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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, 2025 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 August 1, 2025, the registrant had outstanding 93,396,488 common units representing limited partner interests and 14,491,540 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	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3. Quantitative and Qualitative Disclosures About Market Risk	34
Item 4. Controls and Procedures	35


PART II – OTHER INFORMATION
Item 1. Legal Proceedings	35
Item 1A. Risk Factors	35
Item 5. Other Information	35
Item 6. Exhibits	36
Signatures	37

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30,		December 31,
	2025		2024

	(In thousands, except unit amounts)
ASSETS
Current assets
Cash and cash equivalents	$	34,524	$	34,168
Oil, natural gas and NGL receivables		47,989		45,924
Derivative assets		3,773		2,404
Accounts receivable and other current assets		1,963		2,771
Total current assets		88,249		85,267
Property and equipment, net		557		267
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($203,608 and $115,200 excluded from depletion at June 30, 2025 and December 31, 2024, respectively)		2,271,464		2,048,712
Less: accumulated depreciation, depletion and impairment		(1,085,279)		(1,023,890)
Total oil and natural gas properties, net		1,186,185		1,024,822
Right-of-use assets, net		4,783		3,730
Derivative assets		267		566
Loan origination costs, net		4,895		5,263
Total assets	$	1,284,936	$	1,119,915

LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	3,093	$	6,505
Other current liabilities		13,092		5,986
Derivative liabilities		—		255
Total current liabilities		16,185		12,746
Operating lease liabilities, excluding current portion		4,573		3,562
Derivative liabilities		669		879
Long-term debt		462,096		239,160
Other liabilities		10		73
Total liabilities		483,533		256,420
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (162,500 and 325,000 units issued and outstanding as of June 30, 2025 and December 31, 2024)		158,395		316,002
Kimbell Royalty Partners, LP unitholders' equity:
Common units (93,396,488 units and 80,969,651 units issued and outstanding as of June 30, 2025 and December 31, 2024, respectively)		555,914		463,496
Class B units (14,491,540 units and 14,524,120 units issued and outstanding as of June 30, 2025 and December 31, 2024, respectively)		724		726
Total Kimbell Royalty Partners, LP unitholders' equity		556,638		464,222
Non-controlling interest in OpCo		86,370		83,271
Total unitholders' equity		643,008		547,493
Total liabilities, mezzanine equity and unitholders' equity	$	1,284,936	$	1,119,915

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(In thousands, except per unit data)
Revenue
Oil, natural gas and NGL revenues	$	74,695	$	76,959	$	164,646	$	164,458
Lease bonus and other income		2,514		660		2,825		1,099
Gain (loss) on commodity derivative instruments, net		9,339		(1,046)		3,286		(6,750)
Total revenues		86,548		76,573		170,757		158,807
Costs and expenses
Production and ad valorem taxes		5,715		5,577		11,090		12,109
Depreciation and depletion expense		30,458		33,024		61,576		71,191
Impairment of oil and natural gas properties		—		—		—		5,963
Marketing and other deductions		3,016		3,828		7,518		8,391
General and administrative expense		9,573		10,252		19,210		19,700
Total costs and expenses		48,762		52,681		99,394		117,354
Operating income		37,786		23,892		71,363		41,453
Other expense
Interest expense		(8,947)		(6,946)		(15,569)		(14,247)
Other expense		—		—		(12)		—
Net income before income taxes		28,839		16,946		55,782		27,206
Income tax expense		2,167		1,759		3,257		2,682
Net income		26,672		15,187		52,525		24,524
Distribution and accretion on Series A preferred units		(24,337)		(5,243)		(29,540)		(10,499)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(314)		(1,513)		(3,088)		(2,404)
Distribution to Class B unitholders		(14)		(21)		(28)		(42)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	2,007	$	8,410	$	19,869	$	11,579

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.02	$	0.11	$	0.22	$	0.16
Diluted	$	0.02	$	0.11	$	0.22	$	0.16
Weighted average number of common units outstanding
Basic		91,170		74,835		90,430		73,473
Diluted		122,924		116,594		125,277		116,396

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2025
									Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Total

	(In thousands)
Balance at January 1, 2025		80,970	$	463,496		14,524	$	726	$	83,271	$	547,493
Common units issued for equity offering		11,500		163,575		—		—		—		163,575
Unit-based compensation		1,213		3,861		—		—		—		3,861
Restricted units repurchased for tax withholding		(315)		(5,081)		—		—		—		(5,081)
Conversion of Class B units to common units		32		187		(32)		(2)		(187)		(2)
Forfeiture of restricted units		(4)		(57)		—		—		—		(57)
Distributions to unitholders		—		(37,359)		—		—		(5,796)		(43,155)
Distribution and accretion on Series A preferred units		—		(4,504)		—		—		(699)		(5,203)
Distribution to Class B unitholders		—		(14)		—		—		—		(14)
Change in ownership of consolidated subsidiaries, net		—		(12,253)		—		—		12,253		—
Net income		—		22,380		—		—		3,473		25,853
Balance at March 31, 2025		93,396		594,231		14,492		724		92,315		687,270
Unit-based compensation		—		4,124		—		—		—		4,124
Distributions to unitholders		—		(43,896)		—		—		(6,811)		(50,707)
Distribution and accretion on Series A preferred units		—		(21,068)		—		—		(3,269)		(24,337)
Distribution to Class B unitholders		—		(14)		—		—		—		(14)
Change in ownership of consolidated subsidiaries, net		—		(552)		—		—		552		—
Net income		—		23,089		—		—		3,583		26,672
Balance at June 30, 2025		93,396	$	555,914		14,492	$	724	$	86,370	$	643,008

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)


	Six Months Ended June 30, 2024
									Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Total

	(In thousands)
Balance at January 1, 2024		73,851	$	555,809		20,847	$	1,042	$	157,192	$	714,043
Restricted units repurchased for tax withholding		(292)		(4,914)		—		—		—		(4,914)
Unit-based compensation		1,088		3,684		—		—		—		3,684
Distributions to unitholders		—		(32,098)		—		—		(9,463)		(41,561)
Distribution and accretion on Series A preferred units		—		(4,109)		—		—		(1,147)		(5,256)
Distribution to Class B unitholders		—		(21)		—		—		—		(21)
Change in ownership of consolidated subsidiaries, net		—		1,192		—		—		(1,192)		—
Net income		—		7,299		—		—		2,038		9,337
Balance at March 31, 2024		74,647		526,842		20,847		1,042		147,428		675,312
Conversion of Class B units to common units		6,323		44,716		(6,323)		(316)		(44,716)		(316)
Unit-based compensation		—		5,109		—		—		—		5,109
Distributions to unitholders		—		(36,577)		—		—		(10,216)		(46,793)
Distribution and accretion on Series A preferred units		—		(4,446)		—		—		(797)		(5,243)
Distribution to Class B unitholders		—		(21)		—		—		—		(21)
Change in ownership of consolidated subsidiaries, net		—		(3,824)		—		—		3,824		—
Net income		—		12,877		—		—		2,310		15,187
Balance at June 30, 2024		80,970	$	544,676		14,524	$	726	$	97,833	$	643,235

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

Table of Contents

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
	2025		2024

	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	52,525	$	24,524
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		61,576		71,191
Impairment of oil and natural gas properties		—		5,963
Amortization of right-of-use assets		171		173
Amortization of loan origination costs		1,113		1,060
Unit-based compensation		7,985		8,793
Forfeiture of restricted units		(57)		—
(Gain) loss on derivative instruments, net of settlements		(1,535)		12,534
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(2,065)		5,802
Accounts receivable and other current assets		809		(689)
Accounts payable		(941)		(40)
Other current liabilities		7,034		2,804
Operating lease liabilities		(141)		(186)
Net cash provided by operating activities		126,474		131,929
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(552)		(109)
Proceeds from sale of property and equipment		13		—
Purchase of oil and natural gas properties		(222,752)		(22)
Net cash used in investing activities		(223,291)		(131)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering, net of issuance costs		163,575		—
Redemption of Class B contributions on converted units		(2)		(317)
Redemption of Series A preferred units		(179,908)		—
Distribution to common unitholders		(81,255)		(68,675)
Distribution to OpCo unitholders		(12,607)		(19,679)
Distribution to Series A preferred unitholders		(9,710)		(9,763)
Distribution to Class B unitholders		(28)		(42)
Borrowings on long-term debt		254,136		4,960
Repayments on long-term debt		(31,200)		(33,400)
Payment of loan origination costs		(747)		(16)
Restricted units repurchased for tax withholding		(5,081)		(4,914)
Net cash provided by (used in) financing activities		97,173		(131,846)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		356		(48)
CASH AND CASH EQUIVALENTS, beginning of period		34,168		30,993
CASH AND CASH EQUIVALENTS, end of period	$	34,524	$	30,945
Supplemental cash flow information:
Cash paid for interest	$	11,391	$	13,325
Cash paid for taxes	$	219	$	—
Non-cash investing and financing activities:
Deemed distribution to Series A preferred units	$	673	$	789
Distribution on Series A preferred units in accounts payable	$	2,431	$	4,848
Recognition of tenant improvement asset	$	63	$	63
Right-of-use assets obtained in exchange for operating lease liabilities	$	1,224	$	—

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 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, 2024 (the “2024 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 has one business activity as the owner of mineral and royalty interests and 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 (the “CODM”) in deciding how to

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allocate resources and assess performance. The segment participates in activities and derives revenue as described in the organization section on a consolidated basis. The Partnership’s CODM is our Chief Operating Officer.

The CODM assesses performance for the segment and decides how to allocate resources based on net income presented on a consolidated basis, for purposes of allocating resources and evaluating financial performance as presented on the consolidated statement of operations. The CODM uses this measure in the annual budgeting and monthly forecasting process and to evaluate income generated from segment assets to distribute cash to unitholders and deciding whether to reinvest profits for new or existing mineral and royalty interest through acquisitions or organic growth. The measure of segment assets is reported on the balance sheet as total consolidated assets. The accounting policies of the segment are the same as those described in the summary of significant accounting policies.

Significant segment expenses of the Partnership include production and ad valorem taxes, depreciation and depletion expense, impairment of oil and natural gas properties, marketing and other deductions, general and administrative expense and interest expense. Other segment items included in net income are income tax expenses and other income (expense) line items. All significant segment expenses and other segment items are presented individually in the consolidated statements of operations.

Global Conflicts and Uncertainties

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. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, the ceasefire has not held and the conflict has continued. 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.

President Trump has executed several executive orders, some of which impact the oil and gas industry, and he and others in Congress have indicated the potential for further changes to regulations, many of which could impact the oil and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.

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 2024 Form 10-K. There have been no substantial changes in such policies or the application of such policies during the three and six months ended June 30, 2025.

Recently Issued Accounting Pronouncements

In December 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. For entities other than public business entities, the amendments are effective for annual periods beginning after December 15, 2025, with early adoption 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.

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In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40).” The amendments in this update apply to all public business entities. The amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in this update should be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this Update or (2) retrospectively to any or all prior periods presented in the financial statements. 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,
	2025		2024		2025		2024

	(In thousands)
Oil revenue	$	48,827	$	53,405	$	100,762	$	115,033
Natural gas revenue		15,293		14,071		40,931		28,625
NGL revenue		10,575		9,483		22,953		20,800
Total Oil, natural gas and NGL revenues	$	74,695	$	76,959	$	164,646	$	164,458

NOTE 4—ACQUISITIONS

Acquisitions

On January 17, 2025, the Partnership completed the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in a transaction valued at approximately $230.4 million, including transaction costs and certain customary post-closing adjustments. The Partnership funded the cash consideration of the purchase price with borrowings under its secured revolving credit facility and net proceeds from the 2025 Equity Offering (as defined in Note 11). The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas. The Boren Acquisition was accounted for as an asset acquisition and the allocation of the purchase price was $94.9 million to proved developed properties and $127.8 million to unevaluated properties.

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.

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As of June 30, 2025, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its natural gas fixed price swap transactions are settled based upon the last scheduled trading day of the first nearby month futures contract corresponding to the relevant contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. Changes in the fair values of the Partnership’s commodity derivative instruments are recognized as gains or losses in the current period and are presented on a net basis within revenue in the accompanying 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,
	2025		2024		2025		2024

	(In thousands)
Beginning fair value of derivative instruments	$	(5,154)	$	5,309	$	1,836	$	14,047
Gain (loss) on commodity derivative instruments, net		9,339		(1,046)		3,286		(6,750)
Net cash received on settlements of derivative instruments		(814)		(2,750)		(1,751)		(5,784)
Ending fair value of derivative instruments	$	3,371	$	1,513	$	3,371	$	1,513

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	2025		2024

			(In thousands)
Assets:
Current assets	Derivative assets	$	3,773	$	2,404
Long-term assets	Derivative assets		267		566
Liabilities:
Current liabilities	Derivative liabilities		—		(255)
Long-term liabilities	Derivative liabilities		(669)		(879)
		$	3,371	$	1,836

As of June 30, 2025, 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 2025 - December 2025	282,440	$	71.12	$	68.26	$	74.20
January 2026 - December 2026	595,680	$	67.75	$	63.33	$	70.78
January 2027 - June 2027	304,623	$	62.65	$	61.57	$	63.75

Natural Gas Price Swaps


	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
July 2025 - December 2025	2,553,644	$	3.71	$	3.68	$	3.74
January 2026 - December 2026	5,256,000	$	3.69	$	3.33	$	4.07
January 2027 - June 2027	2,658,528	$	3.96	$	3.47	$	4.46

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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, 2025 and December 31, 2024 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

●

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

●

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

●

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and six months ended June 30, 2025 and 2024.

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

	(In thousands)
June 30, 2025
Assets
Commodity derivative contracts	$	—	$	6,917	$	—	$	(2,877)	$	4,040
Liabilities
Commodity derivative contracts	$	—	$	(3,546)	$	—	$	2,877	$	(669)
December 31, 2024
Assets
Commodity derivative contracts	$	—	$	4,476	$	—	$	(1,506)	$	2,970
Liabilities
Commodity derivative contracts	$	—	$	(2,640)	$	—	$	1,506	$	(1,134)

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NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:


	June 30,		December 31,
	2025		2024

	(In thousands)
Oil and natural gas properties
Proved properties	$	2,067,856	$	1,933,512
Unevaluated properties		203,608		115,200
Less: accumulated depreciation, depletion and impairment		(1,085,279)		(1,023,890)
Total oil and natural gas properties	$	1,186,185	$	1,024,822

Costs not subject to depletion
Incurred in 2025	$	120,791
Incurred in 2024		—
Incurred in 2023		82,817
Prior		—
Total costs not subject to depletion	$	203,608

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

The Partnership did not record an impairment on its oil and natural gas properties for the three and six months ended June 30, 2025. 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.

Depletion expense for the three months ended June 30, 2025 and 2024 was $30.4 million and $32.9 million, respectively and the average depletion rate per barrel was $13.16 and $15.01, respectively. Depletion expense for the six months ended June 30, 2025 and 2024 was $61.4 million and $71.0 million, respectively and the average depletion rate per barrel was $13.34 and $15.13, respectively.

NOTE 8—LEASES

The Partnership is the lessee on a lease of administrative office space used for its operations. On December 26, 2024, the Partnership modified its existing operating leases associated with its main office used for operations. The lease commenced in February 2025, expanding the current office space and extending the lease term to 2035, with the exclusive right and option to renew and extend the lease at the expiration of the primary term. The Partnership does not have any material lessor arrangements. Substantially all the Partnership’s leases are long-term operating leases with fixed payment terms and will terminate in February 2035. 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, 2025 is 9.59 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,

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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 7.51% for the six months ended June 30, 2025.

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, 2025 and 2024. The total operating lease expense recorded for the three months June 30, 2025 and 2024 was $0.2 million and $0.1 million, respectively, and $0.4 million and $0.3 million for the six months ended June 30, 2025 and 2024, respectively.

Future minimum lease commitments as of June 30, 2025 were as follows:


	Total		2025		2026		2027		2028		2029		Thereafter

	(In thousands)
Operating leases	$	6,906	$	324	$	658	$	668	$	682	$	702	$	3,872
Less: Imputed Interest		(2,031)
Total	$	4,875

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.

On May 1, 2025, in connection with the recent redetermination, the Partnership entered into Amendment No. 3 (the “Third 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 $550.0 million to $625.0 million.

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 2025, the Partnership borrowed an additional $254.1 million under the secured revolving credit facility and repaid approximately $31.2 million of the outstanding borrowings. As of June 30, 2025, the Partnership’s outstanding balance was $462.1 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of June 30, 2025.

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As of June 30, 2025, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.25% or the ABR (as defined in the Amended Credit Agreement) plus a margin of 2.25%. For the three and six months ended June 30, 2025, the weighted average interest rate on the Partnership’s outstanding borrowings was 7.75% and 7.72%, respectively.

NOTE 10—PREFERRED UNITS

On May 7, 2025, the Partnership completed the redemption of 162,500 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,121.92 per Series A preferred unit for an aggregate redemption price of $182.3 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date, a deemed dividend distribution of $24.0 million was recognized in unitholders’ equity and non-controlling interest during the six months ended June 30, 2025.

The Series A preferred units are classified as mezzanine equity on the consolidated balance sheets due to certain redemption provisions being outside of the Partnership’s control. The Partnership has elected to accrete changes in the redemption value of the Series A preferred units over the period from the date of issuance to the earliest redemption date. The Series A preferred units were estimated to be redeemable at a price of $1,116.00 per Series A preferred unit as of June 30, 2025, equal to 112% of par value.

The Series A preferred units had a carrying value of $158.4 million, including accrued distributions of $2.4 million, as of June 30, 2025, and a carrying value of $316.0 million, including accrued distributions of $4.9 million, as of December 31, 2024.

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of June 30, 2025, the Partnership had a total of 93,396,488 common units issued and outstanding and 14,491,540 Class B units issued and outstanding.

On January 9, 2025, the Partnership completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). The Partnership used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition.

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


		Common Units
Balance at December 31, 2024		80,969,651
Units issued for equity offering		11,500,000
Common units issued under the A&R LTIP (1)		1,213,611
Restricted units repurchased for tax withholding		(315,276)
Conversion of Class B units to common units		32,580
Forfeiture of restricted units		(4,078)
Balance at June 30, 2025		93,396,488

(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 25, 2025.

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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 2025	$	0.47	May 8, 2025	May 20, 2025	May 28, 2025
Q2 2025	$	0.38	August 7, 2025	August 18, 2025	August 25, 2025

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

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.

Holders of the Class B units are entitled to one vote per unit on all matters to be voted upon by the unitholders. 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.

Change in Ownership of Consolidated Subsidiaries

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(In thousands)
Net income attributable to the Partnership	$	23,089	$	12,877	$	45,469	$	20,176
Changes in ownership of consolidated subsidiaries, net		(552)		(3,824)		(12,805)		(2,632)
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$	22,537	$	9,053	$	32,664	$	17,544

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.

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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,
	2025		2024		2025		2024

	(In thousands)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	2,007	$	8,410	$	19,869	$	11,579
Distribution and accretion on Series A preferred units		24,337		5,243		29,540		10,499
Net income attributable to non-controlling interests in OpCo and distribution to Class B unitholders		328		1,534		3,116		2,446
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	26,672	$	15,187	$	52,525	$	24,524

Weighted average number of common units outstanding:
Basic		91,170		74,835		90,430		73,473
Effect of dilutive securities:
Series A preferred units		15,048		21,566		18,290		21,566
Class B units		14,492		18,624		14,499		19,736
Restricted units		2,214		1,569		2,058		1,621
Diluted		122,924		116,594		125,277		116,396

Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.02	$	0.11	$	0.22	$	0.16
Diluted	$	0.02	$	0.11	$	0.22	$	0.16

The calculation of diluted net income per unit for the three and six months ended June 30, 2025 and 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.

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.

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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, 2024	1,992,201	$	15.727	1.542 years
Awarded	1,213,611		15.780	—
Vested	(975,338)		15.519	—
Forfeited	(4,078)		15.633	—
Unvested at June 30, 2025 (1)	2,226,396	$	15.847	2.079 years

(1)	As of June 30, 2025, there was $35.3 million of unrecognized compensation expense associated with unvested restricted units based on the weighted average grant date fair value per unit of $15.847.

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, 2025 was 5.8%, compared to 9.9% for the three months ended June 30, 2024. The Partnership recorded an income tax expense of $2.2 million and $1.8 million for the three months ended June 30, 2025 and 2024, respectively, and an income tax expense of $3.3 million and $2.7 million for the six months ended June 30, 2025 and 2024, 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 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. During the three and six months ended June 30, 2025, the Partnership made payments to K3 Royalties in the amount of $30,000 and $60,000, respectively.

The Partnership received $41,732 and $82,888 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three and six months ended June 30, 2025, respectively.

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, 2025.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to June 30, 2025 in the preparation of its unaudited interim consolidated financial statements.

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Government Legislation

The One Big Beautiful Bill Act, enacted on July 4, 2025, introduced significant modifications to the U.S. tax code. Pursuant to ASC Topic 740, Income Taxes, the effects of changes in tax law are recognized in the period of enactment. As such, this legislation is not reflected in the Partnership’s unaudited consolidated financial statements for the periods ended June 30, 2025. The Partnership is currently evaluating the full impact of this new legislation on its consolidated financial statements.

Distributions

On August 7, 2025 the Board of Directors declared a quarterly cash distribution of $0.38 per common unit and $0.380261 per OpCo common unit for the quarter ended June 30, 2025. The Partnership intends to pay this distribution on August 25, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on August 18, 2025.

As to the Partnership, $0.000261 of the OpCo common unit distribution corresponds to a tax payment made by the Partnership in the second quarter of 2025. Under the limited liability company agreement of the Operating Company, the Partnership is not reimbursed by the Operating Company for federal income taxes paid by the Partnership.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $2.4 million for the quarter ended June 30, 2025. The Partnership intends to pay the distribution subsequent to August 7, 2025, 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, 2024 (the “2024 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, 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 energy and environmental proposals being considered and evaluated by the federal government and other regulating bodies;

●

trade policies and tensions, including changes in, or the imposition of, tariffs and/or trade barriers and the economic impacts, volatility and uncertainty resulting therefrom, which may have varying effects on commodity prices;

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●

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

●

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 regulation, proposals, and 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 2024 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.

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As of June 30, 2025, we owned mineral and royalty interests in approximately 12.3 million gross acres and overriding royalty interests in approximately 4.7 million gross acres, with approximately 55% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non-cost-bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2025, 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 131,000 gross wells, including over 52,000 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, 2025:


			Average Daily
			Production
Basin or Producing Region	Gross Acreage	Net Acreage	(Boe/d)(6:1)(1)	Well Count
Permian Basin	3,404,777	27,799	11,068	52,162
Mid‑Continent	5,868,926	48,832	4,392	21,029
Terryville/Cotton Valley/Haynesville	1,428,907	7,919	3,664	16,372
Appalachian Basin	741,354	23,203	1,583	3,965
Bakken/Williston Basin	1,640,077	6,138	832	5,519
Eagle Ford	624,148	6,730	1,826	4,448
DJ Basin/Rockies/Niobrara	74,152	1,036	849	12,598
Other	3,232,560	36,693	1,141	15,478
Total	17,014,901	158,350	25,355	131,571

(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 2024 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, 2025:


Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	524	459	3.27	2.15
Mid‑Continent	114	76	0.78	0.39
Terryville/Cotton Valley/Haynesville	54	30	0.35	0.13
Appalachian Basin	3	4	0.02	0.02
Bakken/Williston Basin	61	97	0.36	0.10
Eagle Ford	55	15	0.22	0.08
DJ Basin/Rockies/Niobrara	12	6	0.10	0.02
Total	823	687	5.10	2.89

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

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Recent Developments

Equity Offering

On January 9, 2025, we completed an underwritten public offering of 11,500,000 common units for net proceeds of approximately $163.6 million (the “2025 Equity Offering”). We used the net proceeds from the 2025 Equity Offering to purchase OpCo common units. The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition (as defined below).

Acquisitions

On January 17, 2025, we completed the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in a transaction valued at approximately $230.4 million, including transaction costs and certain customary post-closing adjustments. We funded the cash consideration of the purchase price with borrowings under our secured revolving credit facility and net proceeds from the 2025 Equity Offering. The oil and gas properties acquired are located under the Mabee Ranch in the Midland Basin in Texas.

Partial Redemption of Preferred Units

On May 7, 2025, we completed the redemption of 162,500 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,121.92 per Series A preferred unit for an aggregate redemption price of $182.3 million.

Quarterly Distributions

On August 7, 2025, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.38 per common unit representing limited partner interests in the Partnership (“common unit”) and $0.380261 per common unit of the Operating Company (“OpCo common unit”) for the quarter ended June 30, 2025. We intend to pay the distributions on August 25, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on August 18, 2025.

As to us, $0.000261 of the OpCo common unit distribution corresponds to a tax payment made by us in the second quarter of 2025. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.

We will pay a cash distribution on the Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) of approximately $2.4 million for the quarter ended June 30, 2025. We intend to pay the distribution subsequent to August 7, 2025 and prior to the distribution on the common units and OpCo common units.

Business Environment

Global Conflicts and Uncertainties

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. In April 2024, Iran launched an attack on Israel, further escalating the regional conflict in the Middle East. In January 2025, Israel and Hamas agreed to a ceasefire deal, however, the ceasefire has not held and the conflict has continued. 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.

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and gas industry, as well as the implementation of tariffs on foreign goods and services. It is uncertain at this time to what extent such changes in regulations and tariffs will impact our business. Tariffs on foreign goods and services could result in other countries instituting tariffs on U.S. goods and services, which could impact the demand for and price of commodities, increase the price of supplies and raw materials that we rely on, and could impact interest rates. A changing regulatory environment and domestic or foreign tariffs could ultimately impact our operations and expenses.

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, 2025				Six Months Ended June 30, 2024
	High		Low		High		Low
Oil ($/Bbl)	$	80.73	$	58.50	$	87.69	$	70.62
Natural gas ($/MMBtu)	$	9.86	$	2.65	$	13.20	$	1.25

On July 28, 2025, the West Texas Intermediate posted price for crude oil was $67.81 per Bbl and the Henry Hub spot market price of natural gas was $3.12 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,
	2025		2024		2025		2024
Oil ($/Bbl)	$	64.57	$	81.81	$	68.12	$	79.69
Natural gas ($/MMBtu)	$	3.19	$	2.07	$	3.66	$	2.11

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 4.8% to 533 active land rigs at June 30, 2025 compared to 560 active land rigs at June 30, 2024. The 533 active land rigs at June 30, 2025 decreased by 7.3% compared to 575 active land rigs at March 31, 2025. The decrease in rig count is primarily related to a decrease in the average prices received for oil, partially offset by an increase in the average price received for natural gas, coupled with domestic and international uncertainties, as noted above.

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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	2025	2024
Permian Basin	53	47
Mid‑Continent	13	20
Terryville/Cotton Valley/Haynesville	11	9
Appalachian Basin	—	1
Bakken/Williston Basin	6	7
Eagle Ford	3	6
DJ Basin/Rockies/Niobrara	—	1
Other	2	—
Total	88	91

Sources of Our Revenue

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Revenue
Oil revenue	66	%	70	%	61	%	70	%
Natural gas revenue	20	%	18	%	25	%	17	%
NGL revenue	14	%	12	%	14	%	13	%
	100	%	100	%	100	%	100	%

We have entered into oil and natural gas commodity derivative agreements, which extend through June 2027, to establish, in advance, a price for the sale of a portion of the oil and natural gas produced from our mineral and royalty interests. For further discussion on our commodity derivative agreements, see “Note 5—Derivatives.”

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 and unrealized gains and losses on derivative instruments. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution on common units as Adjusted EBITDA, less cash needed for debt service and other

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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,
	2025		2024		2025		2024

	(In thousands)
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	26,672	$	15,187	$	52,525	$	24,524
Depreciation and depletion expense		30,458		33,024		61,576		71,191
Interest expense		8,947		6,946		15,569		14,247
Income tax expense		2,167		1,759		3,257		2,682
EBITDA		68,244		56,916		132,927		112,644
Impairment of oil and natural gas properties		—		—		—		5,963
Unit-based compensation		4,124		5,109		7,985		8,793
(Gain) loss on derivative instruments, net of settlements		(8,524)		3,796		(1,535)		12,534
Consolidated Adjusted EBITDA		63,844		65,821		139,377		139,934
Adjusted EBITDA attributable to non-controlling interest		(8,576)		(10,011)		(18,722)		(26,191)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		55,268		55,810		120,655		113,743
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		5,810		5,620		9,861		10,854
Cash distribution to Series A preferred unitholders		2,104		4,111		6,267		7,911
Cash income tax expense		219		—		219		—
Distribution to Class B unitholders		14		21		28		42
Cash available for distribution on common units	$	47,121	$	46,058	$	104,280	$	94,936

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	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024

	(In thousands)
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	$	72,321	$	62,883	$	126,474	$	131,929
Interest expense		8,947		6,946		15,569		14,247
Income tax expense		2,167		1,759		3,257		2,682
Impairment of oil and natural gas properties		—		—		—		(5,963)
Amortization of right-of-use assets		(86)		(87)		(171)		(173)
Amortization of loan origination costs		(579)		(530)		(1,113)		(1,060)
Unit-based compensation		(4,124)		(5,109)		(7,985)		(8,793)
Forfeiture of restricted units				—		57		—
Gain (loss) on derivative instruments, net of settlements		8,524		(3,796)		1,535		(12,534)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(13,009)		(1,486)		2,065		(5,802)
Accounts receivable and other current assets		(792)		(460)		(809)		689
Accounts payable		3		353		941		40
Other current liabilities		(5,208)		(3,651)		(7,034)		(2,804)
Operating lease liabilities		80		94		141		186
EBITDA		68,244		56,916		132,927		112,644
Add:
Impairment of oil and natural gas properties		—		—		—		5,963
Unit-based compensation		4,124		5,109		7,985		8,793
(Gain) loss on derivative instruments, net of settlements		(8,524)		3,796		(1,535)		12,534
Consolidated Adjusted EBITDA		63,844		65,821		139,377		139,934
Adjusted EBITDA attributable to non-controlling interest		(8,576)		(10,011)		(18,722)		(26,191)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		55,268		55,810		120,655		113,743
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		5,810		5,620		9,861		10,854
Cash distribution to Series A preferred unitholders		2,104		4,111		6,267		7,911
Cash income tax expense		219		—		219		—
Distribution to Class B unitholders		14		21		28		42
Cash available for distribution on common units	$	47,121	$	46,058	$	104,280	$	94,936

Factors Affecting the Comparability of Our Results to Our Historical Results

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

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material

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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, 2025 and 2024 include the Boren Acquisition in January 2025.

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.

We did not record an impairment on our oil and natural gas properties for the three and six months ended June 30, 2025 or the three months ended June 30, 2024. 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.

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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,
	2025		2024		2025		2024

	(In thousands, except production data)
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	74,695	$	76,959	$	164,646	$	164,458
Lease bonus and other income		2,514		660		2,825		1,099
Gain (loss) on commodity derivative instruments, net		9,339		(1,046)		3,286		(6,750)
Total revenues		86,548		76,573		170,757		158,807
Costs and expenses
Production and ad valorem taxes		5,715		5,577		11,090		12,109
Depreciation and depletion expense		30,458		33,024		61,576		71,191
Impairment of oil and natural gas properties		—		—		—		5,963
Marketing and other deductions		3,016		3,828		7,518		8,391
General and administrative expense		9,573		10,252		19,210		19,700
Total costs and expenses		48,762		52,681		99,394		117,354
Operating income		37,786		23,892		71,363		41,453
Other expense
Interest expense		(8,947)		(6,946)		(15,569)		(14,247)
Other expense		—		—		(12)		—
Net income before income taxes		28,839		16,946		55,782		27,206
Income tax expense		2,167		1,759		3,257		2,682
Net income		26,672		15,187		52,525		24,524
Distribution and accretion on Series A preferred units		(24,337)		(5,243)		(29,540)		(10,499)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(314)		(1,513)		(3,088)		(2,404)
Distribution to Class B unitholders		(14)		(21)		(28)		(42)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	2,007	$	8,410	$	19,869	$	11,579
Production Data:
Oil (Bbls)		768,711		691,819		1,518,455		1,496,408
Natural gas (Mcf)		6,538,116		6,714,323		13,157,069		14,127,392
Natural gas liquids (Bbls)		448,887		383,092		891,074		841,339
Combined volumes (Boe) (6:1)		2,307,284		2,193,965		4,602,374		4,692,312

Comparison of the Three Months Ended June 30, 2025 to the Three Months Ended June 30, 2024

Oil, Natural Gas and NGL Revenues

For the three months ended June 30, 2025, our oil, natural gas and NGL revenues were $74.7 million, a decrease of $2.3 million from $77.0 million for the three months ended June 30, 2024. The decrease in oil, natural gas and NGL revenues was primarily related to decrease in the average prices received for oil and NGLs, partially offset by an increase in the average prices received for natural gas and an increase in production volumes for the three months ended June 30, 2025 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 2,307,284 Boe or 25,355 Boe/d, for the three months ended June 30, 2025, an increase of 113,319 Boe or 1,245 Boe/d, from 2,193,965 Boe or 24,110 Boe/d, for the three months ended June 30, 2024. The increase in production volumes for the three months ended June 30, 2025 was primarily attributable to production associated with the Boren Acquisition.

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Our operators received an average of $63.52 per Bbl of oil, $2.34 per Mcf of natural gas and $23.56 per Bbl of NGL for the volumes sold during the three months ended June 30, 2025 compared to $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. These average prices received during the three months ended June 30, 2025 decreased 17.7% or $13.68 per Bbl of oil and increased 11.4% or $0.24 per Mcf of natural gas as compared to the three months ended June 30, 2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 21.1% or $17.24 per Bbl of oil and an increase of 54.1% or $1.12 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, 2025 was $2.5 million, an increase of $1.8 million compared to $0.7 million for the three months ended June 30, 2024. The increase in lease bonus and other income was due to an increase in activity during the three months ended June 30, 2025.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the three months ended June 30, 2025 included $8.5 million of mark-to-market gains and $0.8 million of gains on the settlement of commodity derivative instruments compared to $3.8 million of mark-to-market losses and $2.8 million of gains on the settlement of commodity derivative instruments for the three months ended June 30, 2024. We recorded a mark-to-market gain for the three months ended June 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing. We recorded a mark-to-market loss for the three months ended June 30, 2024 as a result of an increase in strip pricing from the previous quarter, partially offset by gains on the settlement of commodity derivative instruments.

Production and Ad Valorem Taxes

Production and ad valorem taxes for the three months ended June 30, 2025 remained relatively flat at $5.7 million, compared to $5.6 million for the three months ended June 30, 2024.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended June 30, 2025 was $30.5 million, a decrease of $2.5 million from $33.0 million for the three months ended June 30, 2024. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which 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 $13.16 for the three months ended June 30, 2025, a decrease of $1.85 per barrel from the $15.01 average depletion rate per barrel for the three months ended June 30, 2024. The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which 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, 2025 were $3.0 million, a decrease of $0.8 million compared to $3.8 million for the three months ended June 30, 2024. The decrease in marketing and other deductions was primarily related to decrease in the average prices received for oil and NGLs, partially offset by an increase in the average prices received for natural gas for the three months ended June 30, 2025.

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General and Administrative Expenses

General and administrative expenses for the three months ended June 30, 2025 were $9.6 million, a decrease of $0.7 million compared to $10.3 million for the three months ended June 30, 2024. 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 decrease in general and administrative expenses was primarily attributable to a decrease in unit-based compensation expense.

Interest Expense

Interest expense for the three months ended June 30, 2025 was $8.9 million, compared to $6.9 million for the three months ended June 30, 2024. The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the partial redemption of the Series A preferred units.

Income Tax Expense

We recorded an income tax expense of $2.2 million and $1.8 million for the three months ended June 30, 2025 and 2024, respectively.

Comparison of the Six Months Ended June 30, 2025 to the Six Months Ended June 30, 2024

Oil, Natural Gas and NGL Revenues

For the six months ended June 30, 2025, our oil, natural gas and NGL revenues remained flat at $164.6 million, compared to $164.5 million for the six months ended June 30, 2024.

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 4,602,374 Boe or 25,427 Boe/d, for the six months ended June 30, 2025, a decrease of 89,938 Boe or 355 Boe/d, from 4,692,312 Boe or 25,782 Boe/d, for the six months ended June 30, 2024. The decrease in production for the six months ended June 30, 2025 was primarily attributable to prior period production recognized for the six months ended June 30, 2024, partially offset by production associated with the Boren Acquisition.

Our operators received an average of $66.36 per Bbl of oil, $3.11 per Mcf of natural gas and $25.76 per Bbl of NGL for the volumes sold during the six months ended June 30, 2025 compared to $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. These average prices received during the six months ended June 30, 2025 decreased 13.7% or $10.51 per Bbl of oil and increased 53.2% or $1.08 per Mcf of natural gas as compared to the six months ended June 30, 2024. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 14.5% or $11.57 per Bbl of oil and an increase of 73.5% or $1.55 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, 2025 was $2.8 million, an increase of $1.7 million compared to $1.1 million for the six months ended June 30, 2024. The increase in lease bonus and other income was due to an increase in activity during the six months ended June 30, 2025.

Gain (Loss) on Commodity Derivative Instruments

Gain on commodity derivative instruments for the six months ended June 30, 2025 included $1.5 million of mark-to-market gains and $1.8 million of gains on the settlement of commodity derivative instruments compared to $12.5 million of mark-to-market losses and $5.7 million of gains on the settlement of commodity derivative instruments for the six months ended June 30, 2024. We recorded a mark-to-market gain for the six months ended June 30, 2025 as a result of the maturity of derivative contracts with lower strike pricing. We recorded a mark-to-market loss for the six months ended June 30, 2024 as a result of an increase in strip pricing from the previous quarter, partially offset by gains on the settlement of commodity derivative instruments.

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Production and Ad Valorem Taxes

Production and ad valorem taxes for the six months ended June 30, 2025 were $11.1 million, a decrease of $1.0 million from $12.1 million for the six months ended June 30, 2024. The decrease in production and ad valorem taxes was primarily attributable to the decrease in oil and natural gas production, partially offset by an increase in production and ad valorem taxes associated with the Boren Acquisition.

Depreciation and Depletion Expense

Depreciation and depletion expense for the six months ended June 30, 2025 was $61.6 million, a decrease of $9.6 million from $71.2 million for the six months ended June 30, 2024. The decrease in depreciation and depletion expense was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which 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 $13.34 for the six months ended June 30, 2025, a decrease of $1.79 per barrel from the $15.13 average depletion rate per barrel for the six months ended June 30, 2024. The decrease in the depletion rate was due to the impairment that was recorded during the year ended December 31, 2024, which significantly reduced our net capitalized oil and natural gas properties, partially offset by the Boren Acquisition, which increased our net capitalized oil and natural gas properties.

Impairment

We did not record an impairment on our oil and natural gas properties for the six months ended June 30, 2025. 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 is primarily attributed to the decline in the 12-month average price of oil and natural gas.

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, 2025 was $7.5 million, a decrease of $0.9 million compared to $8.4 million for the six months ended June 30, 2024. The decrease in marketing and other deductions was primarily related to decrease in the average prices received for oil and NGLs, partially offset by an increase in the average prices received for natural gas for the six months ended June 30, 2025.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2025 were $19.2 million, a decrease of $0.5 million compared to $19.7 million for the six months ended June 30, 2024. 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 decrease in general and administrative expenses was primarily attributable to a decrease in unit-based compensation expense.

Interest Expense

Interest expense for the six months ended June 30, 2025 was $15.6 million, compared to $14.2 million for the six months ended June 30, 2024. The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the partial redemption of the Series A preferred units.

Income Tax Expense

We recorded an income tax expense of $3.3 million and $2.7 million for the six months ended June 30, 2025 and 2024, respectively.

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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 fo

Kimbell Royalty Partners, LP 10-Q