Kimbell Royalty Partners, LP

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 Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and all intercompany balances are eliminated in consolidation. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

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. 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

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 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

Management Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of third party operated royalty income related to expected sales volumes and prices, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, the carrying value of oil and natural gas interests and recoverability of costs of unevaluated properties.

The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information.

The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

Cash and Cash Equivalents

The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.

At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits.

Oil, Natural Gas and NGL Receivables

Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. The Partnership estimates and records an allowance for expected credit losses when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2025 and 2024, no allowance for expected credit losses is deemed necessary based upon a review of current receivables and the lack of historical write offs.

Commodity Derivatives

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions.

Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statements of operations within gain (loss) on commodity derivative instruments.

Property and Equipment

Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three toseven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.

Loan Origination Costs

Certain direct costs associated with the Partnership’ssecured revolving credit facility are presented in the consolidated balance sheets as loan origination costs. These costs are amortized over the term of the secured revolving credit facility and included as a component of interest expense in the consolidated statements of operations.

Oil and Natural Gas Properties

The Partnership follows the full-cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.

The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. For discussion regarding impairment on the Partnership’s oil and natural gas properties see Note 6—Oil and Natural Gas Properties.

The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the years ended December 31, 2025, 2024 or 2023.

The Partnership assesses all unevaluated properties on periodic basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: economic and market conditions; operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved 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.

Due to the nature of the Partnership’s mineral and royalty interests, there areno exploratory activities pending determination, andno exploratory costs were charged to expense for the years ended December 31, 2025, 2024 or 2023.

Earnings (Loss) Per Unit

Basic earnings (loss) 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 12—Unit Based Compensation) and potential conversion of Series A Cumulative Convertible Preferred Units representing limited partner interests in the Partnership (the “Series A preferred units”) and Class B units representing limited partnership interests in the Partnership (“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.

Other Current Liabilities

Other current liabilities consist primarily of accrued bonuses, accrued interest, revenue payable, accrued tax liability, ad valorem taxes and short-term operating lease liabilities.

Income Taxes

As discussed further in Note 1—Organization and Basis of Presentation, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period of the enactment date. Valuation allowances are established when it is more likely than not that some or all of the deferred tax assets will not be realized.

Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership hadno uncertain tax positions at December 31, 2025, 2024 and 2023.

The Partnership recognizes interest and penalties related to uncertain tax positions in income tax expense. For the years ended December 31, 2025, 2024 and 2023, the Partnership didnot recognize any interest or penalty expense related to uncertain tax positions.

Concentration of Credit Risk

The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations.

During the years ended December 31, 2025, 2024 and 2023, the Partnership’stop purchaser accounted for approximately 7.7%,9.1% and 6.7%, respectively, of oil, natural gas and NGL sales revenue.

Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. While the Partnership does not require the counterparties to its derivative contracts to post collateral, the Partnership does evaluate the credit standing of such counterparties as they deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information.

Non-controlling Interest

Non-controlling interest in the accompanying consolidated financial statements represents OpCo common units, as defined in Note 10—Unitholders’ Equity and Partnership Distributions. The Partnership’s Class B units are exchangeable on a one-for-one basis, together with an equal number of OpCo common units, for common units of the Partnership. When OpCo common unitholders’ relative ownership interest in the Operating Company changes, adjustments to non-controlling interest and common unitholder equity will occur. Because these changes in the Partnership’s ownership interest in the Operating Company did not result in a change of control, the transactions were accounted for as equity transactions under ASC Topic 810, “Consolidation.”

Change in Ownership of Consolidated Subsidiaries

The Partnership’s relative ownership interest in OpCo can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, conversion of Class B to common units, repurchases of common units and distribution rights paid on the Partnership’s units. These changes in ownership percentage result in adjustments to non-controlling interest and common unitholders' equity.

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:

Transaction Price Allocated to Remaining Performance Obligations

The Partnership’s right to revenue does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s revenue contracts.

Contract Balances

Under the Partnership’s revenue contracts, it would have the right to receive revenue from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s revenue contracts do not give rise to contract assets or liabilities under GAAP.

Prior-Period Performance Obligations

The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received forone tofour months after the date production is delivered, and as a result, the Partnership is required to estimate the revenue to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2025, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and NGL contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

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. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5—Fair Value Measurements for further discussion of the Partnership’s fair value measurements.

Recently Adopted Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” The amendments in this update apply to all entities that are subject to Topic 740, Income Taxes. The Partnership adopted ASU 2023-09 for the year ended December 31, 2025, on a prospective basis. The Partnership’s annual income tax disclosures have been expanded to provide additional transparency into the drivers of its effective tax rate and cash taxes paid, net of refunds received, to various jurisdictions. The disclosures reflect new quantitative thresholds and expanded presentation requirements introduced under ASU 2023-09. See Note 13—Income Taxes, for additional information.

Recently Issued Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40).” The amendments in this update apply to all public business entities. The amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The amendments in this Update should be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this Update or (2) retrospectively to any or all prior periods presented in the financial statements. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity.

NOTE 3—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 4—DERIVATIVES

Commodity Derivatives

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

At December 31, 2025, the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

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

At December 31, 2025, the Partnership’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

Natural Gas Price Swaps

NOTE 5—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 consolidated balance sheets approximated fair value at December 31, 2025 and 2024 due to their short-term duration and variable interest rates that approximate prevailing interest rates as of each reporting period. As a result, these financial assets and liabilities are not discussed below.

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 years ended December 31, 2025 and 2024.

The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets.

The following tables summarize the Partnership’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy:

Asset and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions.

NOTE 6**—**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 year ended December 31, 2025. As a result of its full cost ceiling analysis, the Partnership recorded an impairment on its oil and natural gas

properties of $62.1 million and $18.2 million during the years ended December 31, 2024 and 2023. The impairments were primarily attributed to the decline in the 12-month average price of oil and natural gas.

Depletion expense for the years ended December 31, 2025, 2024 and 2023 was $124.3 million, $134.7 million and $96.1 million, respectively. For the years ended December 31, 2025, 2024 and 2023, the average depletion rate per barrel was $13.22, $14.80 and $13.03, respectively.

NOTE 7—LEASES

The Partnership is the lessee on a lease of administrative office space used for its operations. On December 26, 2024, the Partnership modified its existing operating leases associated with its main office used for operations. The modified operating lease includes $1.2 million of rent expense that had not yet commenced as of December 31, 2024. The lease commenced in February 2025, expanding the current office space and extending the lease term to 2035, with the exclusive right and option to renew and extend the lease at the expiration of the primary term. The Partnership does not have any material lessor arrangements. Substantially all of the Partnership’s leases are long-term operating leases with fixed payment terms and will now 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 consolidated balance sheets. Short-term operating lease liabilities are included in other current liabilities. The weighted average remaining lease term as of December 31, 2025 is 9.09 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 lease was 7.51% for the year ended December 31, 2025.

Operating lease expense is recognized on a straight-line basis over the lease term and is included in general and administrative expense in the accompanying consolidated statements of operations. The total operating lease expense recorded for the years ended December 31, 2025, 2024 and 2023 was $0.7 million, $0.6 million and $0.6 million, respectively.

Maturities of lease liabilities as of December 31, 2025 are as follows:

NOTE 8—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 thesecured 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 year ended December 31, 2025, the Partnership borrowed an additional $695.6 million under the secured revolving credit facility and repaid approximately $493.3 million of the outstanding borrowings. As of December 31, 2025, the Partnership’s outstanding balance was $441.5 million and there wereno outstanding letters of credit under the secured revolving credit facility. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2025.

As of December 31, 2025, 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 year ended December 31, 2025, the weighted average interest rate on the Partnership’s outstanding borrowings was 7.57%.

NOTE 9—PREFERRED UNITS

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

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.

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

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

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

The Series A preferred units are redeemable at the option of the Series A Purchasers after seven years from the effective date of the Series A preferred unit purchase agreement, August 2, 2023. The Series A preferred units may be

redeemed by the Partnership at any time or in the event of a change of control. The Series A preferred units may be redeemed for a cash amount per Series A preferred unit equal to the product of (a) the number of outstanding Series A preferred units multiplied by (b) the greatest of (i) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve the Minimum IRR (as defined below), (ii) an amount (together with all prior distributions made in respect of such Series A preferred unit) necessary to achieve a return on investment equal to 1.2 times with respect to such Series A preferred unit and (iii) the Series A issue price plus accrued and unpaid distributions.

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

The Series A preferred units are classified as mezzanine equity on the consolidated 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 $1,146.25 per Series A preferred unit as of December 31, 2025, equal to 115% of par value.

The Series A preferred units had a carrying value of $158.8 million, including accrued distributions of $2.5 million, as of December 31, 2025, and a carrying value of $316.0 million, including accrued distributions of $4.9 million, as of December 31, 2024.

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

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

NOTE 10—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has issued units representing limited partner interests. As of December 31, 2025, the Partnership had a total of 93,396,488 common units issued andoutstanding and 14,491,540 Class B units 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 common units of the Operating Company (“OpCo common units”). The Operating Company ultimately used the net proceeds of the 2025 Equity Offering to fund the Boren Acquisition.

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

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

The following table presents information regarding the common unit cash distributions approved by the General Partner’s Board of Directors (the “Board of Directors”) for the periods presented:

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

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

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

Change in Ownership of Consolidated Subsidiaries

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

NOTE 11—EARNINGS (LOSS) PER COMMON UNIT

Basic earnings (loss) 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 12) 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 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 (loss) per common unit:

The calculation of diluted net income per share for the years ended December 31, 2025 and 2023 includes the conversion of Series A preferred units to common units and Class B units to common units calculated using the “if-converted” method and units of unvested restricted units calculated using the treasury stock method. The calculation of diluted net loss per share for the year ended December 31, 2024 excludes the conversion of Series A preferred units to common units, the conversion of Class B units to common units and unvested restricted units because their inclusion in the calculation would be anti-dilutive.

NOTE 12—UNIT-BASED COMPENSATION

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

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NOTE 13—INCOME TAXES

The Partnership’s income tax (benefit) expense is based on the estimated annual effective tax rate. The Partnership incurred a benefit of $1.3 million and $0.8 million for the years ended December 31, 2025 and 2024, respectively, and expense of $3.8 million for the year ended December 31, 2023. The Partnership has filed all tax returns to date that are currently due.

The components of income tax (benefit) expense are summarized as follows:

The Partnership’s income tax (benefit) expense differs from the amount derived by applying the statutory federal rate to pre-tax income principally due the effect of the following items:

The Partnership’s effective income tax benefit was 1.33% for the year ended December 31, 2025. The Partnership earned income before taxes, as calculated under GAAP, for the current year and is recording a current income tax benefit of $1.3 million.

A significant reconciling item in the Partnership’s effective tax rate reconciliation relates to income allocated to non-controlling interest, which is held by the OpCo common unitholders and not subject to federal income taxes. While 100% of the Partnership’s income is included in its consolidated pre-tax book income, for U.S. federal income tax purposes, the Partnership is only subject to tax on the portion of Partnership income allocated to them as the C corporation. The income allocated to OpCo common unitholders is not taxable to the Partnership, resulting in a reduction to its effective tax rate compared to the statutory rate. This reconciling item reflects the exclusion from the Partnership’s taxable income of earnings allocated to OpCo common unitholders, consistent with the partnership tax rules under which income is taxed at the partner level and not at the partnership entity level.

The Partnership recorded a decrease in the valuation allowance related to federal deferred tax assets and an increase in the valuation allowance related to state deferred tax assets. These changes were primarily attributable to a true-up of prior-year amounts following the finalization of tax returns, resulting from changes in estimates the year ended December 31, 2025.

The Partnership’s effective tax rate is increased by state and local income taxes, which are imposed in addition to federal income taxes. The impact varies based on the mix of income earned in states with different tax rates and the availability of state tax credits and incentives.

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 affecting 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 September 30, 2025, the reporting period that included the enactment date, resulted in a reduction to current income tax expense, primarily due to the changes to the 163(j) interest limitation.

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below.

The tax years ended December 31, 2022 through 2025 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and its federal and state loss carryforward will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $24.5 million on the deferred tax assets.

Income taxes paid (net of refunds) were paid in the following jurisdictions:

Other than cash payments or refunds for U.S. federal income tax shown in the table above, Oklahoma ($1.5 million refund), New Mexico ($0.7 million refund) and Texas ($0.3 million paid) are the only jurisdictions in which the Partnership received or paid more than 5% of total cash taxes in the year presented.

As of December 31, 2025, the Partnership hasnot recorded a reserve for any uncertain tax positions.

NOTE 14—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 year ended December 31, 2025, the Partnership made payments to K3 Royalties in the amount of $120,000.

John Wynne, the son of Mitch S. Wynne, acts as the Partnership’s agent at Higginbotham Insurance & Financial Services, which provides director and officer insurance to the Partnership. John Wynne derived a commission of approximately $25,700 for the year ended December 31, 2025, for the placement of the Partnership’s insurance coverage. The Partnership’s annual premium expense was approximately $583,300 for the year ended December 31, 2025.

The Partnership received $187,031 in reimbursements from Rivercrest Capital Management, LLC for shared operating expenses for the year ended December 31, 2025.

NOTE 15—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 December 31, 2025.

NOTE 16—SUBSEQUENT EVENTS

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

Distributions

On February 26, 2026, the Board of Directors declared a quarterly cash distribution of $0.37 per common unit and $0.357502 per OpCo common unit for the quarter ended December 31, 2025. The Partnership intends to pay this distribution on March 25, 2026 to common unitholders and OpCo common unitholders of record as of the close of business on March 18, 2026.

As to the Partnership, $0.012498 excluded from the OpCo common unit distribution corresponds to a tax refund received by the Partnership in the fourth quarter of 2025. Under the limited liability company agreement of the Operating Company, the Partnership does not reimburse the Operating Company for federal income tax refunds received by the Partnership.

The Partnership will pay a quarterly cash distribution on the Series A preferred units of approximately $2.5 million for the quarter ended December 31, 2025. The Partnership intends to pay the distribution subsequent to February 26, 2026 and prior to the distribution on the common units and OpCo common units.

Executive Bonus and LTIP Issuance

On February 24, 2026, the Conflicts and Compensation Committee of the Board of Directors approved short-term incentive cash bonuses for executive officers of approximately $2.4 million and the issuance of 1,216,990 restricted units to its employees and directors.

NOTE 17—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows:

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows:

Results of Operations from Oil, Natural Gas and NGL Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership’s oil, natural gas and NGL operations.

The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves. The estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2025, 2024 and 2023. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC.

Proved Oil, Natural Gas and NGL Reserve Quantities

Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

A Boe conversion ratio of six thousand cubic feet per barrel (6mcf/Bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a price equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below:

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure

The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties is as follows (in thousands):

Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2025, 2024 and 2023 were $65.34, $75.48 and $78.22 per barrel for crude oil and $3.39, $2.13 and $2.64 per Mcf for natural gas, respectively.

Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands):