TXO Partners, L.P.

To the Unitholders and Board of Directors

TXO Partners, L.P. and TXO Partners GP, LLC:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of TXO Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2025 and 2024, the related consolidated statements of operations, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2012.

February 26, 2026

Consolidated Statements of Partners’ Capital

Notes to Consolidated Financial Statements

Organization and Summary of Significant Accounting Policies

TXO Partners, L.P. (TXO Partners or the Partnership) is an independent oil and gas company that was formed as a Delaware limited partnership in January 2012 (with an effective inception of operations at January 18, 2012). The operations of TXO Partners are governed by the provisions of the partnership agreement, as amended, executed by the general partner, TXO GP, LLC (the General Partner) and the limited partners. The General Partner is the manager and operator of TXO Partners. The General Partner is managed by the board of directors and executive officers of our General Partner. The board of directors is made up of nine directors, each of whom was appointed by MorningStar Oil & Gas, LLC (“MSOG”), as the sole member of our General Partner. Pursuant to applicable provisions of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and the limited partnership agreement, the partners have no liability for the debts, obligations and liabilities of TXO Partners, except as expressly required in the limited partnership agreement or the Delaware Act. TXO Partners will remain in existence unless and until dissolved in accordance with the terms of the partnership agreement.

TXO Partners’ assets include its investment in an unincorporated joint venture. TXO Partners owns 50% of the joint venture, and TXO Partners is the manager of the joint venture. The joint venture is governed by a Member Management Committee (MMC) and is comprised ofsix representatives, three from each group, with each group havingone voting member. All matters that come before the MMC require the unanimous consent of the voting members. On the last day of each calendar quarter, the joint venture distributes all excess cash to the members based on their ownership percentage of 50% each, except for earnings from the note receivable which is owned 5% by TXO Partners. The joint venture’s properties are located primarily in the San Juan Basin of New Mexico and Colorado and the Permian Basin of West Texas and New Mexico.

TXO Partners also has a wholly-owned subsidiary, MorningStar Operating LLC which owns oil and gas assets primarily in the San Juan Basin of New Mexico and Colorado, the Permian Basin of West Texas and New Mexico and the Williston Basin of Montana and North Dakota.

In accordance with oil and gas accounting guidance, we account for our undivided interest in our investment in the joint venture using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of the joint venture. As discussed above, we own 50% of the oil and gas assets, liabilities, revenues and expenses, but we only own 5% of the note receivable from related party and related interest income.

The accompanying consolidated financial statements include the financial statements of TXO Partners, its wholly-owned subsidiaries and our undivided interests in the joint venture. All significant intercompany balances and transactions have been eliminated in consolidation.

Reorganization and Public Listing of Common Units

In January 2023, we completed a series of reorganization transactions in conjunction with publicly listing our common units on the New York Stock Exchange. These included the following transactions (the Reorganization Transactions):

•

We effectuated a one-for-25.33 reverse unit split;

•

We caused the exchange of all outstanding Series 5 preferred units for 10,644,484 common units, resulting in our capital structure to consist of a single class of common units;

•

All limited partner holders party to our amended and restated agreement of limited partnership contributed all of the outstanding equity interests in us to a new parent company, MorningStar Partners II, L.P., a Delaware limited partnership (“MSP II”) in exchange for equity interests in MSP II; and

•

We amended our governing documents to, among other things, (i) change our name from “MorningStar Partners, L.P.” to “TXO Partners, L.P.” and (ii) reflect TXO GP, LLC, a Delaware limited liability company, as our new non-economic general partner.

As a result of these transactions, the capital structure has been reflected as if the new number of units had been in place for all periods presented.

Basis of Presentation

The accounts of TXO Partners are presented in the accompanying financial statements. These financial statements have been prepared in accordance with U.S. GAAP.

Liquidity

Our primary sources of liquidity are cash provided by operating activities, borrowings under our credit facility and equity raised from partners. Short-term liquidity needs are provided by borrowings under our Credit Facility. We believe that we have a sufficient combination of resources and operating flexibility to ensure that we meet our current obligations and our future debt covenants for at least the next 12 months from the date of issuance of these financial statements. See Note 4.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

•

estimates of proved reserves and related estimates of the present value of future revenues;

•

the recoverability and fair value of oil and gas properties;

•

estimates of revenue earned but not yet received;

•

asset retirement obligations;

•

valuation of derivative instruments; and

•

legal and environmental risks and exposure.

Property and Equipment

We follow the successful efforts method of accounting, capitalizing costs of successful exploratory wells and expensing costs of unsuccessful exploratory wells. Exploratory geological and geophysical costs are expensed as incurred. All developmental costs are capitalized. We generally pursue acquisition and development of proved reserves as opposed to exploration activities. All of the proved property costs reflected in the accompanying balance sheet are from TXO Partners, our wholly-owned subsidiary, MorningStar Operating LLC, and our 50% share of the joint venture’s proved properties as of December 31, 2025 and 2024. Proved properties balances include costs of$10.1 million at December 31, 2025 and$8.5 million at December 31, 2024 related to wells in process of drilling. Successful drill well costs are transferred to proved properties generally within one month of the well completion date.

Depreciation, depletion, and amortization (DD&A) of proved producing properties is computed on the unit-of-production method based on estimated proved oil and gas reserves. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives which range fromt hree to seven years, except for the gas processing plant which is being depreciated over an estimated useful life of 14 years. Repairs and maintenance are expensed, while renewals and betterments are generally capitalized.

If conditions indicate that proved properties may be impaired, the carrying value of property is compared to management’s future estimated pre-tax undiscounted cash flow from properties generally aggregated on a field-level basis. If impairment is necessary, the asset carrying value is written down to fair value, typically a discounted present value of estimated future cash flows. Cash flow pricing estimates are based on estimated reserves and production information and pricing assumptions that management believes are reasonable. As a result of the Cross Timbers Transactions, we evaluated the recoverability of the Cross Timbers oil and gas assets and recorded an impairment of long-lived assets of$42.4 million for the year ended December 31, 2025 related to our assets in the Permian Basin. During the year ended December 31, 2024, we didnot recognize an impairment of long-lived assets. During the year end ended December 31, 2023, we recognized an impairment of long-lived assets of$223.4 million for our assets in the Permian Basin, that is within our Cross Timbers joint venture, primarily due to a lower net commodity price environment and increased costs as well as a change in our development plans to reduce the duration of the proved undeveloped reserves from five years totwo years. We recorded the impairment to accumulated depreciation, depletion and amortization on the balance sheets.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion, and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized in the current period.

If the fair value for asset retirement obligation can be reasonably estimated, the liability is recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. The retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to proved properties on the balance sheet. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of operations. See Note 7.

Cash and Cash Equivalents

Cash equivalents are considered to be all highly liquid investments having an original maturity of three months or less.

Fair Value of Financial Instruments

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

Income Taxes

TXO Partners is a limited partnership treated as a partnership for federal income tax purposes, with income tax liabilities and/or benefits of the Partnership passed through to the partners. As such, we are not a taxable entity for federal income tax purposes and we do not directly pay federal income tax.

For state tax purposes, we are subject to the Revised Texas Franchise Tax (commonly referred to as the "Texas Margin Tax"). Although the Texas Margin Tax is not considered a traditional state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. Due to immateriality, income taxes related to the Texas margin tax have been included in general and administrative expenses on the statement of operations and no deferred tax amounts were calculated.

Derivatives

We opportunistically use derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. We record all derivatives on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. See Note 9.

We do not designate these derivative contracts as cash flow hedges. Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil and gas revenues. Settlements of derivatives are included in cash flows from operating activities.

Revenue Recognition

Oil, gas and natural gas liquids revenues are recognized upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for the product. See Note 13 for further discussion.

Loss Contingencies

When management determines that it is probable that an asset has been impaired or a liability has been incurred, we accrue our best estimate of the loss if it can be reasonably estimated. Any legal costs related to litigation are expensed as incurred.

Unit-Based Compensation

We recognize compensation related to all unit-based awards in the financial statements based on their estimated grant-date fair value. We estimate expected forfeitures and we recognize compensation expense only for those awards expected to vest. Compensation expense is amortized on a straight-line basis over the estimated service period. All compensation is recognized by the time the award vests. See Note 12.

Segments

We evaluated how TXO Partners is organized and managed and have identified onlyone reporting segment, which is the exploration and production of oil, natural gas and natural gas liquids. The operating segments within the reportable segment have been aggregated based on the similarity of their economic and other characteristics, including product type and services. All of our assets are located in the United States, and all revenues are attributable to United States customers. See Note 15.

Significant Purchasers

Our production is sold to various purchasers, based on their credit rating and the location of our production. Sales tothree purchasers for the year ended December 31, 2025, two purchasers for the year ended December 31, 2024, and two purchasers for the year ended December 31, 2023, as shown in the table below, were greater than 10% of total revenues. We believe that alternative purchasers are available, if necessary, to purchase production at prices substantially similar to those received from these significant purchasers.

Earnings per Common Unit

We report basic earnings per unit, which excludes the effect of potentially dilutive securities, and diluted earnings per common unit, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. See Note 11.

Acquisitions and Dispositions

In February 2026, Cross Timbers executed agreements to dispose of certain of the oil and gas assets owned by Cross Timbers pursuant to purchase and sale agreements with multiple private buyers. We anticipate realizing about $40 millionof aggregate proceeds from the Cross Timbers Transactions, subject in each case to customary purchase price adjustments, which we intend to use to pay a portion of the deferred payment for the WRE Acquisition. The Cross Timbers Transactions are expected to close in the second quarter of 2026, subject to customary closing conditions. There can be no assurance that all of the conditions to closing any or all of the Cross Timbers Transactions will be satisfied.

In July 2025, we completed the acquisition of certain oil and gas assets from White Rock Energy, LLC, which are located in the Elm Coulee field in Montana and North Dakota for cash consideration of$331.6 million, including a deferred payment of$70.0 million which is due on July 31, 2026. Our purchase price allocation included$343.0 million to proved properties,$3.0 million to other properties,$1.7 million to other current assets,$6.9 million to other current liabilities and$9.2 million to asset retirement obligation. The WRE Acquisition was funded by a combination of cash on hand from the 2025 Offering (Note 10) and borrowings under our Credit Facility (Note 4).

In the statements of operations, we recorded$20.2 million of revenues and net income of$6.2 million for the three months ended December 31, 2025 and$32.0 million of revenues and net income of$9.0 million for the period we owned these assets from July 31, 2025 to December 31, 2025 from the WRE Acquisition.

In August 2024, we completed the acquisition of producing properties from Eagle Mountain Energy Partners and VR 4-ELM, LP, located in the Elm Coulee field in Montana and the Russian Creek field in North Dakota which are part of the Greater Williston Basin, for cash consideration of$244.2 million and 2.5 million common units of TXO valued at$50.0 million (the “EMEP Acquisition”). Our purchase price allocation included$314.8 million to proved properties,$0.6 million to other properties,$0.3 million to other current assets,$1.0 million to other assets,$5.7 million to other current liabilities and$16.8 million to asset retirement obligation. The cash portion of the acquisition was funded by a combination of cash on hand from the 2024 Offering (as defined below) (Note 10) and borrowings under our Credit Facility (Note 4).

Additionally, in August 2024, we completed the acquisition of producing properties from Kaiser-Francis Oil Company in the Russian Creek field in North Dakota for cash consideration of$17.0 million (the “KFOC Acquisition”). Our purchase price allocation included$19.1 million to proved properties,$0.5 million to current liabilities and$1.6 million to asset retirement obligation. The acquisition was funded by cash on hand from the 2024 Offering (Note 10).

In the statements of operations, we recorded$29.6 million of revenues and net income of$13.4 million for the three months ended December 31, 2024 and$39.8 million of revenues and net income of$17.5 million for the period we owned these assets from August 1, 2024 to December 31, 2024 from the EMEP Acquisition and the KFOC Acquisition.

During 2023, we completed multiple acquisitions of producing properties primarily in the Permian Basin of New Mexico for approximately$8.7 million. Our purchase price allocation included$10.3 million to proved properties,$1.4 million to asset retirement obligation and a$0.2 million reduction to other current assets. The acquisitions were funded by borrowings under our Credit Facility.

Pro forma financial information (Unaudited)

The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the years ended December 31, 2025 and 2024, assuming the WRE Acquisition, EMEP Acquisition and KFOC Acquisition had been completed as of January 1, 2024. The pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations would have been. Future results may vary significantly from the results reflected because of various factors.

Related Party Transactions

We earned management fees from the joint venture of$5.2 million for the year ended December 31, 2025,$5.1 million for the year ended December 31, 2024, and$6.2 million for the year ended December 31, 2023. As of December 31, 2025, we had a note receivable from related party outstanding with a highly-rated, offshore subsidiary of our joint venture partner (Note 5). On September 30, 2016, TXO Partners entered in a loan agreement with the joint venture (Note 4).

Since the purpose of the management fees is to share costs between the various entities, the management fees from the joint venture are included as a reduction of general and administrative expenses in our statements of operations.

We occupy a building owned by MorningStar Capital LLC, a limited liability company owned by the Chairman of the Board. In lieu of paying rent, we paid property taxes and paid for repairs and maintenance on behalf of MorningStar Capital LLC of$0.6 million in 2025,$0.8 million in 2024 and$0.8 million in 2023.

Debt

November 2021 Credit Facility

On July 31, 2025, we entered into Amendment No. 5 and Borrowing Base Agreement (“Amendment No. 5”) on our senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 5 extended the maturity date of the Credit Facility to August 30, 2029, increased the borrowing base from$275 million to$410 million and joined certain new Lenders to the Credit Facility. In connection with the Credit Facility, we incurred financing fees and expenses, which are included in other assets on the balance sheets, of approximately$8.6 million as of December 31, 2025 and$6.2 million as of December 31, 2024 before accumulated amortization of$3.6 million as of December 31, 2025 and$2.5 million as of December 31, 2024. We incurred$2.4 million of financing fees and expenses in conjunction with Amendment No. 5. These costs are being amortized over the life of the credit facility. Such amortized expenses are recorded as interest expense on the statements of operations.

Redetermination of the borrowing base under the credit facility, is based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in March and September, as well as upon requested interim redeterminations, by the lenders at their sole discretion. We also have the right to request additional borrowing base redeterminations each year at our discretion. Significant declines in commodity prices may result in a decrease in the borrowing base. These borrowing base declines can be offset by any commodity price hedges we enter. Our obligations under the credit facility are secured by substantially all assets of the Partnership, including, without limitation, (i) our interest in the joint venture, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by TXO Partners or its wholly-owned subsidiaries. We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio (“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding$15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required to hedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of December 31, 2025 and December 31, 2024. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.

At our election, interest on borrowings under the credit facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The weighted average interest rate on credit facility borrowings was 7.9% in 2025 and 8.6% in 2024.

September 2016 Loan

On September 30, 2016, TXO Partners entered into an unsecured loan agreement with the joint venture (the “FAM Loan”). The proceeds for the loan were taken from the cash held by the offshore subsidiary of Exxon Mobil Corporation and the loan was assigned to the offshore subsidiary (Note 5). The loan matures on November 29, 2029, but is automatically extended should our Credit Facility be extended. In all instances, this loan will mature ninety-one days after the maturity of the Credit Facility. Interest on the loan is the lesser of (a) SOFR plus three and one-quarter of one percent (3.25% per annum, adjusted monthly or (b) the highest rate permitted by applicable law. Though the note is unsecured, we are required to stay in compliance with terms of our Credit Facility. The weighted average interest rate on loan was 7.7% in 2025 and 8.6% in 2024.

Note Receivable from Related Party

As of December 31, 2025 and 2024, we, through our 5% ownership interest in investment assets at the joint venture, had a note receivable totaling$7.1 million outstanding with a highly-rated, offshore subsidiary of our joint venture partner. Under the terms of the agreement, there is no stated maturity date and, the joint venture may demand repayment of all or any portion of the outstanding balance ontwo business days’ notice. Interest is earned based on the one-month SOFR rate per an active international exchange and is paid monthly. Interest income totaled$0.3 million in 2025,$0.4 million in 2024 and$0.4 million in 2023.

The note receivable is treated as a non-current asset, since the joint venture does not have any intention of demanding repayment of all or any portion of the outstanding balance at this time. Repayment would require the approval of the joint venture MMC.

Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Commodity Commitments

During 2025, 2024 and 2023, we entered into futures contracts and swap agreements that effectively fixed crude oil, NGL and natural gas prices on a portion of our production. See Note 9.

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The following is a summary of asset retirement obligation activity for the years ended December 31, 2025 and 2024:

(1)

Revisions in the estimated cash flows for the years ended December 31, 2025 and 2024 are primarily the result of revised cost estimates.

Fair Value

We opportunistically use commodity-based and financial derivative contracts to manage exposures to commodity price. We do not hold or issue derivative financial instruments for speculative or trading purposes. We periodically enter into futures contracts, costless collars, energy swaps, swaptions and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales (Note 9).

Fair Value of Financial Instruments

Because of their short-term maturity, the fair value of cash and cash equivalents, accounts receivable and accounts payable approximates their carrying values at December 31, 2025 and 2024. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

The fair value of our note receivable from related party approximates the carrying amount because the interest rate is based on current market interest rates and can be called upontwo business days’ notice (Note 5). The fair value of our long-term debt approximates the carrying amount because the interest rate is reset periodically at then current market rates (Note 4).

The fair value of our note receivable from related party (Note 5), net derivative asset (liability) (Note 9) and our long-term debt (Note 4) is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or other market-corroborated prices. Counterparty credit risk is considered when determining the fair value of our notes receivable and net derivative asset (liability). Since our counterparty is highly rated, the fair value of our note receivable from related party does not require an adjustment to account for the risk of nonperformance by the counterparty, however, an adjustment for counterparty credit risk, including our own credit risk, has been applied to the net derivative asset (liability).

The following table summarizes our fair value measurements and the level within the fair value hierarchy in which the fair value measurements fall.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable and are based upon Level 3 inputs. These assets and liabilities can include assets and liabilities acquired in a business combination, proved and unproved crude oil, natural gas liquids and natural gas properties, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired.

We periodically review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. We review our oil and natural gas properties by asset group. The estimated future net cash flows are based upon the underlying reserves and anticipated future pricing. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Partnership recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such assets. We record any impairments to accumulated depreciation, depletion and amortization on the balance sheets. The fair value of the proved properties is measured based on a combination of the income and market approaches. These inputs are categorized as Level 3 in the fair value hierarchy. We recorded an impairment of long-lived assets of$42.4 million for the year ended December 31, 2025 and$223.4 million for the year ended December 31, 2023. We didnot recognize an impairment of long-lived assets during the year ended December 31, 2024.

Commodity Price Hedging Instruments

We periodically enter into futures contracts, energy swaps, options, collars and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas and natural gas liquids sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. See Note 9.

The fair value of our derivatives contracts consists of the following:

Derivative fair value (gain) loss, included as part of the related revenue line on the consolidated statements of operations, comprises the following realized and unrealized components:

Concentrations of Credit Risk

Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. Letters of credit or other appropriate security are obtained as considered necessary to limit risk of loss from the other companies. Including the bank that issued the letter of credit, we currently have greater concentrations of credit with several investment-grade (BBB- or better) rated companies.

Commodity Sales Commitments

Our policy is to consider hedging a portion of our production at commodity prices the general partner deems attractive. While there is a risk we may not be able to realize the benefit of rising prices, the general partner may enter into hedging agreements because of the benefits of predictable, stable cash flows.

We enter futures contracts, energy swaps, options and basis swaps to hedge our exposure to price fluctuations on crude oil, natural gas liquids and natural gas sales. When actual commodity prices exceed the fixed price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the contractually provided fixed price, we receive this difference from the counterparty. We also enter costless price collars, which set a ceiling and floor price to hedge our exposure to price fluctuations on crude oil or natural gas sales. When actual commodity prices exceed the ceiling price provided by these contracts we pay this excess to the counterparty, and when the commodity prices are below the floor price, we receive this difference from the counterparty. If the actual commodity price falls in between the ceiling and floor price, there is no cash settlement.

Crude Oil

We have entered into crude oil futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.

Net settlement gains on oil futures and sell basis swap contracts in 2025 and losses in 2024 and 2023 increased oil revenues by$7.1 million in 2025 and decreased revenues by$5.6 million in 2024 and$7.1 million in 2023. Unrealized gains in 2025, 2024 and 2023 to record the fair value of derivative contracts increased oil revenues by$19.1 million in 2025,$5.8 million in 2024 and$9.5 million in 2023.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts and swap agreements for ethane that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.

Net settlement gains in 2024 and 2023 on NGL futures contracts and swap agreements increased NGL revenues$0.5 million in 2024 and$0.4 million in 2023. There wereno NGL settlement gains or losses in 2025. An unrealized gain in 2025 and 2023 and an unrealized loss in 2024 to record the fair value of derivative contracts increased NGL revenues by$0.0 million in 2025, decreased NGL revenues by$0.5 million in 2024 and increased NGL revenues by$1.0 million in 2023.

Natural Gas

We have entered into natural gas futures contracts and swap agreements that effectively fix prices for the production and periods shown below. Prices to be realized for hedged production may be less than these fixed prices because of location, quality and other adjustments.

The price we receive for our gas production is generally less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. We have entered into sell basis swap agreements that effectively fix the basis adjustment for the San Juan Basin delivery location for the production and periods shown below.

————————————————

(a)

Reductions to NYMEX gas price for delivery location

Net settlement gains on gas futures and sell basis swap contracts in 2025 and 2024 and losses in 2023 increased gas revenues by$6.6 million in 2025 and$10.0 million in 2024 and decreased gas revenues by$76.4 million in 2023. An unrealized gain in 2025 and 2023 and an unrealized loss in 2024 to record the fair value of derivative contracts increased gas revenues by$5.0 million in 2025, decreased gas revenues by$12.8 million in 2024 and increased gas revenues by$95.8 million in 2023.

Partners’ Capital

Partners’ Units

On May 15, 2025, we completed an underwritten public offering for the sale of approximately 11,666,667 common units at a price of$15.00 per common unit resulting in proceeds of approximately$165.6 million net of underwriting discounts, commissions and other costs. On May 19, 2025, we completed the sale of an additional 1,750,000 common units at a price of$15.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the 2025 Offering, resulting in additional net proceeds of approximately$23.9 million, after deducting underwriting discounts, commissions and other costs. We used the net proceeds from the 2025 Offering to fund a portion of the cash consideration for the WRE Acquisition (Note 2).

On June 28, 2024, we completed an underwritten public offering for the sale of 6.5 million common units at a price of$20.00 per common unit resulting in proceeds of$122.5 million net of underwriting discounts, commissions and other costs (“the 2024 Offering”). On July 02, 2024, we completed the sale of an additional 975,000 common units at a price of$20.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the 2024 Offering, resulting in additional proceeds of$18.7 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the 2024 Offering to fund a portion of the cash consideration for the EMEP Acquisition and the KFOC Acquisition (Note 2).

On August 30, 2024, as part of the consideration paid in the EMEP Acquisition, we issued 2.5 million common units of TXO valued at$50.0 million (Note 2).

Distributions

During 2025, we paid$101.4 million of cash distributions to our Common unitholders. The following is a summary of our 2025 distributions.

During 2024, we paid$85.4 million of cash distributions to our Common unitholders. The following is a summary of our 2024 distributions:

During 2023, we paid$49.8 million of cash distributions to our Common unitholders. The following is a summary of our 2023 distributions:

During 2023, we paidno in-kind distributions to our Series 5 Preferred holders.

Our fourth quarter distribution of$0.30 per unit with respect to cash available for distribution for the three months ended December 31, 2025, was declared on February 26, 2026 and will be paid on March 17, 2026 to unitholders of record on March 10, 2026.

The determination of the amount of future distributions on the Common Units, if any, to be declared and paid is at the sole discretion of the General Partner and will depend on our financial condition, earnings and cash flow from operations, the level of debt outstanding, the level of our capital expenditures, our future business prospects and other matters the General Partner deems relevant.

Earnings per Unit

The following represents basic and diluted earnings (loss) per Common Unit upon the Reorganization (See Note 1) and corresponding issuance of 30.8 million Common Units:

All restricted units, totaling 950 thousand units and 538 thousand units, were excluded from the calculation of earnings per share for the year ended December 31, 2025 and December 31, 2023, because the units were anti-dilutive. No units were excluded for the year ended December 31, 2024.

Employee Benefit Plans

Unit Incentive Plans

At the time of the public offering in January 2023, we adopted a new long-term incentive plan. Under the 2023 Long-Term Incentive Plan (the "LTIP"), the general partner may issue long-term equity-based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. The LTIP provides for the grant, from time to time at the discretion of the Board or any delegate thereof, of cash awards, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. As of December 31, 2025,3.9 million units were available for future grants of awards under the LTIP. Effective January 1, 2026, an additional 2.7 million units became available for grants under the LTIP pursuant to the LTIP’s “evergreen” feature.

In January 2026, the Compensation Committee of the Board (the "Compensation Committee") approved grants of 632,353 time-vesting phantom units with distribution equivalent rights to the non-employee directors, officers and certain key employees. These phantom units will vest ratably over a three-year period for the officers and key employees and will fully vest on theone-year anniversary of the grant for the non-employee directors. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

Additionally, in January 2026, the Compensation Committee approved grants of 510,552 performance-vesting phantom units to the officers and certain key employees. These performance-based phantom units will be earned based on the Company’s performance during the 2026 calendar year according to certain performance objectives and will vest in one-half increments on January 31, 2028 and January 31, 2029. Prior to determination of the achievement of the performance objectives, distribution equivalent rights will be paid according to the target number of phantom unit grants; following determination of the number of earned phantom units based on achievement of the performance objectives, distribution equivalent rights will be paid according to the number of earned phantom units. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

In conjunction with the announcement that Brent W. Clum and Gary D. Simpson were named Co-Chief Executive Officers of the General Partner, effective April 1, 2025, on March 31, 2025, the Compensation Committee granted the following awards, effective April 1, 2025, to each of Mr. Clum and Mr. Simpson: (i)100,000 phantom units which vested on April 1, 2025 and (ii)100,000 phantom units, along with distribution equivalent rights, which vest on April 1, 2026.

In January 2025, the Compensation Committee approved grants of 301,180 time-vesting phantom units with distribution equivalent rights to the non-employee directors, officers and certain key employees. These phantom units will vest ratably over athree-year period for the officers and key employees and will fully vest on theone-year anniversary of the grant for the non-employee directors. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

Additionally, in January 2025, the Compensation Committee approved grants of 249,380 performance-vesting phantom units to the officers and certain key employees. Based on the results of the Company’s performance during 2025 according to certain performance objectives,243,142 performance-vesting phantom units were earned and will vest in one-half increments on January 31, 2027 and January 31, 2028. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

In January 2024, the Compensation Committee approved grants of 208,875 time-vesting phantom units with distribution equivalent rights to the non-employee directors, officers and certain key employees. These phantom units will vest ratably over athree-year period for the officers and key employees and will fully vest on theone-year anniversary of the grant for the non-employee directors. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

Additionally, in January 2024, the Compensation Committee approved grants of 159,475 performance-vesting phantom units to the officers and certain key employees. Based on the results of the Company’s performance during 2024 according to certain performance objectives,215,977 performance-vesting phantom units were earned and will vest in one-half increments on January 31, 2026 and January 31, 2027. The phantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

The performance-vesting phantom units are earned based on TXO Partners annual performance. The objectives for 2025 and 2024 were (1) distributions to unitholders, (2) lease operating expenses plus cash general and operating expenses per Boe and (3) discretionary factors as determined by the Compensation Committee. These three objectives are essentially equally weighted. The objectives are scored using a range from 50% to 200% depending on the actual results. Generally, exceeding the objective is scored at 200% of target, meeting the objective is scored at 100% of target and missing the objective is scored at 50% of target. The same objectives and scoring will be used to measure the 2026 awards. Additionally, we expense the performance-vesting performance phantom units assuming 100% of the phantom units will be earned. We only change this estimate when we have information that the earned awards will be different than 100% or at such time as the awards are earned.

In connection with the offering, the Board approved grants of 545,000 phantom units with distribution equivalent rights to the non-employee directors, officers and certain key employees. These phantom units will vest ratably over athree-year period for the officers and key employees and fully vested on theone-year anniversary of the grant for the non-employee directors. Thephantom units will be settled in common units and distribution equivalents will be paid to holders of outstanding phantom units, including unvested phantom units.

We recognized non-cash restricted unit compensation expense of$16.3 million in 2025,$6.2 million in 2024 and$3.5 million in 2023. Total deferred compensation at December 31, 2025 related to restricted units was$11.6 million. We estimate that incentive compensation for service periods after December 31, 2025 will be approximately$7.4 million in 2026,$3.9 million in 2027, and$0.3 million in 2028. The weighted-average remaining vesting period is 1.0 yearsfor restricted units.

Revenue from Contracts with Customers

The Partnership recognizes sales of oil, natural gas, and NGLs when it satisfies a performance obligation by transferring control of the product to a customer, in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for the product.

As discussed in Note 9, the Partnership recognizes the impact of derivative gains and losses as a component of revenue. See table below for the reconciliation of revenue from contracts with customers and derivative gains and losses.

Natural Gas and NGL Sales

Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or at the inlet of a facility. The midstream provider gathers and processes the product and both the residue gas and the resulting natural gas liquids are sold at the tailgate of the plant. The Partnership’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to the market. We evaluated these arrangements and determined that control of the products transfers at the tailgate of the plant, meaning that the Partnership is the principal and the third-party purchaser is its customer. As such, we present the gas and NGL sales on a gross basis and the related gathering and processing costs as a component of taxes, transportation, and other on the statement of operations.

Oil and Condensate Sales

Oil production is typically sold at the wellhead or at the outlet of a gathering system under market-sensitive contracts at an index price, net of pricing differentials. The Partnership recognizes revenue upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for the product.

Production imbalances

The Partnership uses the sales method to account for production imbalances. If the Partnership’s sales volumes for a well exceed the Partnership’s proportionate share of production from the well, a liability is recognized to the extent that the Partnership’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy the imbalance. No receivables are recorded for those wells on which the Partnership has taken less than its proportionate share of production.

Contract Balances

Under the Partnership’s product sales contracts, its customers are invoiced once the Partnership’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Partnership’s product sales contracts do not give rise to contract assets or contract liabilities.

Performance Obligations

The majority of the Partnership’s sales are short-term in nature with a contract term of one year or less. For those contracts, the Partnership has utilized the practical expedient in ASC 606-10-50-14 exempting the Partnership from disclosures of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original duration of one year or less.

For the Partnership’s product sales that have a contract term greater than one year, the Partnership has utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligation is not required.

Accrued Liabilities

Accrued liabilities consist of the following at December 31, 2025 and 2024:

Segment Reporting

We haveone reportable segment, our exploration and production of oil, natural gas and natural gas liquids segment (“E&P segment”). Our E&P segment derives revenues from customers by selling oil, natural gas and natural gas liquids under contracts of various terms and durations (See Note 13). The operating segments within the reportable segment have been aggregated based on the similarity of their economic and other characteristics, including product type and services. All of our assets are located in the United States, and all revenues are attributable to United States customers.

The Partnership's Chief Operating Decision Maker ("CODM") is a group of executives, including the Co-Chief Executive Officer and the Co-Chief Executive Officer and Chief Financial Officer. The CODM assesses performance for the E&P segment and decides how to allocate resources based on cash provided by operations which is also reported on the statement of cash flows as consolidated cash provided by operations. The measure of segment assets is reported on the balance sheet as total consolidated assets.

The CODM uses net income to evaluate income generated from segment assets in deciding whether to reinvest profits into the E&P segment or to pay distributions.

Selected financial information related to ourone reportable segment is included below:

Supplemental Cash Flow Information

The statement of cash flows excludes the following non-cash transactions:

•

The issuance of 2.5 million common units to partially fund the EMEP Acquisition in 2024 (Note 2).

•

The exchange of 2,061.22 Series 5 Preferred Units for 10,644,482 Common Units in 2023 (Note 10).

•

Accrued capital expenditures were$4.8 million at December 31, 2025 and$5.4 million at December 31, 2024.

Interest payments totaled$15.4 million in 2025,$7.0 million in 2024 and$3.5 million in 2023. State income tax payments totaled$0.3 million in 2025,$1.9 million in 2024 and$3.6 million in 2023.

Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued. See Notes 2 and 12.

Supplementary Financial Information for Oil and Gas Producing Activities(Unaudited)

All of our operations are directly related to oil and gas producing activities located in the United States primarily in the San Juan Basin of New Mexico and Colorado, the Permian Basin of West Texas and New Mexico and the Williston Basin of Montana and North Dakota.

Costs Incurred Related to Oil and Gas Producing Activities

The following table summarizes costs incurred whether such costs are capitalized or expensed for financial reporting purposes for each year:

Proved Reserves

Our proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural 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 regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors. Proved reserves exclude volumes deliverable to others under production payments or retained interests.

Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce year-end estimated proved reserves. Discounted future net cash flows are calculated using a 10% rate. No provision is included for federal income taxes since our future net cash flows are not subject to taxation. Limited liability companies are subject to the Texas margin tax.

Estimated well abandonment costs, net of salvage values, are deducted from the standardized measure using year-end costs and discounted at the 10% rate. Such abandonment costs are recorded as a liability on the consolidated balance sheet, using estimated values as of the projected abandonment date and discounted using a risk-adjusted rate at the time the well is drilled or acquired (Note 7).

The standardized measure does not represent management’s estimate of our future cash flows or the value of proved oil and natural gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations.

Furthermore, prices used to determine the standardized measure are influenced by supply and demand as effected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

In 2025, the 25.3 Mboe of purchases in place represent the reserves acquired from White Rock (25.3 MBoe). The 10.2 MBoe of extensions, additions and discoveries in proved reserves in 2025 did not result in the conversion of any proved undeveloped reserves to proved developed reserves because they were primarily related to drilling wells in the San Juan Basin, Permian Basin and Williston Basin that did not have proved undeveloped reserves assigned at the beginning of the year, and which resulted in additional proved developed reserves. The 10.2 MBoe of upward revisions in proved reserves for 2025 were the result of higher commodity prices (9.8 MBoe) and changes in the development plan (0.4 MBoe).

In 2024, the 15.5 Mboe of purchases in place represent the reserves acquired primarily from Eagle Mountain (14.2 MBoe) and Kaiser Francis (1.3 Mboe). The 0.4 MBoe of extensions, additions and discoveries in proved reserves in 2024 did not result in the conversion of any proved undeveloped reserves to proved developed reserves because they were primarily related to drilling in the San Juan Basin and Permian Basin that did not have proved undeveloped reserves assigned at the beginning of the year, and which resulted in additional proved developed reserves. The 13.7 MBoe of downward revisions in proved reserves for 2024 were the result of lower commodity prices (10.0 MBoe) and changes in the development plan (3.7 MBoe).

In 2023, the 1.2 Mboe of purchases in place represent the reserves acquired from multiple acquisitions. The 1.2 MBoe of extensions, additions and discoveries in proved reserves in 2023 did not result in the conversion of any proved undeveloped reserves to proved developed reserves because they were primarily related to drilling in the San Juan Basin and Permian Basin that did not have proved undeveloped reserves assigned at the beginning of the year, and which resulted in additional proved developed reserves. The (37.2 MBoe) of downward revisions in proved reserves for 2023 were the result of a combination of lower commodity prices and higher costs (22.6 MBoe)and changes in the development plan (14.6 MBoe).

(a)

The December 31, 2025 standardized measure includes a reduction of$450.2 million ($450.8 million before income tax) for estimated property abandonment costs. These estimated property abandonment costs are not included in the reserves report prepared by our third-party engineer. The consolidated balance sheet at December 31, 2025 includes a liability of$221.1 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

(b)

The December 31, 2024 standardized measure includes a reduction of$392.1 million ($392.9 million before income tax) for estimated property abandonment costs. These estimated property abandonment costs are not included in the reserves report prepared by our third-party engineer. The consolidated balance sheet at December 31, 2024 includes a liability of$190.9 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

(c)

The December 31, 2023 standardized measure includes a reduction of$292.0 million ($292.5 million before income tax) for estimated property abandonment costs. These estimated property abandonment costs are not included in the reserves report prepared by our third-party engineer. The consolidated balance sheet at December 31, 2023 includes a liability of$154.0 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

Price and cost revisions are primarily the net result of changes in prices, based on beginning of year reserve estimates. Quantity estimate revisions are primarily the result of the extended economic life of proved reserves and proved undeveloped reserve additions attributable to increased development activity.

Average realized oil prices used in the estimation of proved reserves and calculation of the standardized measure were$62.02 for 2025,$73.73 for 2024 and$76.58 for 2023. Average realized natural gas liquids prices were$15.78 for 2025,$17.70 for 2024 and

$18.44 for 2023. Average realized gas prices were$2.11 for 2025,$1.14 for 2024 and$1.58 for 2023. We used 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period.