10-Q

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 March 31, 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 May 2, 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	19
Item 3. Quantitative and Qualitative Disclosures About Market Risk	33
Item 4. Controls and Procedures	34
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 2. Unregistered Sales of Equity Securities	35
Item 5. Other Information	36
Item 6. Exhibits	36
Signatures	37

i

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	35,627,785	$	34,168,424
Oil, natural gas and NGL receivables		60,997,646		45,923,508
Derivative assets		—		2,403,597
Accounts receivable and other current assets		2,755,191		2,771,552
Total current assets		99,380,622		85,267,081
Property and equipment, net		475,498		267,111
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($218,108,900 and $115,200,109 excluded from depletion at March 31, 2025 and December 31, 2024, respectively)		2,271,330,491		2,048,711,692
Less: accumulated depreciation, depletion and impairment		(1,054,916,030)		(1,023,889,484)
Total oil and natural gas properties, net		1,216,414,461		1,024,822,208
Right-of-use assets, net		4,869,142		3,730,234
Derivative assets		—		565,938
Loan origination costs, net		4,727,986		5,262,191
Total assets	$	1,325,867,709	$	1,119,914,763
LIABILITIES, MEZZANINE EQUITY AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable	$	5,473,889	$	6,505,482
Other current liabilities		7,883,212		5,985,727
Derivative liabilities		3,165,270		254,654
Total current liabilities		16,522,371		12,745,863
Operating lease liabilities, excluding current portion		4,652,678		3,562,110
Derivative liabilities		1,988,387		879,559
Long-term debt		298,996,274		239,159,776
Other liabilities		41,670		72,920
Total liabilities		322,201,380		256,420,228
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units issued and outstanding as of March 31, 2025 and December 31, 2024)		316,396,786		316,002,143
Kimbell Royalty Partners, LP unitholders' equity:
Common units (93,396,488 units and 80,969,651 units issued and outstanding as of March 31, 2025 and December 31, 2024, respectively)		594,230,792		463,495,360
Class B units (14,491,540 units and 14,524,120 units issued and outstanding as of March 31, 2025 and December 31, 2024, respectively)		724,577		726,206
Total Kimbell Royalty Partners, LP unitholders' equity		594,955,369		464,221,566
Non-controlling interest in OpCo		92,314,174		83,270,826
Total unitholders' equity		687,269,543		547,492,392
Total liabilities, mezzanine equity and unitholders' equity	$	1,325,867,709	$	1,119,914,763

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

1

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2025		2024
Revenue
Oil, natural gas and NGL revenues	$	89,951,203	$	87,499,509
Lease bonus and other income		310,989		438,796
Loss on commodity derivative instruments, net		(6,053,426)		(5,704,361)
Total revenues		84,208,766		82,233,944
Costs and expenses
Production and ad valorem taxes		5,375,429		6,531,901
Depreciation and depletion expense		31,118,095		38,166,806
Impairment of oil and natural gas properties		—		5,963,575
Marketing and other deductions		4,501,767		4,562,944
General and administrative expense		9,636,743		9,447,881
Total costs and expenses		50,632,034		64,673,107
Operating income		33,576,732		17,560,837
Other expense
Interest expense		(6,621,526)		(7,301,330)
Other expense		(12,585)		—
Net income before income taxes		26,942,621		10,259,507
Income tax expense		1,089,426		922,568
Net income		25,853,195		9,336,939
Distribution and accretion on Series A preferred units		(5,202,862)		(5,256,287)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(2,773,757)		(890,849)
Distribution on Class B units		(14,492)		(20,847)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	17,862,084	$	3,168,956
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.20	$	0.04
Diluted	$	0.20	$	0.04
Weighted average number of common units outstanding
Basic		89,682,038		72,112,056
Diluted		127,947,257		116,539,624

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

2

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)

	Three Months Ended March 31, 2025
									Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Total
Balance at January 1, 2025		80,969,651	$	463,495,360		14,524,120	$	726,206	$	83,270,826	$	547,492,392
Common units issued for equity offering		11,500,000		163,574,081		—		—		—		163,574,081
Unit-based compensation		1,213,611		3,861,815		—		—		—		3,861,815
Restricted units repurchased for tax withholding		(315,276)		(5,080,939)		—		—		—		(5,080,939)
Conversion of Class B units to common units		32,580		186,790		(32,580)		(1,629)		(186,790)		(1,629)
Forfeiture of restricted units		(4,078)		(56,807)		—		—		—		(56,807)
Distributions to unitholders		—		(37,358,595)		—		—		(5,796,616)		(43,155,211)
Distribution and accretion on Series A preferred units		—		(4,504,013)		—		—		(698,849)		(5,202,862)
Distribution on Class B units		—		(14,492)		—		—		—		(14,492)
Change in ownership of consolidated subsidiaries, net		—		(12,252,997)		—		—		12,252,997		—
Net income		—		22,380,589		—		—		3,472,606		25,853,195
Balance at March 31, 2025		93,396,488	$	594,230,792		14,491,540	$	724,577	$	92,314,174	$	687,269,543

3

KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)

	Three Months Ended March 31, 2024
									Non-controlling
	Common Units		Amount		Class B Units		Amount		Interest in OpCo		Total
Balance at January 1, 2024		73,851,458	$	555,809,000		20,847,295	$	1,042,365	$	157,191,815	$	714,043,180
Restricted units repurchased for tax withholding		(292,484)		(4,914,149)		—		—		—		(4,914,149)
Unit-based compensation		1,087,502		3,684,080		—		—		—		3,684,080
Distributions to unitholders		—		(32,097,985)		—		—		(9,462,525)		(41,560,510)
Distribution and accretion on Series A preferred units		—		(4,108,784)		—		—		(1,147,503)		(5,256,287)
Distribution on Class B units		—		(20,847)		—		—		—		(20,847)
Change in ownership of consolidated subsidiaries, net		—		1,192,335		—		—		(1,192,335)		—
Net income		—		7,298,587		—		—		2,038,352		9,336,939
Balance at March 31, 2024		74,646,476	$	526,842,237		20,847,295	$	1,042,365	$	147,427,804	$	675,312,406

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

4

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2025		2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	25,853,195	$	9,336,939
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense		31,118,095		38,166,806
Impairment of oil and natural gas properties		—		5,963,575
Amortization of right-of-use assets		85,055		86,324
Amortization of loan origination costs		534,205		530,130
Unit-based compensation		3,861,815		3,684,080
Forfeiture of restricted units		(56,807)		—
Loss on derivative instruments, net of settlements		6,988,979		8,737,714
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(15,074,138)		4,316,194
Accounts receivable and other current assets		16,361		(1,149,530)
Accounts payable		(938,173)		312,764
Other current liabilities		1,825,602		(847,611)
Operating lease liabilities		(61,512)		(91,769)
Net cash provided by operating activities		54,152,677		69,045,616
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(343,600)		(69,763)
Proceeds from sale of property and equipment		12,415		—
Purchase of oil and natural gas properties		(222,618,800)		(21,605)
Net cash used in investing activities		(222,949,985)		(91,368)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering, net of issuance costs		163,574,081		—
Redemption of Class B contributions on converted units		(1,629)		—
Distribution to common unitholders		(37,358,595)		(32,097,985)
Distribution to OpCo unitholders		(5,796,616)		(9,462,525)
Distribution on Series A preferred units		(4,901,639)		(4,915,069)
Distribution on Class B units		(14,492)		(20,847)
Borrowings on long-term debt		74,136,498		4,959,776
Repayments on long-term debt		(14,300,000)		(13,800,000)
Payment of loan origination costs		—		(16,499)
Restricted units repurchased for tax withholding		(5,080,939)		(4,914,149)
Net cash provided by (used in) financing activities		170,256,669		(60,267,298)
NET INCREASE IN CASH AND CASH EQUIVALENTS		1,459,361		8,686,950
CASH AND CASH EQUIVALENTS, beginning of period		34,168,424		30,992,670
CASH AND CASH EQUIVALENTS, end of period	$	35,627,785	$	39,679,620
Supplemental cash flow information:
Cash paid for interest	$	4,679,794	$	6,696,655
Non-cash investing and financing activities:
Deemed distribution to Series A preferred units	$	394,643	$	394,643
Distribution on Series A preferred units in accounts payable	$	4,808,219	$	4,861,644
Recognition of tenant improvement asset	$	31,250	$	31,250
Right-of-use assets obtained in exchange for operating lease liabilities	$	1,223,963	$	—

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

5

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 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

6

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, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. 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 months ended March 31, 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.

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

7

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 March 31,
	2025		2024
Oil revenue	$	51,934,492	$	61,627,873
Natural gas revenue		25,637,994		14,554,573
NGL revenue		12,378,717		11,317,063
Total Oil, natural gas and NGL revenues	$	89,951,203	$	87,499,509

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.

As of March 31, 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

8

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 March 31,
	2025		2024
Beginning fair value of derivative instruments	$	1,835,322	$	14,046,982
Loss on commodity derivative instruments, net		(6,053,426)		(5,704,361)
Net cash received on settlements of derivative instruments		(935,553)		(3,033,353)
Ending fair value of derivative instruments	$	(5,153,657)	$	5,309,268

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

		March 31,		December 31,
Classification	Balance Sheet Location	2025		2024
Assets:
Current assets	Derivative assets	$	—	$	2,403,597
Long-term assets	Derivative assets		—		565,938
Liabilities:
Current liabilities	Derivative liabilities		(3,165,270)		(254,654)
Long-term liabilities	Derivative liabilities		(1,988,387)		(879,559)
		$	(5,153,657)	$	1,835,322

As of March 31, 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
April 2025 - December 2025	423,126	$	69.96	$	64.35	$	75.70
January 2026 - December 2026	595,680	$	67.75	$	63.33	$	70.78
January 2027 - March 2027	151,470	$	63.75	$	63.75	$	63.75

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
April 2025 - December 2025	3,863,771	$	3.64	$	3.50	$	3.74
January 2026 - December 2026	5,256,000	$	3.69	$	3.33	$	4.07
January 2027 - March 2027	1,321,920	$	4.46	$	4.46	$	4.46

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 March 31, 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.

9

● 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 months ended March 31, 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
March 31, 2025
Assets
Commodity derivative contracts	$	—	$	2,772,850	$	—	$	(2,772,850)	$	—
Liabilities
Commodity derivative contracts	$	—	$	(7,926,507)	$	—	$	2,772,850	$	(5,153,657)
December 31, 2024
Assets
Commodity derivative contracts	$	—	$	4,475,750	$	—	$	(1,506,215)	$	2,969,535
Liabilities
Commodity derivative contracts	$	—	$	(2,640,428)	$	—	$	1,506,215	$	(1,134,213)

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	March 31,		December 31,
	2025		2024
Oil and natural gas properties
Proved properties	$	2,053,221,591	$	1,933,511,583
Unevaluated properties		218,108,900		115,200,109
Less: accumulated depreciation, depletion and impairment		(1,054,916,030)		(1,023,889,484)
Total oil and natural gas properties	$	1,216,414,461	$	1,024,822,208
Costs not subject to depletion
Incurred in 2025	$	123,354,476
Incurred in 2024		—
Incurred in 2023		94,754,424
Prior		—
Total costs not subject to depletion	$	218,108,900

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

10

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

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

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 unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Depletion expense for the three months ended March 31, 2025 and 2024 was $31.0 million and $38.1 million, respectively and the average depletion rate per barrel was $13.52 and $15.24, 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 March 31, 2025 is 9.84 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating leases was 7.51% for the three months ended March 31, 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 months ended March 31, 2025 and 2024. The total operating lease expense recorded for the three months March 31, 2025 and 2024 was $0.2 million and $0.1 million, respectively.

11

Future minimum lease commitments as of March 31, 2025 were as follows:

	Total		2025		2026		2027		2028		2029		Thereafter
Operating leases	$	7,068,250	$	486,713	$	658,010	$	667,894	$	682,307	$	701,663	$	3,871,663
Less: Imputed Interest		(2,122,850)
Total	$	4,945,400

NOTE 9—LONG-TERM DEBT

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

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

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

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

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

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

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

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

12

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 three months ended March 31 2025, the Partnership borrowed an additional $74.1 million under the secured revolving credit facility and repaid approximately $14.3 million of the outstanding borrowings. As of March 31, 2025, the Partnership’s outstanding balance was $299.0 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2025.

As of March 31, 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 months ended March 31, 2025, the weighted average interest rate on the Partnership’s outstanding borrowings was 7.68%.

For additional information on our secured revolving credit facility, please read Note 17―Subsequent Events.

NOTE 10—PREFERRED UNITS

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

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

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

13

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

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

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

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 $1,121.92 per Series A preferred unit as of March 31, 2025, equal to 112% of par value.

The Series A preferred units had a carrying value of $316.4 million, including accrued distributions of $4.8 million, as of March 31, 2025, and a carrying value of $316.0 million, including accrued distributions of $4.9 million, as of December 31, 2024.

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

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

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, 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.

14

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 March 31, 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.

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
Q1 2024	$	0.49	May 2, 2024	May 13, 2024	May 20, 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 share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

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 March 31,
	2025		2024
Net income attributable to the Partnership	$	22,380,589	$	7,298,587
Changes in ownership of consolidated subsidiaries, net		(12,252,997)		1,192,335
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$	10,127,592	$	8,490,922

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.

15

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 March 31,
	2025		2024
Net income attributable to common units of Kimbell Royalty Partners, LP	$	17,862,084	$	3,168,956
Distribution and accretion on Series A preferred units		5,202,862		5,256,287
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		2,788,249		911,696
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	25,853,195	$	9,336,939
Weighted average number of common units outstanding:
Basic		89,682,038		72,112,056
Effect of dilutive securities:
Series A preferred units		21,566,025		21,566,025
Class B units		14,507,398		20,847,295
Restricted units		2,191,796		2,014,248
Diluted		127,947,257		116,539,624
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.20	$	0.04
Diluted	$	0.20	$	0.04

The calculation of diluted net income per share for the three months ended March 31, 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.

16

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 March 31, 2025 (1)	2,226,396	$	15.847	2.328 years

(1) As of March 31, 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 March 31, 2025 was 4.0%, compared to 9.0% for the three months ended March 31, 2024. The Partnership recorded an income tax expense of $1.1 million and $0.9 million for the three months ended March 31, 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 months ended March 31, 2025, the Partnership made payments to K3 Royalties in the amount of $30,000.

The Partnership received $41,156 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three months ended March 31, 2025.

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 March 31, 2025.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2025 in the preparation of its unaudited interim consolidated financial statements.

17

Long-Term Debt

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.

Drawdown on Secured Revolving Credit Facility

On May 1, 2025, the Partnership borrowed an additional $180.00 million under the secured revolving credit facility to fund the partial redemption of the preferred units. As of May 2, 2025, the Partnership’s outstanding balance on its secured revolving credit facility was $479.0 million.

Partial Redemption of 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.

Distributions

On May 8, 2025 the Board of Directors declared a quarterly cash distribution of $0.47 per common unit and OpCo common unit for the quarter ended March 31, 2025. The Partnership intends to pay this distribution on May 28, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on May 20, 2025.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.8 million for the quarter ended March 31, 2025. The Partnership intends to pay the distribution subsequent to May 8, 2025, and prior to the distribution on the common units and OpCo common units.

18

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;

19

● 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.

20

As of March 31, 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 March 31, 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 March 31, 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	10,831	52,162
Mid‑Continent	5,868,926	48,832	4,577	21,029
Terryville/Cotton Valley/Haynesville	1,428,907	7,919	3,918	16,372
Appalachian Basin	741,354	23,203	1,590	3,965
Bakken/Williston Basin	1,640,077	6,138	849	5,519
Eagle Ford	624,148	6,730	1,774	4,448
DJ Basin/Rockies/Niobrara	74,152	1,036	775	12,598
Other	3,232,560	36,693	1,187	15,478
Total	17,014,901	158,350	25,501	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 March 31, 2025:

Basin or Producing Region(1)	Gross DUCs	Gross Permits	Net DUCs	Net Permits
Permian Basin	503	491	2.64	2.55
Mid‑Continent	114	78	0.91	0.41
Terryville/Cotton Valley/Haynesville	40	22	0.37	0.16
Appalachian Basin	2	1	0.02	—
Bakken/Williston Basin	70	67	0.31	0.22
Eagle Ford	67	22	0.32	0.08
DJ Basin/Rockies/Niobrara	12	1	0.10	0.01
Total	808	682	4.67	3.43

(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.

21

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.

Quarterly Distributions

On May 8, 2025, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.47 per common unit representing limited partner interests in the Partnership (“common unit”) and common unit of the Operating Company (“OpCo common unit”) for the quarter ended March 31, 2025. We intend to pay the distributions on May 28, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on May 20, 2025.

We will pay a cash distribution on the Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) of approximately $4.8 million for the quarter ended March 31, 2025. We intend to pay the distribution subsequent to May 8, 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, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. 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.

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.

22

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”).

	Three Months Ended March 31, 2025				Three Months Ended March 31, 2024
	High		Low		High		Low
Oil ($/Bbl)	$	80.73	$	66.31	$	84.39	$	70.62
Natural gas ($/MMBtu)	$	9.86	$	2.93	$	13.20	$	1.25

On April 28, 2025, the West Texas Intermediate posted price for crude oil was $63.30 per Bbl and the Henry Hub spot market price of natural gas was $2.96 per MMBtu.

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

	Three Months Ended March 31,
	2025		2024
Oil ($/Bbl)	$	71.78	$	77.50
Natural gas ($/MMBtu)	$	4.14	$	2.15

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 4.3% to 575 active land rigs at March 31, 2025 compared to 601 active land rigs at March 31, 2024. The 575 active land rigs at March 31, 2025 increased slightly compared to 573 active land rigs at December 31, 2024. While the United States Rotary Rig count decreased year over year, overall production is not decreasing, indicating improved efficiencies are allowing sustained production from fewer rigs.

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

	March 31,
Basin or Producing Region	2025	2024
Permian Basin	49	50
Mid‑Continent	19	23
Terryville/Cotton Valley/Haynesville	6	9
Bakken/Williston Basin	8	6
Eagle Ford	5	8
DJ Basin/Rockies/Niobrara	1	1
Other	2	1
Total	90	98

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.

23

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

	Three Months Ended March 31,
	2025		2024
Revenue
Oil revenue	58	%	70	%
Natural gas revenue	29	%	17	%
NGL revenue	13	%	13	%
	100	%	100	%

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

24

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 March 31,
	2025		2024
Reconciliation of net income to Adjusted EBITDA and cash available for distribution on common units:
Net income	$	25,853,195	$	9,336,939
Depreciation and depletion expense		31,118,095		38,166,806
Interest expense		6,621,526		7,301,330
Income tax expense		1,089,426		922,568
EBITDA		64,682,242		55,727,643
Impairment of oil and natural gas properties		—		5,963,575
Unit-based compensation		3,861,815		3,684,080
Loss on derivative instruments, net of settlements		6,988,979		8,737,714
Consolidated Adjusted EBITDA		75,533,036		74,113,012
Adjusted EBITDA attributable to non-controlling interest		(10,145,611)		(16,179,650)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		65,387,425		57,933,362
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		4,051,203		5,234,705
Cash distribution on Series A preferred units		4,162,378		3,800,296
Distribution on Class B units		14,492		20,847
Cash available for distribution on common units	$	57,159,352	$	48,877,514

25

	Three Months Ended March 31,
	2025		2024
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	$	54,152,677	$	69,045,616
Interest expense		6,621,526		7,301,330
Income tax expense		1,089,426		922,568
Impairment of oil and natural gas properties		—		(5,963,575)
Amortization of right-of-use assets		(85,055)		(86,324)
Amortization of loan origination costs		(534,205)		(530,130)
Unit-based compensation		(3,861,815)		(3,684,080)
Forfeiture of restricted units		56,807		—
Loss on derivative instruments, net of settlements		(6,988,979)		(8,737,714)
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		15,074,138		(4,316,194)
Accounts receivable and other current assets		(16,361)		1,149,530
Accounts payable		938,173		(312,764)
Other current liabilities		(1,825,602)		847,611
Operating lease liabilities		61,512		91,769
EBITDA		64,682,242		55,727,643
Add:
Impairment of oil and natural gas properties		—		5,963,575
Unit-based compensation		3,861,815		3,684,080
Loss on derivative instruments, net of settlements		6,988,979		8,737,714
Consolidated Adjusted EBITDA		75,533,036		74,113,012
Adjusted EBITDA attributable to non-controlling interest		(10,145,611)		(16,179,650)
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP		65,387,425		57,933,362
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
Cash interest expense		4,051,203		5,234,705
Cash distribution on Series A preferred units		4,162,378		3,800,296
Distribution on Class B units		14,492		20,847
Cash available for distribution on common units	$	57,159,352	$	48,877,514

Factors Affecting the Comparability of Our Results to Our Historical Results

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

Ongoing Acquisition Activities

Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three months ended March 31, 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.

26

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 months ended March 31, 2025. 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 three months ended March 31, 2024. The impairment was primarily attributed to the decline in the 12-month average price of oil and natural gas for the three months ended March 31, 2024. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.

27

Results of Operations

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

	Three Months Ended March 31,
	2025		2024
Operating Results:
Revenue
Oil, natural gas and NGL revenues	$	89,951,203	$	87,499,509
Lease bonus and other income		310,989		438,796
Loss on commodity derivative instruments, net		(6,053,426)		(5,704,361)
Total revenues		84,208,766		82,233,944
Costs and expenses
Production and ad valorem taxes		5,375,429		6,531,901
Depreciation and depletion expense		31,118,095		38,166,806
Impairment of oil and natural gas properties		—		5,963,575
Marketing and other deductions		4,501,767		4,562,944
General and administrative expense		9,636,743		9,447,881
Total costs and expenses		50,632,034		64,673,107
Operating income		33,576,732		17,560,837
Other expense
Interest expense		(6,621,526)		(7,301,330)
Other expense		(12,585)		—
Net income before income taxes		26,942,621		10,259,507
Income tax expense		1,089,426		922,568
Net income		25,853,195		9,336,939
Distribution and accretion on Series A preferred units		(5,202,862)		(5,256,287)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests		(2,773,757)		(890,849)
Distribution on Class B units		(14,492)		(20,847)
Net income attributable to common units of Kimbell Royalty Partners, LP	$	17,862,084	$	3,168,956
Production Data:
Oil (Bbls)		749,744		804,589
Natural gas (Mcf)		6,618,953		7,413,069
Natural gas liquids (Bbls)		442,187		458,247
Combined volumes (Boe) (6:1)		2,295,090		2,498,348

Comparison of the Three Months Ended March 31, 2025 to the Three Months Ended March 31, 2024

Oil, Natural Gas and NGL Revenues

For the three months ended March 31, 2025, our oil, natural gas and NGL revenues were $90.0 million, an increase of $2.5 million from $87.5 million for the three months ended March 31, 2024. The increase in oil, natural gas and NGL revenues was primarily related to an increase in the average prices received for natural gas and NGLs for the three months ended March 31, 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 2,295,090 Boe or 25,501 Boe/d, for the three months ended March 31, 2025, a decrease of 203,258 Boe or 1,953 Boe/d, from 2,498,348 Boe or 27,454 Boe/d, for the three months ended March 31, 2024. The decrease in production for the three months ended March 31, 2025 was primarily attributable to 252,653 Boe or 2,776 Boe/d of prior period production recognized for the three months ended March 31, 2024, partially offset by production associated with the Boren Acquisition.

Our operators received an average of $69.27 per Bbl of oil, $3.87 per Mcf of natural gas and $27.99 per Bbl of NGL for the volumes sold during the three months ended March 31, 2025 compared to $76.60 per Bbl of oil, $1.96 per Mcf of natural gas and $24.70 per Bbl of NGL for the volumes sold during the three months ended March 31, 2024. These average prices received during the three months ended March 31, 2025 decreased 9.6% or $7.33 per Bbl of oil and increased 97.4% or $1.91 per Mcf of natural gas as compared to the three months ended March 31, 2024. This change is

28

consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 7.4% or $5.72 per Bbl of oil and an increase of 92.6% or $1.99 per Mcf of natural gas for the comparable periods.

Lease Bonus and Other Income

Lease bonus and other income for the three months ended March 31, 2025 remained relatively flat at $0.3 million, compared to $0.4 million for the three months ended March 31, 2024.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended March 31, 2025 included $7.0 million of mark-to-market losses and $0.9 million of gains on the settlement of commodity derivative instruments compared to $8.7 million of mark-to-market losses and $3.0 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2024. We recorded a mark-to-market losses for the three months ended March 31, 2025 and 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 March 31, 2025 were $5.4 million, a decrease of $1.1 million from $6.5 million for the three months ended March 31, 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 three months ended March 31, 2025 was $31.1 million, a decrease of $7.1 million from $38.2 million for the three months ended March 31, 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 $13.52 for the three months ended March 31, 2025, a decrease of $1.72 per barrel from the $15.24 average depletion rate per barrel for the three months ended March 31, 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 three months ended March 31, 2025. We recorded an impairment on our oil and natural gas properties of $6.0 million during the three months ended March 31, 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. As of March 31, 2024, the 12-month average prices of oil and natural gas were $77.48 per Bbl of oil and $2.45 per Mcf of natural gas. These prices represent a 14.8% and 58.8% decrease, respectively, from the 12-month average prices of oil and natural gas as of March 31, 2023, which were $90.97 per Bbl of oil and $5.95 per Mcf of natural gas.

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 March 31, 2025 remained relatively flat at $4.5 million, compared to $4.6 million for the three months ended March 31, 2024.

29

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2025 were $9.6 million, an increase of $0.2 million compared to $9.4 million for the three months ended March 31, 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 increase in general and administrative expenses was primarily attributable to an increase in unit-based compensation expense.

Interest Expense

Interest expense for the three months ended March 31, 2025 was $6.6 million, compared to $7.3 million for the three months ended March 31, 2024. The decrease in interest expense was primarily due to a 1.03% decrease in the weighted average interest rate on our outstanding borrowings for the three months ended March 31, 2025.

Income Tax Expense

We recorded an income tax expense of $1.1 million and $0.9 million for the three months ended March 31, 2025 and 2024, respectively.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operations and equity and debt financings, and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. On June 13, 2023, we entered into the A&R Credit Agreement (as defined below). On July 24, 2023, we entered into the First Amendment (as defined below) to the A&R Credit Agreement that, among other things, (i) decrease the frequency of and increase the threshold for excess cash determinations from $30.0 million to $50.0 million, and (ii) permit us to issue certain preferred equity interests. On December 8, 2023, we entered into the Second Amendment (as defined below) to the A&R Credit Agreement that, among other things, increase each of the borrowing base and aggregate elected commitments from $400.0 million to $550.0 million. See “Indebtedness” below for further discussion of our secured revolving credit facility.

Cash Distribution Policy

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

The Board of Directors approved the allocation of 25% of our cash available for distribution on common units for the first quarter of 2025 for the repayment of $16.9 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first quarter of 2025. With respect to future quarters, the Board of Directors intends to continue to allocate a portion of our cash available for distribution on common units to the repayment of outstanding borrowings under our secured revolving credit facility and may allocate such cash in other manners in which the Board of Directors determines to be appropriate at the time. The Board of Directors may further change its policy with respect to cash distributions in the future.

30

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

It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we completed the Boren Acquisition partially with net proceeds from the 2025 Equity Offering. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted. See “Recent Developments—Quarterly Distributions” above for discussion of our first quarter 2025 distributions.

Cash Flows

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

	Three Months Ended March 31,
	2025		2024
Cash Flow Data:
Net cash provided by operating activities	$	54,152,677	$	69,045,616
Net cash used in investing activities		(222,949,985)		(91,368)
Net cash provided by (used in) financing activities		170,256,669		(60,267,298)
Net increase in cash and cash equivalents	$	1,459,361	$	8,686,950

Operating Activities

Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2025 were $54.2 million, a decrease of $14.8 million compared to $69.0 million for the three months ended March 31, 2024.

Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2025 were $222.9 million compared to $0.1 million for the three months ended March 31, 2024. For the three months ended March 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition. For the three months ended March 31, 2024, cash flows used in investing activities included costs associated with an acquisition and the purchase of equipment.

Financing Activities

Cash flows provided by financing activities were $170.3 million for the three months ended March 31, 2025 compared to $60.3 million of cash flows used in financing activities for the three months ended March 31, 2024. Cash flows provided by financing activities for the three months ended March 31, 2025 consists primarily of $163.6 million in proceeds from the 2025 Equity Offering and $74.1 million of additional borrowings under our secured revolving credit facility, partially offset by $48.1 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $14.3 million used to repay borrowings under our secured revolving credit facility and $5.1 million of restricted units repurchased for tax withholding.

Cash flows used in financing activities for the three months ended March 31, 2024 consists primarily of $46.5 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $13.8 million used to repay borrowings under our secured revolving credit facility and $4.9 million of restricted units repurchased for tax withholding, partially offset by $5.0 million of additional borrowings under our secured revolving credit facility.

31

Indebtedness

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

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

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

For additional information on our secured revolving credit facility, please read Note 9―Long-Term Debt and Note 17―Subsequent Events to the unaudited interim consolidated financial statements included in this Quarterly Report.

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. The non-controlling interest, which represents OpCo common unitholders’, are not subject to federal income taxes. We estimate that a portion of our quarterly distributions will constitute a non-taxable reduction to the tax basis of unitholders’ common units. The reduced tax basis will increase unitholders’ capital gain (or decrease unitholders’ capital loss) when unitholders sell their common units. We currently believe that the portion that constitutes dividends for U.S. federal income tax purposes will be considered qualified dividends, subject to holding period and certain other conditions, which are subject to a tax rate of 0%, 15% or 20% depending on the income level and tax filing status of a unitholder for 2024. Our estimates regarding treatment of our distributions are based on currently available information only and are subject to change, including with respect to prior quarters.

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

New and Revised Financial Accounting Standards

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

32

Critical Accounting Policies and Related Estimates

There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our 2024 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2024 Form 10-K. As of March 31, 2025, we did not have any off-balance sheet arrangements. See Note 8—Leases to the unaudited interim consolidated financial statements for additional information regarding our operating leases.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

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

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

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

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2025, we had seven counterparties to our derivative contracts, which are also lenders under our secured revolving credit facility.

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

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. As of March 31, 2025, we had total borrowings outstanding under our secured revolving credit facility of $299.0 million. The impact of a 1% increase in the

33

interest rate on this amount of debt could result in an increase in interest expense of approximately $3.0 million annually, assuming that our indebtedness remained constant throughout the year.

Inflation

Inflation in the United States did not have a material impact on results of operations for the period from January 1, 2024 through March 31, 2025. However, inflation in wages and other costs has the potential to adversely affect our results of operations, cash flows and financial position by increasing our overall cost structure. In addition, the existence of inflation in the economy has the potential to result in higher interest rates, which could result in higher borrowing costs, supply shortages, increased costs of labor and other similar effects.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of the management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Disclosure controls and procedures are defined as controls designed to ensure that the information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon that evaluation, our General Partner’s management, including its principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

For a description of the Partnership’s legal proceedings, see Note 16—Commitments and Contingencies to the unaudited interim consolidated financial statements included in Part I of this Quarterly Report and incorporated by reference herein.

Item 1A. Risk Factors

In addition to the risks and uncertainties discussed in this Quarterly Report, included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, you should carefully consider the risks set out under the heading “Risk Factors” in Part I, Item 1A. Risk Factors in our 2024 Form 10-K. The following supplements and updates the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2024. These risk factors could materially affect our business, financial condition and results of operations. The volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

34

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. Several recent tariff announcements by the U.S. federal government have been followed by announcements of limited exemptions and temporary pauses. These actions are unprecedented, have caused substantial uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods and commodities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and increased volatility in commodity prices. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

Item 2. Unregistered Sales of Equity Securities

On February 12, 2025, we issued 3,162 common units to an existing OpCo unitholder in exchange for 3,162 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement, dated as of September 23, 2018, by and among us, the General Partner, the Operating Company and the other holders of OpCo common units and Class B units from time to time party thereto (the “Exchange Agreement”).

On February 14, 2025, we issued 29,418 common units to another existing OpCo unitholder in exchange for 29,418 OpCo common units and an equal number of Class B units pursuant to the terms of the Exchange Agreement.

The issuance of each of the foregoing securities was exempt from the registration requirements of the Securities Act in reliance upon Section 4(a)(2) of the Securities Act.

Period	Total Number of Common Units Purchased(1)	Average Price Paid per Common Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number of Common Units That May Yet be Purchased Under the Plans or Programs(2)
January 1, 2025 - January 31, 2025	—	$	—	—	—
February 1, 2025 - February 29, 2025	—	$	—	—	—
March 1, 2025 - March 31, 2025	315,276	$	14.99	—	—

(1) All of the common units shown above were withheld during the three months ended March 31, 2025 to satisfy tax-withholding obligations arising in conjunction with the vesting of restricted units. The required withholding is calculated using the closing sales price per common unit reported by the New York Stock Exchange on the date prior to the applicable vesting date.

(2) We did not have at any time during the quarter ended March 31, 2025, and currently do not have, a common unit repurchase program in place.

35

Item 5. Other Information

Rule 10b5-1 Plans

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

Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of Limited Partnership of Kimbell Royalty Partners, LP (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.2	—	Fifth Amended and Restated Agreement of Limited Partnership of Kimbell Royalty Partners, LP, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed September 13, 2023)
3.3	—	Certificate of Formation of Kimbell Royalty GP, LLC (incorporated by reference to Exhibit 3.3 to Kimbell Royalty Partners, LP’s Registration Statement on Form S-1 (File No. 333-215458) filed on January 6, 2017)
3.4	—	Third Amended and Restated Limited Liability Company Agreement of Kimbell Royalty Operating, LLC, dated as of September 13, 2023 (incorporated by reference to Exhibit 3.2 to Kimbell Royalty Partners, LP’s Current Report on Form 8-K filed on September 13, 2023)
10.1+	—	First Amendment to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on 10-Q filed on May 2, 2024)
10.2		Purchase and Sale Agreement, dated as of January 7, 2025, by and between Boren Minerals and Kimbell Royalty Partners, LP. (incorporated by reference to Exhibit 10.1 to Kimbell Royalty Partners, LP’s Current Report on Form 8 K filed on January 7, 2025)
31.1*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934
32.1**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS*	—	Inline XBRL Instance Document —the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	—	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	—	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	—	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* —filed herewith

** —furnished herewith

+ —Management contract or compensatory plan or arrangement.

36

SIGNATURES

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

	Kimbell Royalty Partners, LP
	By:	Kimbell Royalty GP, LLC
		its general partner
Date: May 8, 2025	By:	/s/ Robert D. Ravnaas
		Name:	Robert D. Ravnaas
		Title:	Chief Executive Officer and Chairman
			Principal Executive Officer

Date: May 8, 2025	By:	/s/ R. Davis Ravnaas
		Name:	R. Davis Ravnaas
		Title:	President and Chief Financial Officer
			Principal Financial Officer

37

EX-31.1

Exhibit 31.1

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

I, Robert D. Ravnaas, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:  

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;  

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and  

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and  

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):  

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and  

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.  

Date: May 8, 2025	/s/ Robert D. Ravnaas
	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Executive Officer)

EX-31.2

Exhibit 31.2

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

I, R. Davis Ravnaas, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:  

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;  

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and  

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and  

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):  

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and  

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.  

Date: May 8, 2025	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Financial Officer)

EX-32.1

Exhibit 32.1

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

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended March 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert D. Ravnaas, Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 8, 2025	/s/ Robert D. Ravnaas
	Chief Executive Officer and Chairman of the Board of Directors of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP (Principal Executive Officer)

EX-32.2

Exhibit 32.2

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

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

In connection with the Quarterly Report of Kimbell Royalty Partners, LP (the “Partnership”) on Form 10-Q for the fiscal quarter ended March 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, R. Davis Ravnaas, President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of  the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: May 8, 2025	/s/ R. Davis Ravnaas
	President and Chief Financial Officer of Kimbell Royalty GP, LLC, the general partner of Kimbell Royalty Partners, LP
	(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2025	May 02, 2025
Document Information
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2025
Document Transition Report	false
Entity Registrant Name	Kimbell Royalty Partners, LP
Securities Act File Number	001-38005
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-5505475
Entity Address, Address Line One	777 Taylor Street, Suite 810
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	945-9700
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	KRP
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Central Index Key	0001657788
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	Q1
Amendment Flag	false
Common Units
Document Information
Entity Common Stock, Shares Outstanding		93,396,488
Common Class B [Member]
Document Information
Entity Common Stock, Shares Outstanding		14,491,540

XML

CONSOLIDATED BALANCE SHEETS - USD ($)	Mar. 31, 2025	Dec. 31, 2024
Current assets
Cash and cash equivalents	$ 35,627,785	$ 34,168,424
Oil, natural gas and NGL receivables	60,997,646	45,923,508
Derivative assets		2,403,597
Accounts receivable and other current assets	2,755,191	2,771,552
Total current assets	99,380,622	85,267,081
Property and equipment, net	475,498	267,111
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting ($218,108,900 and $115,200,109 excluded from depletion at March 31, 2025 and December 31, 2024, respectively)	2,271,330,491	2,048,711,692
Less: accumulated depreciation, depletion and impairment	(1,054,916,030)	(1,023,889,484)
Total oil and natural gas properties, net	1,216,414,461	1,024,822,208
Right-of-use assets, net	4,869,142	3,730,234
Derivative assets		565,938
Loan origination costs, net	4,727,986	5,262,191
Total assets	1,325,867,709	1,119,914,763
Current liabilities
Accounts payable	5,473,889	6,505,482
Other current liabilities	7,883,212	5,985,727
Derivative liabilities	3,165,270	254,654
Total current liabilities	16,522,371	12,745,863
Operating lease liabilities, excluding current portion	4,652,678	3,562,110
Derivative liabilities	1,988,387	879,559
Long-term debt	298,996,274	239,159,776
Other liabilities	41,670	72,920
Total liabilities	322,201,380	256,420,228
Commitments and contingencies (Note 16)
Mezzanine equity:
Series A preferred units (325,000 units issued and outstanding as of March 31, 2025 and December 31, 2024)	316,396,786	316,002,143
Kimbell Royalty Partners, LP unitholders' equity:
Common units (93,396,488 units and 80,969,651 units issued and outstanding as of March 31, 2025 and December 31, 2024, respectively)	594,230,792	463,495,360
Class B units (14,491,540 units and 14,524,120 units issued and outstanding as of March 31, 2025 and December 31, 2024, respectively)	724,577	726,206
Total Kimbell Royalty Partners, LP unitholders' equity	594,955,369	464,221,566
Non-controlling interest in OpCo	92,314,174	83,270,826
Total unitholders' equity	687,269,543	547,492,392
Total liabilities, mezzanine equity and unitholders' equity	$ 1,325,867,709	$ 1,119,914,763

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)	Mar. 31, 2025	Dec. 31, 2024
CONSOLIDATED BALANCE SHEETS
Oil and natural gas properties excluded from depletion	$ 218,108,900	$ 115,200,109
Temporary equity, issued (in units)	325,000	325,000
Temporary equity, outstanding (in units)	325,000	325,000
Common units, issued (in units)	93,396,488	80,969,651
Common units, outstanding (in units)	93,396,488	80,969,651
Class B units, issued (in units)	14,491,540	14,524,120
Class B units, outstanding (in units)	14,491,540	14,524,120

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Loss on commodity derivative instruments, net	$ (6,053,426)	$ (5,704,361)
Total revenues	84,208,766	82,233,944
Costs and expenses
Production and ad valorem taxes	5,375,429	6,531,901
Depreciation and depletion expense	31,118,095	38,166,806
Impairment of oil and natural gas properties	0	5,963,575
Marketing and other deductions	4,501,767	4,562,944
General and administrative expense	9,636,743	9,447,881
Total costs and expenses	50,632,034	64,673,107
Operating income	33,576,732	17,560,837
Other expense
Interest expense	(6,621,526)	(7,301,330)
Other expense	(12,585)
Net income before income taxes	26,942,621	10,259,507
Income tax expense	1,089,426	922,568
Net income	25,853,195	9,336,939
Distribution and accretion on Series A preferred units	(5,202,862)	(5,256,287)
Net income and distributions and accretion on Series A preferred units attributable to non-controlling interests	(2,773,757)	(890,849)
Distribution on Class B units	(14,492)	(20,847)
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 17,862,084	$ 3,168,956
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Net income per unit attributable to common units Kimbell Royalty Partners, LP (basic) (in dollar per share)	$ 0.2	$ 0.04
Net income per unit attributable to common units Kimbell Royalty Partners, LP (diluted) (in dollar per share)	$ 0.2	$ 0.04
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)	89,682,038	72,112,056
Weighted average number of common units outstanding Diluted (in units)	127,947,257	116,539,624
Oil, natural gas and NGL revenues
Revenue	$ 89,951,203	$ 87,499,509
Lease bonus and other income
Revenue	$ 310,989	$ 438,796

XML

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY - USD ($)	Common Units	Class B Common Units	Non-controlling Interest in Opco	Total
Unitholders' capital, beginning balance at Dec. 31, 2023	$ 555,809,000	$ 1,042,365	$ 157,191,815	$ 714,043,180
Unitholders' capital, beginning balance (in units) at Dec. 31, 2023	73,851,458	20,847,295
Increase (Decrease) in Unitholders' Capital
Restricted units repurchased for tax withholding	$ (4,914,149)			(4,914,149)
Restricted units repurchased for tax withholding (in units)	(292,484)
Unit-based compensation	$ 3,684,080			3,684,080
Unit-based compensation (in units)	1,087,502
Distributions to unitholders	$ (32,097,985)		(9,462,525)	(41,560,510)
Distribution and accretion on Series A preferred units	(4,108,784)		(1,147,503)	(5,256,287)
Distribution on Class B units	(20,847)			(20,847)
Change in ownership of consolidated subsidiaries, net	1,192,335		(1,192,335)	(1,192,335)
Net income	7,298,587		2,038,352	9,336,939
Unitholders' capital, ending balance at Mar. 31, 2024	$ 526,842,237	$ 1,042,365	147,427,804	675,312,406
Unitholders' capital, ending balance (in units) at Mar. 31, 2024	74,646,476	20,847,295
Unitholders' capital, beginning balance at Dec. 31, 2024	$ 463,495,360	$ 726,206	83,270,826	$ 547,492,392
Unitholders' capital, beginning balance (in units) at Dec. 31, 2024	80,969,651	14,524,120		80,969,651
Increase (Decrease) in Unitholders' Capital
Common units issued for equity offering	$ 163,574,081			$ 163,574,081
Common units issued for equity offering (in units)	11,500,000
Conversion of Class B units to common units	$ 186,790	$ (1,629)	(186,790)	(1,629)
Conversion of Class B units to common units (in units)	32,580	(32,580)
Restricted units repurchased for tax withholding	$ (5,080,939)			(5,080,939)
Restricted units repurchased for tax withholding (in units)	(315,276)
Forfeiture of restricted units	$ (56,807)			(56,807)
Forfeiture of restricted units (in units)	(4,078)
Unit-based compensation	$ 3,861,815			3,861,815
Unit-based compensation (in units)	1,213,611
Distributions to unitholders	$ (37,358,595)		(5,796,616)	(43,155,211)
Distribution and accretion on Series A preferred units	(4,504,013)		(698,849)	(5,202,862)
Distribution on Class B units	(14,492)			(14,492)
Change in ownership of consolidated subsidiaries, net	(12,252,997)		12,252,997	12,252,997
Net income	22,380,589		3,472,606	25,853,195
Unitholders' capital, ending balance at Mar. 31, 2025	$ 594,230,792	$ 724,577	$ 92,314,174	$ 687,269,543
Unitholders' capital, ending balance (in units) at Mar. 31, 2025	93,396,488	14,491,540		93,396,488

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 25,853,195	$ 9,336,939
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion expense	31,118,095	38,166,806
Impairment of oil and natural gas properties	0	5,963,575
Amortization of right-of-use assets	85,055	86,324
Amortization of loan origination costs	534,205	530,130
Unit-based compensation	3,861,815	3,684,080
Forfeiture of restricted units	(56,807)
Loss on derivative instruments, net of settlements	6,988,979	8,737,714
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	(15,074,138)	4,316,194
Accounts receivable and other current assets	16,361	(1,149,530)
Accounts payable	(938,173)	312,764
Other current liabilities	1,825,602	(847,611)
Operating lease liabilities	(61,512)	(91,769)
Net cash provided by operating activities	54,152,677	69,045,616
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment	(343,600)	(69,763)
Proceeds from sale of property and equipment	12,415
Purchase of oil and natural gas properties	(222,618,800)	(21,605)
Net cash used in investing activities	(222,949,985)	(91,368)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity offering, net of issuance costs	163,574,081
Redemption of Class B contributions on converted units	(1,629)
Distribution to common unitholders	(37,358,595)	(32,097,985)
Distribution to OpCo unitholders	(5,796,616)	(9,462,525)
Distribution on Series A preferred units	(4,901,639)	(4,915,069)
Distribution on Class B units	(14,492)	(20,847)
Borrowings on long-term debt	74,136,498	4,959,776
Repayments on long-term debt	(14,300,000)	(13,800,000)
Payment of loan origination costs		(16,499)
Restricted units repurchased for tax withholding	(5,080,939)	(4,914,149)
Net cash provided by (used in) financing activities	170,256,669	(60,267,298)
NET INCREASE IN CASH AND CASH EQUIVALENTS	1,459,361	8,686,950
CASH AND CASH EQUIVALENTS, beginning of period	34,168,424	30,992,670
CASH AND CASH EQUIVALENTS, end of period	35,627,785	39,679,620
Supplemental cash flow information:
Cash paid for interest	4,679,794	6,696,655
Non-cash investing and financing activities:
Deemed distribution to Series A preferred units	394,643	394,643
Distribution on Series A preferred units in accounts payable	4,808,219	4,861,644
Recognition of tenant improvement asset	31,250	$ 31,250
Right-of-use assets obtained in exchange for operating lease liabilities	$ 1,223,963

XML

ORGANIZATION AND BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2025

ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION AND BASIS OF PRESENTATION

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 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, in March 2025 Israel carried out air strikes against Hamas, suggesting there is no indication on the extent of the ceasefire. 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.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2025

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 months ended March 31, 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.

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.

XML

REVENUE FROM CONTRACTS WITH CUSTOMERS

3 Months Ended

Mar. 31, 2025

REVENUE FROM CONTRACTS WITH CUSTOMERS

REVENUE FROM CONTRACTS WITH CUSTOMERS

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 March 31,
	2025		2024
Oil revenue	$	51,934,492	$	61,627,873
Natural gas revenue		25,637,994		14,554,573
NGL revenue		12,378,717		11,317,063
Total Oil, natural gas and NGL revenues	$	89,951,203	$	87,499,509

XML

ACQUISITIONS

3 Months Ended

Mar. 31, 2025

ACQUISITIONS

ACQUISITIONS

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.

XML

DERIVATIVES

3 Months Ended

Mar. 31, 2025

DERIVATIVES

DERIVATIVES

NOTE 5—DERIVATIVES

Commodity Derivatives

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

As of March 31, 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 March 31,
	2025		2024
Beginning fair value of derivative instruments	$	1,835,322	$	14,046,982
Loss on commodity derivative instruments, net		(6,053,426)		(5,704,361)
Net cash received on settlements of derivative instruments		(935,553)		(3,033,353)
Ending fair value of derivative instruments	$	(5,153,657)	$	5,309,268

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

		March 31,		December 31,
Classification	Balance Sheet Location	2025		2024
Assets:
Current assets	Derivative assets	$	—	$	2,403,597
Long-term assets	Derivative assets		—		565,938
Liabilities:
Current liabilities	Derivative liabilities		(3,165,270)		(254,654)
Long-term liabilities	Derivative liabilities		(1,988,387)		(879,559)
		$	(5,153,657)	$	1,835,322

As of March 31, 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
April 2025 - December 2025	423,126	$	69.96	$	64.35	$	75.70
January 2026 - December 2026	595,680	$	67.75	$	63.33	$	70.78
January 2027 - March 2027	151,470	$	63.75	$	63.75	$	63.75

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
April 2025 - December 2025	3,863,771	$	3.64	$	3.50	$	3.74
January 2026 - December 2026	5,256,000	$	3.69	$	3.33	$	4.07
January 2027 - March 2027	1,321,920	$	4.46	$	4.46	$	4.46

XML

FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2025

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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 March 31, 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 months ended March 31, 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
March 31, 2025
Assets
Commodity derivative contracts	$	—	$	2,772,850	$	—	$	(2,772,850)	$	—
Liabilities
Commodity derivative contracts	$	—	$	(7,926,507)	$	—	$	2,772,850	$	(5,153,657)
December 31, 2024
Assets
Commodity derivative contracts	$	—	$	4,475,750	$	—	$	(1,506,215)	$	2,969,535
Liabilities
Commodity derivative contracts	$	—	$	(2,640,428)	$	—	$	1,506,215	$	(1,134,213)

XML

OIL AND NATURAL GAS PROPERTIES

3 Months Ended

Mar. 31, 2025

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	March 31,		December 31,
	2025		2024
Oil and natural gas properties
Proved properties	$	2,053,221,591	$	1,933,511,583
Unevaluated properties		218,108,900		115,200,109
Less: accumulated depreciation, depletion and impairment		(1,054,916,030)		(1,023,889,484)
Total oil and natural gas properties	$	1,216,414,461	$	1,024,822,208
Costs not subject to depletion
Incurred in 2025	$	123,354,476
Incurred in 2024		—
Incurred in 2023		94,754,424
Prior		—
Total costs not subject to depletion	$	218,108,900

The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and

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

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

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 unit-of-production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Depletion expense for the three months ended March 31, 2025 and 2024 was $31.0 million and $38.1 million, respectively and the average depletion rate per barrel was $13.52 and $15.24, respectively.

XML

LEASES

3 Months Ended

Mar. 31, 2025

LEASES

LEASES

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 March 31, 2025 is 9.84 years.

Both the ROU operating lease assets and liabilities are recognized at the present value of the remaining lease payments over the lease term and do not include lease incentives. The Partnership’s leases do not provide an implicit rate that can readily be determined; therefore, the Partnership used a discount rate based on its incremental borrowing rate, which is determined by the information available in the secured revolving credit facility. The incremental borrowing rate reflects the estimated rate of interest that the Partnership would pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. The weighted average discount rate used for the operating leases was 7.51% for the three months ended March 31, 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 months ended March 31, 2025 and 2024. The total operating lease expense recorded for the three months March 31, 2025 and 2024 was $0.2 million and $0.1 million, respectively.

Future minimum lease commitments as of March 31, 2025 were as follows:

	Total		2025		2026		2027		2028		2029		Thereafter
Operating leases	$	7,068,250	$	486,713	$	658,010	$	667,894	$	682,307	$	701,663	$	3,871,663
Less: Imputed Interest		(2,122,850)
Total	$	4,945,400

XML

LONG-TERM DEBT

3 Months Ended

Mar. 31, 2025

LONG-TERM DEBT.

LONG-TERM DEBT

NOTE 9—LONG-TERM DEBT

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

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

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

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

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

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

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

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

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

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

During the three months ended March 31 2025, the Partnership borrowed an additional $74.1 million under the secured revolving credit facility and repaid approximately $14.3 million of the outstanding borrowings. As of March 31, 2025, the Partnership’s outstanding balance was $299.0 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2025.

As of March 31, 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 months ended March 31, 2025, the weighted average interest rate on the Partnership’s outstanding borrowings was 7.68%.

For additional information on our secured revolving credit facility, please read Note 17―Subsequent Events.

XML

PREFERRED UNITS

3 Months Ended

Mar. 31, 2025

PREFERRED UNITS

PREFERRED UNITS

NOTE 10—PREFERRED UNITS

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

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

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

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

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

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

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 $1,121.92 per Series A preferred unit as of March 31, 2025, equal to 112% of par value.

The Series A preferred units had a carrying value of $316.4 million, including accrued distributions of $4.8 million, as of March 31, 2025, and a carrying value of $316.0 million, including accrued distributions of $4.9 million, as of December 31, 2024.

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

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

XML

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

3 Months Ended

Mar. 31, 2025

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, 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 March 31, 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.

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
Q1 2024	$	0.49	May 2, 2024	May 13, 2024	May 20, 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 share on all matters to be voted upon by the shareholders. Holders of the common units and the Class B units generally vote together as a single class on all matters presented to the Kimbell Royalty Partners, LP unitholders for their vote or approval. Holders of Class B units do not have any right to receive dividends or distributions upon a liquidation or winding up of Kimbell Royalty Partners, LP. The Class B units and OpCo common units are exchangeable together into an equal number of common units of the Partnership.

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 March 31,
	2025		2024
Net income attributable to the Partnership	$	22,380,589	$	7,298,587
Changes in ownership of consolidated subsidiaries, net		(12,252,997)		1,192,335
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$	10,127,592	$	8,490,922

XML

EARNINGS PER COMMON UNIT

3 Months Ended

Mar. 31, 2025

EARNINGS PER COMMON UNIT

EARNINGS PER COMMON UNIT

NOTE 12—EARNINGS PER COMMON UNIT

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

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

	Three Months Ended March 31,
	2025		2024
Net income attributable to common units of Kimbell Royalty Partners, LP	$	17,862,084	$	3,168,956
Distribution and accretion on Series A preferred units		5,202,862		5,256,287
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		2,788,249		911,696
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	25,853,195	$	9,336,939
Weighted average number of common units outstanding:
Basic		89,682,038		72,112,056
Effect of dilutive securities:
Series A preferred units		21,566,025		21,566,025
Class B units		14,507,398		20,847,295
Restricted units		2,191,796		2,014,248
Diluted		127,947,257		116,539,624
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.20	$	0.04
Diluted	$	0.20	$	0.04

The calculation of diluted net income per share for the three months ended March 31, 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.

XML

UNIT-BASED COMPENSATION

3 Months Ended

Mar. 31, 2025

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION

NOTE 13—UNIT-BASED COMPENSATION

On May 1, 2024, the Board of Directors approved and adopted the first amendment to the Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as so amended, the “A&R LTIP”), which increased the number of common units available to be awarded under the A&R LTIP by 4,684,622 common units, which increased the total number of common units available to be awarded under the A&R LTIP, after taking into account previously awarded common units, to 6,765,012 common units. The Partnership’s A&R LTIP authorizes grants to its employees and directors. The restricted units issued under the Partnership’s A&R LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur.

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

The following table presents a summary of the Partnership’s unvested restricted units.

		Weighted		Weighted
		Average		Average
		Grant-Date		Remaining
		Fair Value		Contractual
	Units	per Unit		Term
Unvested at December 31, 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 March 31, 2025 (1)	2,226,396	$	15.847	2.328 years

(1) As of March 31, 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.

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2025

INCOME TAXES

INCOME TAXES

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 March 31, 2025 was 4.0%, compared to 9.0% for the three months ended March 31, 2024. The Partnership recorded an income tax expense of $1.1 million and $0.9 million for the three months ended March 31, 2025 and 2024, respectively.

XML

RELATED PARTY TRANSACTIONS

3 Months Ended

Mar. 31, 2025

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

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 months ended March 31, 2025, the Partnership made payments to K3 Royalties in the amount of $30,000.

The Partnership received $41,156 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three months ended March 31, 2025.

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2025

COMMITMENTS AND CONTINGENCIES.

COMMITMENTS AND CONTINGENCIES

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 March 31, 2025.

XML

SUBSEQUENT EVENTS

3 Months Ended

Mar. 31, 2025

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2025 in the preparation of its unaudited interim consolidated financial statements.

Long-Term Debt

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.

Drawdown on Secured Revolving Credit Facility

On May 1, 2025, the Partnership borrowed an additional $180.00 million under the secured revolving credit facility to fund the partial redemption of the preferred units. As of May 2, 2025, the Partnership’s outstanding balance on its secured revolving credit facility was $479.0 million.

Partial Redemption of 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.

Distributions

On May 8, 2025 the Board of Directors declared a quarterly cash distribution of $0.47 per common unit and OpCo common unit for the quarter ended March 31, 2025. The Partnership intends to pay this distribution on May 28, 2025 to common unitholders and OpCo common unitholders of record as of the close of business on May 20, 2025.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $4.8 million for the quarter ended March 31, 2025. The Partnership intends to pay the distribution subsequent to May 8, 2025, and prior to the distribution on the common units and OpCo common units.

XML

Insider Trading Arrangements	3 Months Ended
	Mar. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2025

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

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

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 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.

Recently adopted and Issued Accounting Pronouncements

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.

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.

XML

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

3 Months Ended

Mar. 31, 2025

REVENUE FROM CONTRACTS WITH CUSTOMERS

Schedule of disaggregation of revenues

	Three Months Ended March 31,
	2025		2024
Oil revenue	$	51,934,492	$	61,627,873
Natural gas revenue		25,637,994		14,554,573
NGL revenue		12,378,717		11,317,063
Total Oil, natural gas and NGL revenues	$	89,951,203	$	87,499,509

XML

DERIVATIVES (Tables)

3 Months Ended

Mar. 31, 2025

DERIVATIVES

Schedule of changes in fair value of derivative instruments

	Three Months Ended March 31,
	2025		2024
Beginning fair value of derivative instruments	$	1,835,322	$	14,046,982
Loss on commodity derivative instruments, net		(6,053,426)		(5,704,361)
Net cash received on settlements of derivative instruments		(935,553)		(3,033,353)
Ending fair value of derivative instruments	$	(5,153,657)	$	5,309,268

Schedule of derivative contracts

		March 31,		December 31,
Classification	Balance Sheet Location	2025		2024
Assets:
Current assets	Derivative assets	$	—	$	2,403,597
Long-term assets	Derivative assets		—		565,938
Liabilities:
Current liabilities	Derivative liabilities		(3,165,270)		(254,654)
Long-term liabilities	Derivative liabilities		(1,988,387)		(879,559)
		$	(5,153,657)	$	1,835,322

Schedule of commodity derivative contracts

Oil Price Swaps

	Notional	Weighted Average		Range (per Bbl)
	Volumes (Bbl)	Fixed Price (per Bbl)			Low	High
April 2025 - December 2025	423,126	$	69.96	$	64.35	$	75.70
January 2026 - December 2026	595,680	$	67.75	$	63.33	$	70.78
January 2027 - March 2027	151,470	$	63.75	$	63.75	$	63.75

Natural Gas Price Swaps

	Notional	Weighted Average		Range (per MMBtu)
	Volumes (MMBtu)	Fixed Price (per MMBtu)		Low		High
April 2025 - December 2025	3,863,771	$	3.64	$	3.50	$	3.74
January 2026 - December 2026	5,256,000	$	3.69	$	3.33	$	4.07
January 2027 - March 2027	1,321,920	$	4.46	$	4.46	$	4.46

XML

FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2025

FAIR VALUE MEASUREMENTS

Schedule of assets and liabilities measured at fair value on a recurring basis

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Effect of Counterparty Netting		Total
March 31, 2025
Assets
Commodity derivative contracts	$	—	$	2,772,850	$	—	$	(2,772,850)	$	—
Liabilities
Commodity derivative contracts	$	—	$	(7,926,507)	$	—	$	2,772,850	$	(5,153,657)
December 31, 2024
Assets
Commodity derivative contracts	$	—	$	4,475,750	$	—	$	(1,506,215)	$	2,969,535
Liabilities
Commodity derivative contracts	$	—	$	(2,640,428)	$	—	$	1,506,215	$	(1,134,213)

XML

OIL AND NATURAL GAS PROPERTIES (Tables)

3 Months Ended

Mar. 31, 2025

OIL AND NATURAL GAS PROPERTIES

Schedule of oil and natural gas properties

	March 31,		December 31,
	2025		2024
Oil and natural gas properties
Proved properties	$	2,053,221,591	$	1,933,511,583
Unevaluated properties		218,108,900		115,200,109
Less: accumulated depreciation, depletion and impairment		(1,054,916,030)		(1,023,889,484)
Total oil and natural gas properties	$	1,216,414,461	$	1,024,822,208
Costs not subject to depletion
Incurred in 2025	$	123,354,476
Incurred in 2024		—
Incurred in 2023		94,754,424
Prior		—
Total costs not subject to depletion	$	218,108,900

XML

LEASES (Tables)

3 Months Ended

Mar. 31, 2025

LEASES

Schedule of future minimum lease commitments

	Total		2025		2026		2027		2028		2029		Thereafter
Operating leases	$	7,068,250	$	486,713	$	658,010	$	667,894	$	682,307	$	701,663	$	3,871,663
Less: Imputed Interest		(2,122,850)
Total	$	4,945,400

XML

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables)

3 Months Ended

Mar. 31, 2025

Common units

Schedule of distributions approved by the Board of Directors

	Amount per		Date	Unitholder	Payment
	Common Unit		Declared	Record Date	Date
Q1 2025	$	0.47	May 8, 2025	May 20, 2025	May 28, 2025
Q1 2024	$	0.49	May 2, 2024	May 13, 2024	May 20, 2024

Schedule of changes in common unitholder's equity due to changes in ownership interest

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

	Three Months Ended March 31,
	2025		2024
Net income attributable to the Partnership	$	22,380,589	$	7,298,587
Changes in ownership of consolidated subsidiaries, net		(12,252,997)		1,192,335
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest	$	10,127,592	$	8,490,922

Common Units

Common units

Schedule of changes in Partnership's 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 March 31, 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.

XML

EARNINGS PER COMMON UNIT (Tables)

3 Months Ended

Mar. 31, 2025

EARNINGS PER COMMON UNIT

Schedule of (loss) earnings per common unit

	Three Months Ended March 31,
	2025		2024
Net income attributable to common units of Kimbell Royalty Partners, LP	$	17,862,084	$	3,168,956
Distribution and accretion on Series A preferred units		5,202,862		5,256,287
Net income attributable to non-controlling interests in OpCo and distribution on Class B units		2,788,249		911,696
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$	25,853,195	$	9,336,939
Weighted average number of common units outstanding:
Basic		89,682,038		72,112,056
Effect of dilutive securities:
Series A preferred units		21,566,025		21,566,025
Class B units		14,507,398		20,847,295
Restricted units		2,191,796		2,014,248
Diluted		127,947,257		116,539,624
Net income per unit attributable to common units of Kimbell Royalty Partners, LP
Basic	$	0.20	$	0.04
Diluted	$	0.20	$	0.04

XML

UNIT-BASED COMPENSATION (Tables)

3 Months Ended

Mar. 31, 2025

UNIT-BASED COMPENSATION

Schedule of unvested restricted stock activity

		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 March 31, 2025 (1)	2,226,396	$	15.847	2.328 years

(1) As of March 31, 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.

XML

ORGANIZATION AND BASIS OF PRESENTATION (Details)	3 Months Ended
	Mar. 31, 2025 segment
Segment Reporting
Number of operating segments	1
Number of reporting units	1

XML

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Oil, natural gas and NGL revenues
Revenue
Total revenue	$ 89,951,203	$ 87,499,509
Oil revenue
Revenue
Total revenue	51,934,492	61,627,873
Natural gas revenue
Revenue
Total revenue	25,637,994	14,554,573
NGL revenue
Revenue
Total revenue	$ 12,378,717	$ 11,317,063

XML

ACQUISITIONS - Acquisitions (Details) - Boren Minerals $ in Millions	Jan. 17, 2025 USD ($)
Acquisitions
Acquisition of mineral and royalty interests	$ 230.4
Proved properties	94.9
Unevaluated properties	$ 127.8

XML

DERIVATIVES (Details)	3 Months Ended
	Mar. 31, 2025 USD ($) $ / bbl MMBbls	Mar. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)
Change in fair values of derivative instruments
Beginning fair value of derivative instruments | $	$ 1,835,322	$ 14,046,982
Loss on commodity derivative instruments, net | $	(6,053,426)	(5,704,361)
Net cash received on settlements of derivative instruments | $	(935,553)	(3,033,353)
Ending fair value of derivative instruments | $	(5,153,657)	5,309,268
Assets:
Current assets | $			$ 2,403,597
Long-term assets | $			565,938
Liabilities:
Current liability | $	(3,165,270)		(254,654)
Long-term liability | $	(1,988,387)		(879,559)
Derivative assets (liabilities) | $	$ (5,153,657)	$ 5,309,268	$ 1,835,322
Oil Price Swaps - April 2025 - December 2025
Derivatives
Notional Volumes | MMBbls	423,126
Weighted Average Fixed Price	69.96
Oil Price Swaps - January 2026 - December 2026
Derivatives
Notional Volumes | MMBbls	595,680
Weighted Average Fixed Price	67.75
Oil Price Swaps - January 2027 - March 2027
Derivatives
Notional Volumes | MMBbls	151,470
Weighted Average Fixed Price	63.75
Natural Gas Price Swaps - April 2025 - December 2025
Derivatives
Notional Volumes | MMBbls	3,863,771
Weighted Average Fixed Price	3.64
Natural Gas Price Swaps - January 2026 - December 2026
Derivatives
Notional Volumes | MMBbls	5,256,000
Weighted Average Fixed Price	3.69
Natural Gas Price Swaps - January 2027 - March 2027
Derivatives
Notional Volumes | MMBbls	1,321,920
Weighted Average Fixed Price	4.46
Minimum | Oil Price Swaps - April 2025 - December 2025
Derivatives
Weighted Average Fixed Price	64.35
Minimum | Oil Price Swaps - January 2026 - December 2026
Derivatives
Weighted Average Fixed Price	63.33
Minimum | Oil Price Swaps - January 2027 - March 2027
Derivatives
Weighted Average Fixed Price	63.75
Minimum | Natural Gas Price Swaps - April 2025 - December 2025
Derivatives
Weighted Average Fixed Price	3.5
Minimum | Natural Gas Price Swaps - January 2026 - December 2026
Derivatives
Weighted Average Fixed Price	3.33
Minimum | Natural Gas Price Swaps - January 2027 - March 2027
Derivatives
Weighted Average Fixed Price	4.46
Maximum | Oil Price Swaps - April 2025 - December 2025
Derivatives
Weighted Average Fixed Price	75.7
Maximum | Oil Price Swaps - January 2026 - December 2026
Derivatives
Weighted Average Fixed Price	70.78
Maximum | Oil Price Swaps - January 2027 - March 2027
Derivatives
Weighted Average Fixed Price	63.75
Maximum | Natural Gas Price Swaps - April 2025 - December 2025
Derivatives
Weighted Average Fixed Price	3.74
Maximum | Natural Gas Price Swaps - January 2026 - December 2026
Derivatives
Weighted Average Fixed Price	4.07
Maximum | Natural Gas Price Swaps - January 2027 - March 2027
Derivatives
Weighted Average Fixed Price	4.46

XML

FAIR VALUE MEASUREMENTS (Details) - Commodity Derivative contract - USD ($)	Mar. 31, 2025	Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Commodity derivative contracts assets, Effect of Counterparty Netting	$ (2,772,850)	$ (1,506,215)
Commodity derivative contracts assets, Total		2,969,535
Commodity derivative contracts liabilities, Effect of Counterparty Netting	2,772,850	1,506,215
Commodity derivative contracts liabilities, Total	(5,153,657)	(1,134,213)
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Commodity derivative contracts assets, Total	2,772,850	4,475,750
Commodity derivative contracts liabilities, Total	$ (7,926,507)	$ (2,640,428)

XML

OIL AND NATURAL GAS PROPERTIES (Details) - USD ($)	Mar. 31, 2025	Dec. 31, 2024
OIL AND NATURAL GAS PROPERTIES
Proved properties	$ 2,053,221,591	$ 1,933,511,583
Unevaluated properties	218,108,900	115,200,109
Less: accumulated depreciation, depletion, and impairment	(1,054,916,030)	(1,023,889,484)
Total oil and natural gas properties, net	1,216,414,461	$ 1,024,822,208
Costs no subject to depletion
Incurred in 2025	123,354,476
Incurred in 2023	94,754,424
Total costs not subject to depletion	$ 218,108,900

XML

OIL AND NATURAL GAS PROPERTIES - Additional Information (Details)	3 Months Ended			12 Months Ended
	Mar. 31, 2025 USD ($) $ / bbl	Mar. 31, 2024 USD ($) $ / bbl $ / Mcf	Mar. 31, 2023 $ / bbl $ / Mcf	Mar. 31, 2024
Oil and natural gas properties
Net revenues discounting percentage at future	10.00%
Impairment of oil and natural gas properties | $	$ 0	$ 5,963,575
Depletion expense | $	$ 31,000,000	$ 38,100,000
Average depletion rate | $ / bbl	13.52	15.24
Crude Oil
Oil and natural gas properties
Average sales prices | $ / bbl		77.48	90.97
Percentage of average prices of oil and natural gas				14.80%
Natural Gas
Oil and natural gas properties
Average sales prices | $ / Mcf		2.45	5.95
Percentage of average prices of oil and natural gas				58.80%

XML

LEASES (Details) - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
LEASES
Operating lease weighted average remaining lease term	9 years 10 months 2 days
Operating lease weighted average discount rate (as a percent)	7.51%
Operating lease expense	$ 200,000	$ 100,000
2025	486,713
2026	658,010
2027	667,894
2028	682,307
2029	701,663
Thereafter	3,871,663
Total operating leases	7,068,250
Less Imputed Interest	(2,122,850)
Total	$ 4,945,400

XML

LONG-TERM DEBT (Details) - USD ($)		3 Months Ended
	Jun. 13, 2023	Mar. 31, 2025	Mar. 31, 2024	Dec. 08, 2023	Dec. 07, 2023	Jul. 24, 2023	Jul. 23, 2023
Long-term debt
Minimum percentage of proved reserves constituting borrowings based properties (as a percent)		75.00%
Debt extinguishment		$ 500,000
Borrowings of debt		74,136,498	$ 4,959,776
Repayment of debt		14,300,000	$ 13,800,000
A & R Credit Agreement
Long-term debt
Revolving credit facility maximum borrowings	$ 750,000,000
Borrowing base	400,000,000			$ 550,000,000	$ 400,000,000
Initial aggregate elected commitments amount	400,000,000			$ 550,000,000	$ 400,000,000
Minimum cash balance required to be applied weekly to prepay loans	50,000,000
Reduced cash balance as permitted by agreement	$ 0
Commitment fees (as a percent)	0.50%
Revolving credit facility outstanding		$ 299,000,000
Excess cash determinations						$ 50,000,000	$ 30,000,000
Interest rate on outstanding borrowings (as a percent)		7.68%
Borrowings of debt		$ 74,100,000
A & R Credit Agreement | Prime
Long-term debt
Margin (as a percent)		2.25%
A & R Credit Agreement | SOFR
Long-term debt
Margin (as a percent)		3.25%
A & R Credit Agreement | Minimum
Long-term debt
Current assets to current liabilities ratio		100.00%
A & R Credit Agreement | Minimum | SOFR
Long-term debt
Margin (as a percent)	2.75%
A & R Credit Agreement | Minimum | Base Rate
Long-term debt
Margin (as a percent)	1.75%
A & R Credit Agreement | Maximum
Long-term debt
Debt to EBITDAX ratio		350.00%
A & R Credit Agreement | Maximum | SOFR
Long-term debt
Margin (as a percent)	3.75%
A & R Credit Agreement | Maximum | Base Rate
Long-term debt
Margin (as a percent)	2.75%
Standby and/or commercial letters of credit
Long-term debt
Revolving credit facility maximum borrowings	$ 10,000,000

XML

PREFERRED UNITS - Other (Details)	Sep. 13, 2023 USD ($) D item $ / shares shares	Mar. 31, 2025 USD ($) $ / shares shares	Dec. 31, 2024 USD ($) shares
Preferred units
Temporary equity, issued (in units) | shares		325,000	325,000
Liquidation preference rate (in percentage)	10.00%
Increased distribution rate	20.00%
Carrying value		$ 316,396,786	$ 316,002,143
Series A Preferred Units
Preferred units
Percentage of cash distributions per annum	6.00%
The period after issuance securities become convertible	7 years
Ratio of return on investment to preferred units	1.2
Redemption price per share | $ / shares		$ 1,121.92
Percentage of redemption price per share		112.00%
Carrying value		$ 316,400,000	316,000,000
Preferred units accrued distributions		$ 4,800,000	$ 4,900,000
Number of members of board | item	2
Ownership required to grant the approval	66.67%
Series A Preferred Units | Series A Issuance Date
Preferred units
Minimum internal rate of return (as percent)	12.00%
Series A Preferred Units | On or after the fifth anniversary of the Series A Issuance Date and prior to the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	13.00%
Series A Preferred Units | On or after the sixth anniversary
Preferred units
Minimum internal rate of return (as percent)	14.00%
Series A Preferred Units | Minimum | The Partnership
Preferred units
Aggregate value of common units to be issued for preferred units	$ 10,000,000
Percentage of closing price to the conversion price	160.00%
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30
Affiliates of Apollo Capital Management, L.P. | LongPoint Minerals II, LLC
Preferred units
Series A preferred units issued | shares	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | Kimbell Royalty Operating, LLC
Preferred units
Temporary equity, issued (in units) | shares	325,000
Affiliates of Apollo Capital Management, L.P. | Series A Preferred Units | LongPoint Minerals II, LLC
Preferred units
Share price (in dollars per unit) | $ / shares	$ 1,000
Proceeds from the issuance of preferred units	$ 325,000,000
Series A Purchasers | Minimum
Preferred units
Percentage of closing price to the conversion price	130.00%
Conversion price of units | $ / shares	$ 15.07
Series A Purchasers | Series A Preferred Units | Minimum
Preferred units
Aggregate value of common units to be issued for preferred units	$ 10,000,000
Threshold trading days for transfer, assign or sale of units preceding the conversion notice | D	20
Threshold consecutive trading days for transfer, assign or sale of units preceding the conversion notice | D	30

XML

UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($)		3 Months Ended
	Jan. 09, 2025	Mar. 31, 2025	Mar. 31, 2024	Dec. 31, 2024
Common units
Units issued (in units)		93,396,488		80,969,651
Units outstanding (in units)		93,396,488		80,969,651
Repayment of debt		$ 14,300,000	$ 13,800,000
Capital rollforward
Unitholders' capital, beginning balance (in units)		80,969,651
Unitholders' capital, ending balance (in units)		93,396,488
Net income attributable to the Partnership		$ 22,380,589	7,298,587
Change in ownership of consolidated subsidiaries, net		(12,252,997)	1,192,335
Change from net income attributable to the Partnership's unitholders and transfers to non-controlling interest		$ 10,127,592	$ 8,490,922
Common Units
Common units
Units issued (in units)		93,396,488
Units outstanding (in units)		93,396,488		80,969,651
Capital rollforward
Unitholders' capital, beginning balance (in units)		80,969,651
Units issued for equity offering (in units)		11,500,000
Common units issued under the A&R LTIP (in units)		1,213,611
Restricted units repurchased for tax withholding (in units)		(315,276)
Conversion of Class B units to common units (in units)		32,580
Forfeiture of restricted units (in units)		(4,078)
Unitholders' capital, ending balance (in units)		93,396,488
Class B
Capital rollforward
Cash distributions (as a percent)		2.00%
Class B Common Units
Common units
Units outstanding (in units)		14,491,540
Capital rollforward
Unitholders' capital, beginning balance (in units)
Unitholders' capital, ending balance (in units)		14,491,540
Additional consideration paid per unit (in dollars per unit)		$ 0.05
2025 Equity Offering
Common units
Units issued (in units)	11,500,000
Proceeds from equity offering	$ 163,600,000
2025 Q1 Dividends
Capital rollforward
Cash distributions declared and paid (in dollars per unit)		$ 0.47
Dividend declared date		May 08, 2025
Dividend record date		May 20, 2025
Dividend payable date		May 28, 2025
2024 Q1 Dividends
Capital rollforward
Cash distributions declared and paid (in dollars per unit)			$ 0.49
Dividend declared date			May 02, 2024
Dividend record date			May 13, 2024
Dividend payable date			May 20, 2024

XML

EARNINGS PER COMMON UNIT (Details) - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Earnings per unit
Net income attributable to common units of Kimbell Royalty Partners, LP	$ 17,862,084	$ 3,168,956
Distribution and accretion on Series A preferred units	5,202,862	5,256,287
Diluted net income attributable to common units of Kimbell Royalty Partners, LP	$ 25,853,195	$ 9,336,939
Weighted average number of common units outstanding Basic (in units)	89,682,038	72,112,056
Weighted average number of common units outstanding Diluted (in units)	127,947,257	116,539,624
Net income per unit attributable to common units Kimbell Royalty Partners, LP (basic) (in dollar per share)	$ 0.2	$ 0.04
Net income per unit attributable to common units Kimbell Royalty Partners, LP (diluted) (in dollar per share)	$ 0.2	$ 0.04
Series A Preferred Units
Earnings per unit
Distribution and accretion on Series A preferred units	$ 5,202,862	$ 5,256,287
Class B
Earnings per unit
Net income attributable to non-controlling interests in OpCo and distribution on Class B units	$ 2,788,249	$ 911,696
Restricted Units
Earnings per unit
Weighted average number of common units outstanding (in units)	2,191,796	2,014,248
Series A Preferred Units
Earnings per unit
Weighted average number of common units outstanding (in units)	21,566,025	21,566,025
Class B Common Units
Earnings per unit
Weighted average number of common units outstanding (in units)	14,507,398	20,847,295

XML

UNIT-BASED COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended	12 Months Ended
	May 01, 2024	Mar. 31, 2025	Dec. 31, 2024
Restricted Units
Weighted Average Remaining Contractual Term
Exercisable, at end of period (in dollars per unit)		$ 15.847
Unrecognized compensation		$ 35.3
Long-Term Incentive Plan
Unit-based compensation
Additional common units authorized for issuance	4,684,622
Vesting period		3 years
Authorized issuance of units		6,765,012
Long-Term Incentive Plan | First Anniversary
Unit-based compensation
Vesting percent		33.30%
Long-Term Incentive Plan | Second Anniversary
Unit-based compensation
Vesting percent		33.30%
Long-Term Incentive Plan | Third Anniversary
Unit-based compensation
Vesting percent		33.30%
Long-Term Incentive Plan | Restricted Units
Unvested Units
Unvested at beginning of period (in units)		1,992,201
Awarded (in units)		1,213,611
Vesting (in units)		(975,338)
Forfeited (in units)		(4,078)
Unvested at end of period (in units)		2,226,396	1,992,201
Unvested Weighted Average Grant-Date Fair Value
Unvested at beginning of period (in dollars per unit)		$ 15.727
Awarded (in dollars per unit)		15.78
Vesting (in dollars per unit)		15.519
Forfeited (in dollars per unit)		15.633
Unvested at end of period (in dollars per unit)		$ 15.847	$ 15.727
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period		2 years 3 months 28 days	1 year 6 months 15 days

XML

INCOME TAXES - (Details) - USD ($)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
INCOME TAXES
Effective income tax rate (as a percent)	4.00%	9.00%
Income tax expense	$ 1,089,426	$ 922,568

XML

RELATED PARTY TRANSACTIONS (Details) - Related Party	3 Months Ended
	Mar. 31, 2025 USD ($)
K3 Royalties
Related Party Transactions
Payments made to related parties	$ 30,000
Rivercrest Capital Management, LLC
Related Party Transactions
Related party expense reimbursement received	$ 41,156

XML

SUBSEQUENT EVENTS (Details) - USD ($)			1 Months Ended	3 Months Ended
	May 07, 2025	May 01, 2025	May 08, 2025	Mar. 31, 2025	Mar. 31, 2024	May 02, 2025	Apr. 30, 2025	Dec. 08, 2023	Dec. 07, 2023	Jun. 13, 2023
Subsequent events
Borrowings on long-term debt				$ 74,136,498	$ 4,959,776
Subsequent Event | Series A Preferred Units
Subsequent events
Redemption of Series A preferred units	(162,500)
Percentage of Series A preferred units redeemed	50.00%
Conversion price of units	$ 1,121.92
Aggregate redemption price	$ 182,300,000
A & R Credit Agreement
Subsequent events
Borrowing base								$ 550,000,000	$ 400,000,000	$ 400,000,000
Initial aggregate elected commitments amount								$ 550,000,000	$ 400,000,000	$ 400,000,000
Borrowings on long-term debt				74,100,000
Revolving credit facility outstanding				$ 299,000,000
A & R Credit Agreement | Subsequent Event
Subsequent events
Borrowing base		$ 625,000,000					$ 550,000,000
Initial aggregate elected commitments amount		625,000,000					$ 550,000,000
Borrowings on long-term debt		$ 180,000,000
Revolving credit facility outstanding						$ 479,000,000
2025 Q1 Dividends
Subsequent events
Dividend declared date				May 08, 2025
Dividend payable date				May 28, 2025
Dividend record date				May 20, 2025
2025 Q1 Dividends | Subsequent Event
Subsequent events
Dividend declared date			May 08, 2025
Cash distributions declared (in dollars per unit)			$ 0.47
Dividend payable date			May 28, 2025
Dividend record date			May 20, 2025
2025 Q1 Dividends | Subsequent Event | Forecast | Series A Preferred Stock
Subsequent events
Member distributions			$ 4,800,000