Kimbell Royalty Partners KRP Form 10-Q filing Q1 FY2026

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PART I – FINANCIAL INFORMATION

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Item 1. Consolidated Financial Statements (Unaudited)

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS’ EQUITY

(Unaudited)

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KIMBELL ROYALTY PARTNERS, LP

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

(Unaudited)

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

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KIMBELL ROYALTY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

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KIMBELL ROYALTY PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Unless the context otherwise requi**res, references to “Kimbell Royalty Partners, LP,” the “Partnership,” or like terms refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” or “OpCo” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner. References to the “Sponsors” refer to affiliates of the Partnership’s founders, 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, 2025 (the “2025 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 and to make capital allocation decisions such as reinvestment in the business or repurchases under the common unit repurchase program, as discussed in Note 11—Unitholders’ Equity and Partnership Distributions. 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. These conflicts, along with the recent U.S. military action in Venezuela and Iran, 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

For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s 2025 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, 2026*.*

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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:

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NOTE 4**—**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.

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NOTE 5**—**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, 2026, 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:

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

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As of March 31, 2026, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

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Natural Gas Price Swaps

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NOTE 6—FAIR VALUE MEASUREMENTS

The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the unaudited interim consolidated balance sheets approximated fair value as of March 31, 2026 and December 31, 2025 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, 2026 and 2025.

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:

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NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

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The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. Unevaluated properties are assessed on a periodic basis for possible impairment based on the following factors, among others: economic and market conditions, operators’ intent to drill, remaining lease term, geological and geophysical evaluations, operators’ drilling results and activity, the assignment of proved reserves and the economic viability of operator development if

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

The Partnership did not record an impairment on its oil and natural gas properties for the three months ended March 31, 2026 and 2025.

Depletion expense for the three months ended March 31, 2026 and 2025 was $29.3 million and $31.0 million, respectively and the average depletion rate per barrel was $12.74 and $13.52, respectively.

NOTE 8—LEASES

The Partnership is the lessee on a lease of administrative office space used for its operations. 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, 2026 is 8.84 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, 2026.

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, 2026 and 2025. The total operating lease expense recorded for both the three months ended March 31, 2026 and 2025 was $0.2 million.

Future minimum lease commitments as of March 31, 2026 were as follows:

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NOTE 9—LONG-TERM DEBT

On December 16, 2025, the Partnership entered into a Second Amended and Restated Credit Agreement (the “Second A&R Credit Agreement”), which amended and restated our existing Amended and Restated Credit Agreement, dated as of June 13, 2023 (as amended on July 24, 2023, December 8, 2023, and May 1, 2025). The Second 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 $1.5 billion with an initial borrowing base of $625.0 million and an initial aggregate elected commitments amount of up to $625.0 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 Second A&R Credit Agreement to December 16, 2030 (provided, that if (a) any Permitted Preferred Units (as defined in the Second A&R Credit Agreement) that were outstanding on December 16, 2025 remain outstanding on May 3, 2030, and (b) Liquidity (as defined in the Second A&R Credit Agreement) would be less than 10% of the Loan Limit (as defined in the Second A&R Credit Agreement), or the

Debt to EBITDAX Ratio (as defined in the Second A&R Credit Agreement) would be greater than 3.00x, or any Borrowing Base Deficiency (as defined in the Second A&R Credit Agreement) would exist (in each case immediately after giving pro forma effect to the exercise of any put right in respect of such Permitted Preferred Units), the maturity date shall be May 3, 2030).

The secured revolving credit facility bears interest at a rate equal to, at the Partnership’s election, either (a) the Secured Overnight Financing Rate (as defined in the Second A&R Credit Agreement) plus an applicable margin that varies from 2.50% to 3.50% per annum or (b) a base rate plus an applicable margin that varies from 1.50% to 2.50% 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 developed reserves constituting borrowing base properties as set forth on the Partnership’s most recent reserve report. The borrowing base will be based on the value of the Partnership’s and certain of its material subsidiaries’ oil and natural gas properties. The borrowing base will be redetermined semi-annually on or about May 1 and November 1 of each year by the Lenders (as defined in the Second A&R Credit Agreement), with one interim unscheduled redetermination available to each of the Partnership and a group of certain Lenders between scheduled redeterminations during each calendar year. The first scheduled redetermination will be on or around May 1, 2026.

Customary borrowing base reductions and mandatory prepayments are required under the Second 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 Second A&R Credit Agreement) above $50.0 million and 10% of the Loan Limit 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 Second A&R Credit Agreement.

The Partnership is required to pay a commitment fee that varies from 0.375% to 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 Second 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 Second 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, calculated at the end of each fiscal quarter.

The Second 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 Second 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 Second A&R Credit Agreement, the Lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Second A&R Credit Agreement and any outstanding unfunded commitments may be terminated.

During the three months ended March 31, 2026, the Partnership borrowed an additional $12.8 million under the secured revolving credit facility and repaid approximately $13.4 million of the outstanding borrowings. As of March 31, 2026, the Partnership’s outstanding balance was $440.9 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of March 31, 2026.

As of March 31, 2026, borrowings under the secured revolving credit facility bore interest at SOFR plus a margin of 3.00% or the ABR (as defined in the Second A&R Credit Agreement) plus a margin of 2.00%. For the three months ended March 31, 2026, the weighted average interest rate on the Partnership’s outstanding borrowings was 6.70%.

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NOTE 10—PREFERRED UNITS

On May 7, 2025, the Partnership completed the redemption of 162,500 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,121.92 per Series A preferred unit for an aggregate redemption price of $182.3 million. As the consideration transferred by the Partnership to redeem the Series A preferred units was greater than the carrying value of the Series A preferred units as of the redemption date, a deemed dividend distribution of $24.0 million was recognized in unitholders’ equity and non-controlling interest during the year ended December 31, 2025.

The Series A preferred units are classified as mezzanine equity on the consolidated balance sheets due to certain redemption provisions being outside of the Partnership’s control. The Partnership has elected to accrete changes in the redemption value of the Series A preferred units over the period from the date of issuance to the earliest redemption date. The Series A preferred units were estimated to be redeemable at a price of $1,161.04 per Series A preferred unit as of March 31, 2026, equal to 116% of par value.

The Series A preferred units had a carrying value of $159.0 million, including accrued distributions of $2.4 million, as of March 31, 2026, and a carrying value of $158.8 million, including accrued distributions of $2.5 million, as of December 31, 2025.

NOTE 11—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of March 31, 2026, the Partnership had a total of 99,152,268 common units issued and outstanding and 9,122,322 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.

On March 6, 2026, the General Partner’s Board of Directors (the “Board of Directors”) approved of a common unit repurchase program (the “Repurchase Program”). The Repurchase Program allows the Partnership to acquire up to $100 million of its outstanding common units, excluding the 1% U.S. federal excise tax on certain repurchases of common units by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022. The Repurchase Program is authorized to extend through December 31, 2027 and the Partnership intends to purchase common units under the Repurchase Program opportunistically with cash on hand, free cash flow from operations or permitted borrowings under its secured revolving credit facility. The Repurchase Program may be temporarily suspended, modified, extended or discontinued by the Board of Directors. Purchases under the Repurchase Program may be made from time to time in the open market in compliance with Rule 10b-18 under the Exchange Act, or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.

Pursuant to the Repurchase Program, on March 19, 2026, the Partnership purchased 500,000 common units at an average purchase price of $14.60, for a total cost of $7.3 million, excluding excise tax. The units were retired and canceled immediately upon repurchase.

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

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(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 24, 2026.

The following table presents information regarding the common unit cash distributions approved by the Board of Directors for the periods presented:

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

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

Change in Ownership of Consolidated Subsidiaries

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

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NOTE 12—EARNINGS PER COMMON UNI****T

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:

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The calculation of diluted net income per unit for the three months ended March 31, 2026 and 2025 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

The Partnership’s Amended and Restated Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (the “A&R LTIP”), authorizes grants of up to an aggregate amount of 4,334,411 common units, after taking into account previously awarded common units, 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.

(1) As of March 31, 2026, there was $35.9 million of unrecognized compensation expense associated with unvested restricted units based on the weighted average grant date fair value per unit of $15.109.

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’, is 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, 2026 was 9.3%, compared to 4.0% for the three months ended March 31, 2025. The Partnership recorded an income tax expense of $0.7 million and $1.1 million for the three months ended March 31, 2026 and 2025, respectively.

On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “Act”), was enacted by the U.S. government. Key provisions of the Act effecting the Partnership include: (i) the permanent reduction of the corporate tax rate, (ii) the permanent extension of 100% bonus depreciation for qualified property, and (iii) modifications to the calculation for excess business interest expense limitation under § 163(j) to adjusted taxable income calculation on the business interest expense limitation.

In accordance with ASC Topic 740, Income Taxes, the Partnership has recognized the effects of the new tax law in the period of enactment. The impact of the Act for the quarter ended March 31, 2026 resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.

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, 2026, the Partnership made payments to K3 Royalties in the amount of $30,000.

The Partnership received $41,730 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the three months ended March 31, 2026.

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, 2026.

NOTE 17—SUBSEQUENT EVENTS

The Partnership has evaluated events that occurred subsequent to March 31, 2026 in the preparation of its unaudited interim consolidated financial statements.

Distributions

On May 7, 2026, the Board of Directors declared a quarterly cash distribution of $0.41 per common unit and OpCo common unit for the quarter ended March 31, 2026. The Partnership intends to pay this distribution on May 27, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on May 19, 2026.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $2.4 million for the quarter ended March 31, 2026. The Partnership intends to pay the distribution subsequent to May 7, 2026, and prior to the distribution on the common units and OpCo common units.

Drawdown on Secured Revolving Credit Facility

On April 3, 2026, the Partnership borrowed an additional $7.3 million under the secured revolving credit facility to fund the purchase of common units in accordance with the Repurchase Program. As of May 1, 2026, the Partnership’s outstanding balance on its secured revolving credit facility was $448.2 million.

Repurchase Program

Pursuant to the Repurchase Program, on April 2, 2026, the Partnership purchased 500,000 common units at an average purchase price of $14.70, for a total cost of $7.4 million, excluding excise tax. The units were retired and canceled immediately upon repurchase.

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, 2025 (the “2025 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.

Overview

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

As of March 31, 2026, 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 54% 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, 2026, 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 133,000 gross wells, including over 53,000 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, 2026:

(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 2025 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, 2026:

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

Recent Developments

Quarterly Distributions

On May 7, 2026, our General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.41 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, 2026. We intend to pay the distributions on May 27, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on May 19, 2026.

We will pay a cash distribution on the Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) of approximately $2.4 million for the quarter ended

March 31, 2026. We intend to pay the distribution subsequent to May 7, 2026 and prior to the distribution on the common units and OpCo common units.

Repurchase Program

On March 6, 2026, the Board of Directors approved of a common unit repurchase program (the “Repurchase Program”). The Repurchase Program allows us to acquire up to $100 million of our outstanding common units, excluding the 1% U.S. federal excise tax on certain repurchases of common units by publicly traded U.S. corporations enacted as part of the Inflation Reduction Act of 2022. The Repurchase Program is authorized to extend through December 31, 2027 and we intend to purchase common units under the Repurchase Program opportunistically with cash on hand, free cash flow from operations or permitted borrowings under our secured revolving credit facility. The Repurchase Program may be temporarily suspended, modified, extended or discontinued by the Board of Directors. Purchases under the Repurchase Program may be made from time to time in the open market in compliance with Rule 10b-18 under the Exchange Act, or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.

Pursuant to the Repurchase Program, on March 19, 2026, we purchased 500,000 common units at an average purchase price of $14.60, for a total cost of $7.3 million, excluding excise tax. On April 2, 2026, we purchased 500,000 common units at an average purchase price of $14.70, for a total cost of $7.4 million, excluding excise tax. All units were retired and canceled immediately upon repurchase.

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. These conflicts, along with the recent U.S. military action in Venezuela and Iran, 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.

Government Legislation

On July 4, 2025, Public Law No. 119-21, commonly referred to as the One Big Beautiful Bill Act (the “Act”), was enacted by the U.S. government. Key provisions of the Act effecting the us include: (i) the permanent reduction of the corporate tax rate, (ii) the permanent extension of 100% bonus depreciation for qualified property, and (iii) modifications to the calculation for excess business interest expense limitation under § 163(j) to adjusted taxable income calculation on the business interest expense limitation. In accordance with ASC Topic 740, Income Taxes, we have recognized the effects of the new tax law in the period of enactment. The impact of the Act for the quarter ended March 31, 2026 resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.

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”).

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On April 27, 2026, the West Texas Intermediate posted price for crude oil was $99.89 per Bbl and the Henry Hub spot market price of natural gas was $2.72 per MMBtu.

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

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 7.8% to 530 active land rigs at March 31, 2026 compared to 575 active land rigs at March 31, 2025. The 530 active land rigs at March 31, 2026 increased slightly compared to 527 active land rigs at December 31, 2025. The decrease in rig count is primarily related to domestic and international uncertainties, as noted above.

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

Sources of Our Revenue

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

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

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We have entered into oil and natural gas commodity derivative agreements, which extend through March 2028, 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.

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).

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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, 2026 and 2025 include the acquisition of mineral and royalty interests from Boren Minerals (the “Boren Acquisition”) in January 2025.

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

or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.

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

Impairment of Oil and Natural Gas Properties

Accounting standards require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience significant downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. Further, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation. We did not record an impairment on our oil and natural gas properties for the three months ended March 31, 2026 and 2025.

Results of Operations

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

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Comparison of the Three Months Ended March 31, 2026 to the Three Months Ended March 31, 2025

Oil, Natural Gas and NGL Revenues

For the three months ended March 31, 2026, our oil, natural gas and NGL revenues were $82.9 million, a decrease of $7.1 million from $90.0 million for the three months ended March 31, 2025. The decrease in oil, natural gas and NGL revenues was primarily related to a decrease in the average prices received for natural gas and NGLs, partially offset by and an increase in the average prices received for oil coupled with a slight increase in production volumes for the three months ended March 31, 2026, 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 2,296,970 Boe or 25,522 Boe/d, for the three months ended March 31, 2026, an increase of 1,880 Boe or 21 Boe/d, from 2,295,090 Boe or 25,501 Boe/d, for the three months ended March 31, 2025.

Our operators received an average of $69.55 per Bbl of oil, $3.15 per Mcf of natural gas and $23.93 per Bbl of NGL for the volumes sold during the three months ended March 31, 2026 compared to $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. The average price received during the three months ended March 31, 2026 increased 0.4% or $0.28 per Bbl of oil, which is consistent with prices experienced in the market, specifically when compared to the EIA average price increase of 1.3% or $0.96 per Bbl of oil. The average price received during the three months ended March 31, 2026 decreased 18.6% or

$0.72 per Mcf of natural gas as compared to the three months ended March 31, 2025 as a result of lower differentials in the Permian Basin.

Lease Bonus and Other Income

Lease bonus and other income for the three months ended March 31, 2026 was $1.3 million, an increase of $1.0 million compared to $0.3 million for the three months ended March 31, 2025. The increase in lease bonus and other income was due to a large number of lease bonuses received during the three months ended March 31, 2026.

Loss on Commodity Derivative Instruments

Loss on commodity derivative instruments for the three months ended March 31, 2026 included $18.8 million of mark-to-market losses and $0.1 million of gains on the settlement of commodity derivative instruments compared to $7.0 million of mark-to-market losses and $0.9 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2025. We recorded mark-to-market losses for the both the three months ended March 31, 2026 and 2025 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, 2026 were $5.9 million, an increase of $0.5 million compared to $5.4 million for the three months ended March 31, 2025. The increase in production and ad valorem taxes was primarily attributable to the increase in production volumes along with an increase in the average prices received for oil, partially offset by a decrease in the average prices received for natural gas and NGLs for the three months ended March 31, 2026.

Depreciation and Depletion Expense

Depreciation and depletion expense for the three months ended March 31, 2026 was $29.3 million, a decrease of $1.8 million from $31.1 million for the three months ended March 31, 2025. The decrease in depreciation and depletion expense was due to the gradual reduction in the depletable base of our 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 $12.74 for the three months ended March 31, 2026, a decrease of $0.78 per barrel from the $13.52 average depletion rate per barrel for the three months ended March 31, 2025. The decrease in the depletion rate was due to the gradual reduction in the depletable base of our oil and natural gas properties.

Marketing and Other Deductions

Our marketing and other deductions include product marketing expense, which is a post-production expense. Marketing and other deductions for the three months ended March 31, 2026 were $5.2 million, an increase of $0.7 million compared to $4.5 million for the three months ended March 31, 2025. The increase in marketing and other deductions was primarily related to the increase in production volumes along with an increase in the average prices received for oil, partially offset by a decrease in the average prices received for natural gas and NGLs for the three months ended March 31, 2026.

General and Administrative Expenses

General and administrative expenses for the three months ended March 31, 2026 were $9.4 million, a decrease of $0.2 million compared to $9.6 million for the three months ended March 31, 2025. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The decrease in general and administrative expenses was primarily attributable to an overall decrease in cash general and administrative expenses, partially offset by an increase in unit-based compensation expense.

Interest Expense

Interest expense for the three months ended March 31, 2026 was $8.2 million, compared to $6.6 million for the three months ended March 31, 2025. The increase in interest expense was primarily due to an increase in the overall debt balance as a result of additional borrowings to complete the partial redemption of the Series A preferred units.

Income Tax Expense

We recorded an income tax expense of $0.7 million and $1.1 million for the three months ended March 31, 2026 and 2025, 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 December 16, 2025, we entered into a Second Amended and Restated Credit Agreement (the “Second A&R Credit Agreement”). 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, cash used for repurchases of our common units under the Repurchase Program 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, cash used for repurchases of our common units under the Repurchase Program, 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 2026 for the repayment of $14.5 million in outstanding borrowings under our secured revolving credit facility during its determination of “available cash” for the first quarter of 2026. 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.

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 an underwritten public offering of 11,500,000 common units (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 2026 distributions.

Cash Flows

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

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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, 2026 were $49.4 million, a decrease of $4.8 million compared to $54.2 million for the three months ended March 31, 2025.

Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2026 were $0.01 million compared to $222.9 million for the three months ended March 31, 2025. For the three months ended March 31, 2026, cash flows used in investing activities primarily related the purchase of office equipment. For the three months ended March 31, 2025, cash flows used in investing activities primarily related to the Boren Acquisition.

Financing Activities

Cash flows used in financing activities were $56.2 million for the three months ended March 31, 2026 compared to $170.3 million of cash flows provided by financing activities for the three months ended March 31, 2025. Cash flows used in financing activities for the three months ended March 31, 2026 consists primarily of $42.6 million of distributions paid to holders of common units, OpCo common units, Series A preferred units and Class B units, $13.4 million used to repay borrowings under our secured revolving credit facility, $7.3 million used to repurchase common units and $5.2 million of restricted units repurchased for tax withholding, partially offset by $12.8 million of additional borrowings under our secured revolving credit facility.

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.

Indebtedness

On December 16, 2025, we entered into a Second A&R Credit Agreement, which amended and restated our existing Amended and Restated Credit Agreement, dated as of June 13, 2023 (as amended on July 24, 2023, December 8, 2023, and May 1, 2025). The Second 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 $1.5 billion with an initial borrowing base of $625.0 million and an initial aggregate elected commitments amount of up to $625.0 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 Second A&R Credit Agreement to December 16, 2030.

For additional information on our Second A&R Credit Agreement, please read Note 9―Long-Term Debt to the unaudited interim consolidated financial statements included in this Quarterly Report.

Tax Matters

Even though we are organized as a limited partnership under state law, we are treated as a corporation for United States federal income tax purposes. Accordingly, we are subject to United States federal income tax at regular corporate rates on our net taxable income. The non-controlling interest, which is held by the OpCo common unitholders, is 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 2026. 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.

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 2025 Form 10-K.

Contractual Obligations and Off-Balance Sheet Arrangements

There have been no significant changes to our contractual obligations previously disclosed in our 2025 Form 10-K. As of March 31, 2026, 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, 2026, 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, 2026, we had total borrowings outstanding under our secured revolving credit facility of $440.9 million. The impact of a 1% increase in the interest rate on this amount of debt could result in an increase in interest expense of approximately $4.4 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, 2025 through March 31, 2026. 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, 2026.

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, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

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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 2025 Form 10-K. These risk factors could materially affect our business, financial condition and results of operations. The volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks. Further, these risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities

On March 2, 2026, we issued 5,369,218 common units to an existing OpCo unitholder in exchange for 5,369,218 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”).

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.

(1) All of the common units shown above were withheld during the three months ended March 31, 2026 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) On March 6, 2026, the Board of Directors approved of a common unit repurchase program (the “Repurchase Program”). The Repurchase Program allows us to acquire up to $100 million of our outstanding common units. The Repurchase Program is authorized to extend through December 31, 2027 and we intend to purchase common units under the Repurchase Program opportunistically with cash on hand, free cash flow from operations or permitted borrowings under our secured revolving credit facility. The Repurchase Program may be temporarily suspended, modified, extended or discontinued by the Board of Directors. Purchases under the Repurchase Program may be made from time to time in the open market in compliance with Rule 10b-18 under the Exchange Act, or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.

(3) Pursuant to the Repurchase Program, on March 19, 2026, we purchased 500,000 common units at an average purchase price of $14.60, for a total cost of $7.3 million, excluding excise tax. The units were retired and canceled immediately upon repurchase.

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).

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Item 6. Exhibits

Line item Description

— 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) — 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) — 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) — 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) — Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934 — Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) under the Securities Exchange Act of 1934 — Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 — Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 — 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 — Inline XBRL Taxonomy Extension Schema Document — Inline XBRL Taxonomy Extension Calculation Linkbase Document — Inline XBRL Taxonomy Extension Definition Linkbase Document — Inline XBRL Taxonomy Extension Label Linkbase Document — Inline XBRL Taxonomy Extension Presentation Linkbase Document — Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* —filed herewith

** —furnished herewith

​ ​ ​

​ ​ ​ ​ Kimbell Royalty Partners, LP

​ ​

​ ​ By: Kimbell Royalty GP, LLC

​ ​ ​ its general partner

​ ​ ​

Date: May 7, 2026 ​ By: /s/ Robert D. Ravnaas

​ ​ ​ Name: Robert D. Ravnaas

​ ​ ​ Title: Chief Executive Officer and Chairman

​ ​ ​ ​ Principal Executive Officer

​

​

​ ​ ​

Date: May 7, 2026 ​ ​ ​ By: /s/ R. Davis Ravnaas

​ ​ ​ Name: R. Davis Ravnaas

​ ​ ​ Title: President and Chief Financial Officer

​ ​ ​ ​ Principal Financial Officer

​

​

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