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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 12 Months Ended
Dec. 31, 2025
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES  
Basis of Presentation

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

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.

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.
Segment Reporting

Segment Reporting

The Partnership has one business activity as the owner of mineral and royalty interests and operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (the “CODM”) in deciding how to allocate resources and assess performance. The segment participates in activities and derives revenue as described in the organization section on a consolidated basis. The Partnership’s CODM is our Chief Operating Officer.

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

Significant segment expenses of the Partnership include production and ad valorem taxes, depreciation and depletion expense, impairment of oil and natural gas properties, marketing and other deductions, general and administrative expense and interest expense. Other segment items included in net income are income tax expenses and

other income (expense) line items. All significant segment expenses and other segment items are presented individually in the consolidated statements of operations.
Cash and Cash Equivalents

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

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

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

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 to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.
Loan Origination Costs

Loan Origination Costs

Certain direct costs associated with the Partnership’s secured 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

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 are no exploratory activities pending determination, and no exploratory costs were charged to expense for the years ended December 31, 2025, 2024 or 2023.
Earnings (Loss) Per Unit

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

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

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 had no 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 did not recognize any interest or penalty expense related to uncertain tax positions.
Concentration of Credit Risk

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’s top 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

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

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

Revenue from Contracts with Customers

The Partnership has the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Partnership owns a mineral or royalty interest. Revenue is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

The Partnership’s oil, natural gas and NGL sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a mineral or royalty interest sells the Partnership’s proportionate share of oil, natural gas and NGL production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and NGL. In this scenario, the Partnership recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation.

The following table disaggregates the Partnership’s oil, natural gas, and NGL revenues for the following periods:

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​

​

​

​

​

​

​

​

​

​

​

​

Year Ended December 31, 

​

​

2025

  ​ ​ ​

2024

  ​ ​ ​

​

2023

​

​

(In thousands)

Oil revenue

​

$

195,471

​

$

215,539

​

$

183,151

Natural gas revenue

​

​

78,364

​

​

50,156

​

​

59,525

NGL revenue

​

​

43,638

​

​

38,910

​

​

24,910

Total Oil, natural gas and NGL revenues

​

$

317,473

​

$

304,605

​

$

267,586

​

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 for one to four 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

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 and Issued 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.