas. The Partnership did not record an impairment on its oil and natural gas properties for the three months ended June 30, 2024 or three and six months ended June 30, 2023.

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

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, 2024 is 4.89 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, 2024.

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, 2024 and 2023. The total operating lease expense recorded for both the three months June 30, 2024 and 2023 was $0.1 million and $0.3 million for both the six months ended June 30, 2024 and 2023.

Future minimum lease commitments as of June 30, 2024 were as follows:

	Total		2024		2025		2026		2027		2028		Thereafter
Operating leases	$	2,469,315	$	245,367	$	497,033	$	507,648	$	511,917	$	496,785	$	210,565
Less: Imputed Interest		(403,245)
Total	$	2,066,070

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 $750.0 million with an initial borrowing base of $400.0 million and an initial aggregate elected commitments amount of up to $400.0 million, including a sub-facility for the issuance of letters of credit of up to $10.0 million and (ii) an extension of the maturity date of the A&R Credit Agreement to June 7, 2027. In connection with the A&R Credit Agreement, the Partnership recorded a loss on extinguishment of debt of $0.5 million as a result of writing

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off all unamortized loan origination costs associated with the lenders to the Partnership’s existing credit agreement that did not participate in the A&R Credit Agreement.

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

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

The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (i) 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 (ii) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization.

The secured revolving credit facility is guaranteed by certain of the Partnership’s material subsidiaries and is collateralized by substantially all assets, including the oil and natural gas properties of such subsidiaries, including mortgages on at least 75% of the PV-9 of the proved reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders, with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. In connection with the May 1, 2024 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $550.0 million.

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

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

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

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

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

During the six months ended June 30, 2024, the Partnership borrowed an additional $5.0 million under the secured revolving credit facility and repaid approximately $33.4 million of the outstanding borrowings. As of June 30, 2024, the Partnership’s outstanding balance was $265.8 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2024.

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As of June 30, 2024, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.00% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.00%. For the three and six months ended June 30, 2024, the weighted average interest rate on the Partnership’s outstanding borrowings was 8.59% and 8.65%, respectively.

NOTE 10—PREFERRED UNITS

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

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

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

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

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (i) the number of outstanding Series A preferred units multiplied by (ii) the greatest of (a) an amount (together with all prior distributions made in respect of such

15

Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (b) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (c) the Series A issue price plus accrued and unpaid distributions.

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

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

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

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of June 30, 2024, the Partnership had a total of 80,969,651 common units issued and outstanding and 14,524,120 Class B units outstanding.

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

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

	Common Units
Balance at December 31, 2023	73,851,458
Common units issued under the A&R LTIP (1)	1,087,502
Restricted units repurchased for tax withholding	(292,484)
Conversion of Class B units to common units	6,323,175
Balance at June 30, 2024	80,969,651

(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 19, 2024.

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 2024	$	0.49	May 2, 2024	May 13, 2024	May 20, 2024
Q2 2024	$	0.42	August 1, 2024	August 12, 2024	August 19, 2024
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

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, subsequent to distributions on the Series A preferred units, but prior to distributions on the common units and OpCo common units.

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Holders of the Class B units are entitled to one vote per share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

NOTE 12—EARNINGS PER COMMON UNIT

Basic earnings per common unit is calculated by dividing net income attributable to common units by the weighted-average number of common units outstanding during the period. Diluted net income per common unit gives effect, when applicable, to unvested restricted units granted under the Partnership’s A&R LTIP (as defined in Note 13) for its employees and directors and potential conversion of Series A preferred units and Class B units. The Partnership uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding Series A preferred units and Class B units (and corresponding units of Kimbell Royalty Partners, LP), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding restricted units granted under the Partnership’s A&R LTIP. The Partnership does not use the two-class method because the Class B units and the unvested restricted units granted under the Partnership’s A&R LTIP are nonparticipating securities.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net income attributable to common units of Kimbell Royalty Partners, LP	$	8,410,318	$	13,467,988	$	11,579,274	$	36,788,624
Net adjustment to accretion of redeemable non-controlling interest in Kimbell Tiger Acquisition Corporation and write-off of deferred underwriting commissions		—		1,572,737		—		1,572,737
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		8,410,318		15,040,725		11,579,274		38,361,361
Distribution and accretion on Series A preferred units		5,243,004		—		10,499,291		—
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		1,533,207		4,329,043		2,444,903		9,907,945
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	15,186,529	$	19,369,768	$	24,523,468	$	48,269,306
Weighted average number of common units outstanding:
Basic		74,834,777		63,274,492		73,473,416		62,910,053
Effect of dilutive securities:
Series A preferred units		21,566,025		—		21,566,025		—
Class B units		18,623,761		18,139,508		19,735,528		16,819,289
Restricted units		1,568,997		1,545,981		1,620,729		1,533,759
Diluted		116,593,560		82,959,981		116,395,698		81,263,101
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.11	$	0.24	$	0.16	$	0.61
Diluted	$	0.11	$	0.23	$	0.16	$	0.59

The calculation of diluted net income per share for the three and six months ended June 30, 2024 includes the conversion of all Series A preferred units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net income per

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share for the three and six months ended June 30, 2023 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 13—UNIT-BASED COMPENSATION

On May 1, 2024, the Board of Directors approved and adopted the first amendment to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as so amended, the “A&R LTIP”), which increased the number of common units available to be awarded under the A&R LTIP by 4,684,622 common units, which increased the total number of common units available to be awarded under the A&R LTIP, after taking into account previously awarded common units, to 6,765,012 common units. The Partnership’s A&R LTIP authorizes grants to its employees and directors. 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.

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 and directors 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, 2023	1,951,430	$	14.763	1.525 years
Awarded	1,087,502		15.710	—
Vested	(1,046,731)		13.913	—
Unvested at June 30, 2024 (1)	1,992,201	$	15.727	2.047 years

(1) As of June 30, 2024, there was $31.3 million of unrecognized compensation expense associated with unvested restricted units based on the weighted average grant date fair value per unit of $15.727.

NOTE 14—INCOME TAXES

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

The Partnership records income taxes for interim periods based on an estimated annual effective tax rate. The estimated annual effective rate is recomputed on a quarterly basis and may fluctuate due to changes in forecasted annual operating income, positive or negative changes to the valuation allowance for net deferred tax assets, changes in forecasted annual income (loss) attributable to non-controlling interest and changes to actual or forecasted permanent book to tax differences. The Partnership’s effective tax rate for the three months ended June 30, 2024 was 9.9%, compared to 4.7% for the three months ended June 30, 2023. The Partnership recorded an income tax expense of $1.8 million and $0.9 million for the three months ended June 30, 2024 and 2023, respectively, and an income tax expense of $2.7 million and $2.3 million for the six months ended June 30, 2024 and 2023, respectively.

NOTE 15—RELATED PARTY TRANSACTIONS

The Partnership currently has a management services agreement with Kimbell Operating, which has a separate services agreement with K3 Royalties, LLC (“K3 Royalties”). Pursuant to the K3 Royalties service agreement, K3 Royalties 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

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and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and K3 Royalties under their respective services agreements will reduce the amount of cash available for distribution on common units to the Partnership’s unitholders. The Partnership previously had a services agreement with BJF Royalties, LLC (“BJF Royalties”), which was terminated upon the death of Ben Fortson on May 19, 2024.

During the three and six months ended June 30, 2024, no monthly services fee was paid to BJF Royalties. During the three and six months ended June 30, 2024, the Partnership made payments to K3 Royalties in the amount of $30,000 and $60,000, respectively.

The Partnership received $32,101 and $59,479 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three and six months ended June 30, 2024.

NOTE 16—COMMITMENTS AND CONTINGENCIES

During the normal course of business, the Partnership may experience situations where disagreements occur relating to the ownership of certain mineral or overriding royalty interest acreage. Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity as of June 30, 2024.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2024 in the preparation of its unaudited interim consolidated financial statements.

Distributions

On August 1, 2024, the Board of Directors declared a quarterly cash distribution of $0.42 per common unit and OpCo common unit for the quarter ended June 30, 2024. The Partnership intends to pay this distribution on August 19, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on August 12, 2024.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.8 million for the quarter ended June 30, 2024. The Partnership intends to pay the distribution subsequent to August 1, 2024, and prior to the distribution on the common units and OpCo common units.

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

The following discussion and analysis of financial condition 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, 2023 (the “2023 Form 10-K”).

Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” “our Partnership,” “we” “our,” or “us” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to our subsidiary Kimbell Royalty Operating, LLC. References to “our General Partner” refer to Kimbell Royalty GP, LLC. References to “our Sponsors” refer to affiliates of our founders, 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 our Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to us.

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 outcome of the U.S. presidential election and the energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies;

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

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

● 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 to the operators of our properties;

● 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 2023 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, 2024, we owned mineral and royalty interests in approximately 12.2 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 54% of our aggregate acres

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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, 2024, 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 held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 129,000 gross wells, including over 50,000 wells in the Permian Basin.

The following table summarizes 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, 2024:

			Average Daily
			Production
Basin or Producing Region	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	Well Count
Permian Basin	3,336,729	26,928	9,211	50,604
Mid‑Continent	5,868,926	48,832	4,318	20,898
Terryville/Cotton Valley/Haynesville	1,428,907	7,919	4,387	16,297
Appalachian Basin	741,354	23,203	1,708	3,929
Bakken/Williston Basin	1,640,077	6,138	931	5,358
Eagle Ford	624,148	6,730	1,574	4,277
DJ Basin/Rockies/Niobrara	74,152	1,036	836	12,556
Other	3,232,560	36,693	1,145	15,444
Total	16,946,853	157,479	24,110	129,363

(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 2023 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, 2024:

Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	417	416	1.93	2.44
Mid‑Continent	130	64	0.89	0.70
Terryville/Cotton Valley/Haynesville	53	20	0.33	0.38
Appalachian Basin	5	3	0.01	0.01
Bakken/Williston Basin	55	102	0.10	0.23
Eagle Ford	98	58	0.50	0.34
DJ Basin/Rockies/Niobrara	4	9	0.06	0.04
Total	762	672	3.82	4.14

(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.

Recent Developments

Quarterly Distributions

On August 1, 2024, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.42 per common unit representing limited partner interests in the Partnership (“common unit”) and common unit of the Operating Company (“OpCo common unit”) for the quarter ended June 30, 2024. We intend to pay the distributions on August 19, 2024 to common unitholders and OpCo common unitholders of record as of the close of business on August 12, 2024.

We will pay a cash distribution on the Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) of approximately $4.8 million for the quarter ended June 30, 2024. We intend to pay the distribution subsequent to August 1, 2024 and prior to the distribution on the common units and OpCo common units.

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Business Environment

Global Conflicts

In February 2022, Russia invaded Ukraine and is still engaged in active armed conflict against the country. In October 2023, armed active conflict escalated in the Middle East between Israel and Hamas and is still active. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. These conflicts and the applicable sanctions imposed in response have led to regional instability and caused dramatic fluctuations in global financial markets and have increased the level of global economic and political uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has increased volatility in commodity prices. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us.

Commodity Prices and Demand

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

	Six Months Ended June 30, 2024				Six Months Ended June 30, 2023
	High		Low		High		Low
Oil ($/Bbl)	$	87.69	$	70.62	$	83.26	$	66.61
Natural gas ($/MMBtu)	$	13.20	$	1.25	$	3.78	$	1.74

On July 22, 2024, the West Texas Intermediate posted price for crude oil was $81.25 per Bbl and the Henry Hub spot market price of natural gas was $2.19 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,
	2024		2023		2024		2023
Oil ($/Bbl)	$	81.81	$	73.54	$	79.69	$	74.73
Natural gas ($/MMBtu)	$	2.07	$	2.16	$	2.11	$	2.40

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 14.2% to 560 active land rigs at June 30, 2024 compared to 653 active land rigs at June 30, 2023. The 560 active land rigs at June 30, 2024 decreased by 6.8% compared to 601 active land rigs at March 31, 2024. While the average daily prices for oil and natural gas at June 30, 2024 remained relatively flat when compared to June 30, 2023, higher labor and equipment costs, as a result of inflation, discourages any substantial uptake in the market.

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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	2024	2023
Permian Basin	47	50
Mid‑Continent	20	12
Terryville/Cotton Valley/Haynesville	9	17
Appalachian Basin	1	—
Bakken/Williston Basin	7	4
Eagle Ford	6	5
DJ Basin/Rockies/Niobrara	1	1
Other	—	1
Total	91	90

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,
	2024		2023		2024		2023
Revenue
Oil revenue	70	%	70	%	70	%	64	%
Natural gas revenue	18	%	20	%	17	%	27	%
NGL revenue	12	%	10	%	13	%	9	%
	100	%	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through June 2026, 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.

Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution on Common Units

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

We define Adjusted EBITDA as net income (loss), net of depreciation and depletion expense, interest expense, income taxes, impairment of oil and natural gas properties, non-cash unit based compensation, loss on extinguishment of debt, unrealized gains and losses on derivative instruments 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

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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.

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,
	2024		2023		2024		2023
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	15,186,529	$	17,797,031	$	24,523,468	$	46,696,569
Depreciation and depletion expense		33,023,934		19,656,855		71,190,740		37,220,503
Interest expense		6,946,580		6,341,118		14,247,910		11,804,522
Income tax expense		1,759,282		909,057		2,681,850		2,312,040
EBITDA		56,916,325		44,704,061		112,643,968		98,033,634
Impairment of oil and natural gas properties		—		—		5,963,575		—
Unit-based compensation		5,108,318		3,289,740		8,792,398		6,459,740
Loss on extinguishment of debt		—		480,244		—		480,244
Loss (gain) on derivative instruments, net of settlements		3,796,313		(2,600,713)		12,534,027		(15,100,314)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		(1,069,854)		—		(3,508,691)
General and administrative expense		—		219,473		—		927,699
Consolidated Adjusted EBITDA		65,820,956		45,022,951		139,933,968		87,292,312
Adjusted EBITDA attributable to non-controlling interest		(10,011,035)		(10,871,674)		(26,190,685)		(19,008,901)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		55,809,921		34,151,277		113,743,283		68,283,411
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		5,620,423		4,442,318		10,855,128		8,566,027
Cash distribution on Series A preferred units		4,110,950		—		7,911,246		—
Cash income tax refund		—		—		—		(639,325)
Distribution on Class B units		20,847		31,601		41,694		47,085
Cash available for distribution on common units	$	46,057,701	$	29,677,358	$	94,935,215	$	60,309,624

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	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
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	$	62,882,573	$	31,518,529	$	131,928,189	$	78,572,135
Interest expense		6,946,580		6,341,118		14,247,910		11,804,522
Income tax expense		1,759,282		909,057		2,681,850		2,312,040
Impairment of oil and natural gas properties		—		—		(5,963,575)		—
Amortization of right-of-use assets		(86,555)		(84,501)		(172,879)		(167,658)
Amortization of loan origination costs		(530,130)		(492,732)		(1,060,260)		(1,008,830)
Loss on extinguishment of debt		—		(480,244)		—		(480,244)
Unit-based compensation		(5,108,318)		(3,289,740)		(8,792,398)		(6,459,740)
(Loss) gain on derivative instruments, net of settlements		(3,796,313)		2,600,713		(12,534,027)		15,100,314
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(1,486,074)		9,070,691		(5,802,268)		(1,987,323)
Accounts receivable and other current assets		(459,887)		86,707		689,643		(427,105)
Accounts payable		352,173		(450,078)		39,409		(159,557)
Other current liabilities		(3,651,026)		(3,175,769)		(2,803,415)		(3,431,295)
Operating lease liabilities		94,020		85,313		185,789		170,331
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		1,069,854		—		3,508,691
Other assets and liabilities		—		995,143		—		687,353
EBITDA		56,916,325		44,704,061		112,643,968		98,033,634
Add:
Impairment of oil and natural gas properties		—		—		5,963,575		—
Unit-based compensation		5,108,318		3,289,740		8,792,398		6,459,740
Loss on extinguishment of debt		—		480,244		—		480,244
Loss (gain) on derivative instruments, net of settlements		3,796,313		(2,600,713)		12,534,027		(15,100,314)
Consolidated variable interest entities related:
Interest earned on marketable securities in Trust Account		—		(1,069,854)		—		(3,508,691)
General and administrative expense		—		219,473		—		927,699
Consolidated Adjusted EBITDA		65,820,956		45,022,951		139,933,968		87,292,312
Adjusted EBITDA attributable to non-controlling interest		(10,011,035)		(10,871,674)		(26,190,685)		(19,008,901)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		55,809,921		34,151,277		113,743,283		68,283,411
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		5,620,423		4,442,318		10,855,128		8,566,027
Cash distribution on Series A preferred units		4,110,950		—		7,911,246		—
Cash income tax refund		—		—		—		(639,325)
Distribution on Class B units		20,847		31,601		41,694		47,085
Cash available for distribution on common units	$	46,057,701	$	29,677,358	$	94,935,215	$	60,309,624

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

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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, 2024 and 2023 include the acquisition of certain mineral and royalty assets held by MB Minerals, L.P. and certain of its affiliates (the “MB Minerals Acquisition”) in May 2023 and the acquisition of all of the issued and outstanding membership interests of Cherry Creek Minerals LLC pursuant to a securities purchase agreement with LongPoint Minerals II, LLC (the “LongPoint Acquisition”) in September 2023.

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

As a result of our full cost ceiling analysis, we recorded an impairment on our oil and natural gas properties of $6.0 million during the six months ended June 30, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the three months ended June 30, 2024 or three and six months ended June 30, 2023.

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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,
	2024		2023		2024		2023
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	76,959,173	$	56,981,614	$	164,458,682	$	114,398,373
Lease bonus and other income		659,980		2,041,189		1,098,776		2,478,526
(Loss) gain on commodity derivative instruments, net		(1,046,261)		1,729,459		(6,750,622)		10,791,835
Total revenues		76,572,892		60,752,262		158,806,836		127,668,734
Costs and expenses
Production and ad valorem taxes		5,576,798		5,404,955		12,108,699		9,682,159
Depreciation and depletion expense		33,023,934		19,656,855		71,190,740		37,220,503
Impairment of oil and natural gas properties		—		—		5,963,575		—
Marketing and other deductions		3,827,646		2,907,459		8,390,590		5,669,498
General and administrative expense		10,252,123		7,925,159		19,700,004		16,203,426
Consolidated variable interest entities related:
General and administrative expense		—		219,473		—		927,699
Total costs and expenses		52,680,501		36,113,901		117,353,608		69,703,285
Operating income		23,892,391		24,638,361		41,453,228		57,965,449
Other (expense) income
Interest expense		(6,946,580)		(6,341,118)		(14,247,910)		(11,804,522)
Loss on extinguishment of debt		—		(480,244)		—		(480,244)
Other expense		—		(180,765)		—		(180,765)
Consolidated variable interest entities related:
Interest earned on marketable securities in trust account		—		1,069,854		—		3,508,691
Net income before income taxes		16,945,811		18,706,088		27,205,318		49,008,609
Income tax expense		1,759,282		909,057		2,681,850		2,312,040
Net income		15,186,529		17,797,031		24,523,468		46,696,569
Distribution and accretion on Series A preferred units		(5,243,004)		—		(10,499,291)		—
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(1,512,360)		(4,297,442)		(2,403,209)		(9,860,860)
Distribution on Class B units		(20,847)		(31,601)		(41,694)		(47,085)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	8,410,318	$	13,467,988	$	11,579,274	$	36,788,624
Production Data:
Oil (Bbls)		691,819		553,588		1,496,408		999,601
Natural gas (Mcf)		6,714,323		5,203,964		14,127,392		10,794,157
Natural gas liquids (Bbls)		383,092		230,241		841,339		432,946
Combined volumes (Boe) (6:1)		2,193,965		1,651,156		4,692,312		3,231,573

Comparison of the Three Months Ended June 30, 2024 to the Three Months Ended June 30, 2023

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2024, our oil, natural gas and NGL revenues were $77.0 million, an increase of $20.0 million from $57.0 million for the three months ended June 30, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the three months ended June 30, 2024 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 2,193,965 Boe or 24,110 Boe/d, for the three months ended June 30, 2024,

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an increase of 542,809 Boe or 5,965 Boe/d, from 1,651,156 Boe or 18,145 Boe/d, for the three months ended June 30, 2023. The increase in production for the three months ended June 30, 2024 was primarily attributable to production associated with the LongPoint Acquisition.

Our operators received an average of $77.20 per Bbl of oil, $2.10 per Mcf of natural gas and $24.75 per Bbl of NGL for the volumes sold during the three months ended June 30, 2024 compared to $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. These average prices received during the three months ended June 30, 2024 increased 7.4% or $5.29 per Bbl of oil and decreased 5.4% or $0.12 per Mcf of natural gas as compared to the three months ended June 30, 2023. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 11.2% or $8.27 per Bbl of oil and decrease of 4.2% or $0.09 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income for the three months ended June 30, 2024 was $0.7 million, a decrease of $1.3 million from $2.0 million for the three months ended June 30, 2023. The decrease 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.

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended June 30, 2024 included $3.8 million of mark-to-market losses and $2.8 million of gains on the settlement of commodity derivative instruments compared to $2.6 million of mark-to-market gains and $0.9 million of losses on the settlement of commodity derivative instruments for the three months ended June 30, 2023. We recorded a mark-to-market loss for the three months ended June 30, 2024 as a result of the increase in oil and natural gas strip pricing from the three months ended March 31, 2024. 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, partially 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, 2024 were $5.6 million, an increase of $0.2 million from $5.4 million for the three months ended June 30, 2023. The increase in production and ad valorem taxes was primarily attributable to production associated with the LongPoint Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2024 was $33.0 million, an increase of $13.3 million from $19.7 million for the three months ended June 30, 2023. The increase in depreciation and depletion expense was due to the LongPoint 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 $15.01 for the three months ended June 30, 2024, an increase of $3.16 per barrel from the $11.85 average depletion rate per barrel for the three months ended June 30, 2023. The increase in the depletion rate was due to the LongPoint 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 three months ended June 30, 2024 were $3.8 million, an increase of $0.9 million from $2.9 million for the three months ended June 30, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the LongPoint Acquisition.

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General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2024 were $10.3 million, an increase of $2.4 million compared to $7.9 million for the three months ended June 30, 2023. 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 $1.8 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

Interest Expense

Interest expense for the three months ended June 30, 2024 was $6.9 million compared to $6.3 million for the three months ended June 30, 2023. The increase in interest expense was primarily due to an increase in the overall long-term debt balance as a result of borrowings associated with the LongPoint Acquisition, partially offset by a slight decrease in the weighted average interest rate on our outstanding borrowings for the three months ended June 30, 2024.

Income Tax Expense

We recorded an income tax expense of $1.8 million and $0.9 million for the three months ended June 30, 2024 and 2023, respectively.

Comparison of the Six Months Ended June 30, 2024 to the Six Months Ended June 30, 2023

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2024, our oil, natural gas and NGL revenues were $164.5 million, an increase of $50.1 million from $114.4 million for the six months ended June 30, 2023. The increase in oil, natural gas and NGL revenues was primarily related to an increase in production volumes for the six months ended June 30, 2024 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 4,692,312 Boe or 25,782 Boe/d, for the six months ended June 30, 2024, an increase of 1,460,739 Boe or 7,999 Boe/d, from 3,231,573 Boe or 17,783 Boe/d, for the six months ended June 30, 2023. The increase in production for the six months ended June 30, 2024 was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition.

Our operators received an average of $76.87 per Bbl of oil, $2.03 per Mcf of natural gas and $24.72 per Bbl of NGL for the volumes sold during the six months ended June 30, 2024 compared to $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. These average prices received during the six months ended June 30, 2024 increased 5.5% or $4.03 per Bbl of oil and decreased 29.8% or $0.86 per Mcf of natural gas as compared to the six months ended June 30, 2023. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 6.6% or $4.96 per Bbl of oil and decrease of 12.1% or $0.29 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income for the six months ended June 30, 2024 was $1.1 million, a decrease of $1.4 million from $2.5 million for the six months ended June 30, 2023. The decrease in lease bonus and other income was primarily related to a $0.9 million legal settlement received during the six months ended June 30, 2023.

(Loss) Gain on Commodity Derivative Instruments

Loss on commodity derivative instruments for the six months ended June 30, 2024 included $12.5 million of mark-to-market losses and $5.7 million of gains on the settlement of commodity derivative instruments compared to $15.1 million of mark-to-market gains and $4.3 million of losses on the settlement of commodity derivative instruments for the six months ended June 30, 2023. We recorded a mark-to-market loss for the six months ended June 30, 2024 as a result of

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the increase in oil and natural gas strip pricing from the year ended December 31, 2023. 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, partially offset by realized losses on the settlement of commodity derivative instruments.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the six months ended June 30, 2024 were $12.1 million, an increase of $2.4 million from $9.7 million for the six months ended June 30, 2023. The increase in production and ad valorem taxes was primarily attributable to production associated with the MB Minerals Acquisition and the LongPoint Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2024 was $71.2 million, an increase of $34.0 million from $37.2 million for the six months ended June 30, 2023. The increase in depreciation and depletion expense was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.

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 $15.13 for the six months ended June 30, 2024, an increase of $3.67 per barrel from the $11.46 average depletion rate per barrel for the six months ended June 30, 2023. The increase in the depletion rate was due to the MB Minerals Acquisition and the LongPoint Acquisition, which significantly increased our net capitalized oil and natural gas properties.

Impairment

We recorded an impairment on our oil and natural gas properties of $6.0 million during the six months ended June 30, 2024, as a result of our full cost ceiling analysis. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas. We did not record an impairment on our oil and natural gas properties for the six months ended June 30, 2023.

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, 2024 were $8.4 million, an increase of $2.7 million from $5.7 million for the six months ended June 30, 2023. The increase in marketing and other deductions was primarily related to marketing and other deductions associated with the MB Minerals Acquisition and the LongPoint Acquisition.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2024 were $19.7 million, an increase of $3.5 million compared to $16.2 million for the six months ended June 30, 2023. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was attributable to a $2.3 million increase in unit-based compensation expense and cash general and administrative expenses resulting from an increase in our costs associated with company growth.

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Interest Expense

Interest expense for the six months ended June 30, 2024 was $14.2 million compared to $11.8 million for the six months ended June 30, 2023. The increase in interest expense was primarily due to an increase in the overall long-term debt balance as a result of borrowings associated with the MB Minerals Acquisition and the LongPoint Acquisition.

Income Tax Expense

We recorded an income tax expense of $2.7 million and $2.3 million for the six months ended June 30, 2024 and 2023, respectively.

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

Cash Distribution Policy

The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in our partnership agreement and in the limited liability company agreement of the Operating Company. 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 2024 for the repayment of $13.6 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the second quarter of 2024. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

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

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we issued 5,369,218 OpCo common units and an equal number of Class B units representing limited partnership interests in the Partnership (“Class B units”) and 557,302 common units as

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partial consideration in connection with the MB Minerals Acquisition and we completed the LongPoint Acquisition partially with net proceeds from the private placement of Series A preferred units. 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 2024 distributions.

Cash Flows

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

	Six Months Ended June 30,
	2024		2023
Cash Flow Data:
Net cash provided by operating activities	$	131,928,189	$	78,572,135
Net cash (used in) provided by investing activities		(131,089)		199,882,583
Net cash used in financing activities		(131,844,613)		(282,702,167)
Net decrease in cash and cash equivalents	$	(47,513)	$	(4,247,449)

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, 2024 were $131.9 million, an increase of $53.3 million compared to $78.6 million for the six months ended June 30, 2023.

Investing Activities

Cash flows used in investing activities for the six months ended June 30, 2024 were $0.1 million compared to $199.9 million of cash flows provided by investing activities for the six months ended June 30, 2023. For the six months ended June 30, 2024, cash flows used in investing activities included the purchase of equipment. 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 Kimbell Tiger Acquisition Corporation (“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.

Financing Activities

Cash flows used in financing activities were $131.8 million for the six months ended June 30, 2024 compared to $282.7 million for the six months ended June 30, 2023. Cash flows used in financing activities for the six months ended June 30, 2024 consists primarily of $98.2 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $33.4 million used to repay borrowings under our secured revolving credit facility, $4.9 million of restricted units repurchased for tax withholding and $0.3 million paid in connection with the redemption of Class B units, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.

Cash flows 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.

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Indebtedness

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

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

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

For additional information on our 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. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2024. 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.

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.

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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 2023 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2023 Form 10-K. As of June 30, 2024, 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, 2024, we had six 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.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of June 30, 2024, we had total borrowings outstanding under our secured revolving credit facility of $265.8 million. The impact of a 1% increase in the

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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, 2023 through June 30, 2024. 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, 2024, 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, 2024 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 16—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 2023 Form 10-K. These risk factors could materially affect our business, financial condition and results of operations. The volatility in the worldwide economy and oil and gas industry may make it more difficult to 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.

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Item 5. Other Information

Rule 10b5-1 Plans

On March 18, 2024, a member of our Board of Directors, Mitch Wynne, adopted a trading plan intended to satisfy Rule 10b5-1(c) to sell up to 27,539 common units between June 18, 2024, and December 18, 2024, subject to certain conditions. As of June 18, 2024, all shares had been sold under the plan.

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	—	Fifth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 13, 2023)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	Third Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 13, 2023)
10.1+	—	First Amendment to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on 10-Q filed on May 2, 2024)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS*	—	Inline XBRL Instance Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* —filed herewith

** —furnished herewith

+ —Management contract or compensatory plan or arrangement.

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SIGNATURES

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

	Kimbell Royalty Partners, LP
	By:	Kimbell Royalty GP, LLC
		its general partner
Date: August 1, 2024	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer

Date: August 1, 2024	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

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