Kimbell Royalty Partners, LP

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 asingle operating andreportable 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*.*

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:

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). Theoil 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

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:

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

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

Oil Price Swaps

Natural Gas Price Swaps

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.

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:

NOTE 7—OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

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 didnot 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:

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 3.00 x, 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 tozero 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%.

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 andoutstanding 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:

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

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:

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:

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 inone-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.

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.