TXO Partners LP

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 (formerly known as MorningStar Partners L.P. as discussed further in Note 1) (the Partnership) as of December 31, 2023 and 2022, the related consolidated statements of operations, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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.

Dallas, Texas

Auditor Firm ID 185

March 5, 2024

TXO PARTNERS, L.P.Consolidated Balance Sheets

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TXO PARTNERS, L.P. Consolidated Statements of Operations

(in thousands)

TXO PARTNERS, L.P. Consolidated Statements of Cash Flows

(in thousands)

TXO PARTNERS, L.P. Consolidated Statements of Partners’ Capital

(in thousands)

TXOPARTNERS, L.P.

Notes to Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

TXO Partners, L.P. (TXO Partners or the Partnership) is the new name of MorningStar Partners, L.P. as of May 8, 2023. 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 ofthree officers andfour independent 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 and the Permian Basin of West Texas and New Mexico.

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 publically 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 remain in compliance with our future debt covenants for all of our outstanding debt 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 of oil and gas properties;

•estimates of revenue earned but not yet received;

•asset retirement obligations; 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, 2023 and 2022. Proved properties balances include costs of $3.0 million at December 31, 2023 and $17.1 million at December 31, 2022 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 from three toseven 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. 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 Texas 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. During the years ended December 31, 2022 and 2021, we didnot recognize an impairment of long-lived assets. 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.

Asset Retirement Obligation

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 and state income tax purposes, with the exception of the state of Texas, with income tax liabilities and/or benefits of the Partnership passed through to the partners. As such, with the exception of the state of Texas, we are not a taxable entity, we do not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for our operations, except as described below.

Limited partnerships are subject to state income taxes in Texas. 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 operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. All of our assets are located in the United States, and all revenues are attributable to United States customers.

Significant Purchasers

Our production is sold to various purchasers, based on their credit rating and the location of our production. Sales to two purchasers for the year ended December 31, 2023, two purchasers for the year ended December 31, 2022, and three purchasers for the year ended December 31, 2021, 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.

Accounting Standards Update

On November 27, 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. Among other new disclosure requirements, ASU 2023-07 requires companies to disclose significant segment expenses that are regularly provided to the chief operating decision maker. ASU 2023-07 will be effective for annual periods beginning on January 1, 2024 and interim periods beginning on January 1, 2025. ASU 2023-07 must be applied retrospectively to all prior periods presented in the financial statements. We are evaluating the disclosure impact of ASU 2023-07; however, the standard will not have an impact on our financial position, results of operations or cash flows.

2. Acquisitions

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 from our credit facility.

In August 2022, we completed the acquisition of additional interest in our producing properties and gas processing plant in the Permian Basin of New Mexico from Vendera Resources for approximately $52.8 million. Our purchase price allocation included $50.0 million to proved properties, $9.8 million to other properties, $3.7 million as a reduction to other current assets, $0.2 million to other current liabilities and $3.1 million to asset retirement obligation. The acquisition was funded by borrowings from our credit facility.

In February 2022, we completed the acquisition of producing properties in the Permian Basin of Texas from Kaiser Francis for approximately $3.8 million. Our purchase price allocation included $4.0 million to proved properties and $0.2 million to asset retirement obligation. The acquisition was funded by cash on hand.

During 2022, we completed multiple acquisitions of producing properties in the Permian Basin of Texas and New Mexico for $0.6 million. We allocated $0.6 million to proved property.

In December 2021, we completed the acquisition of producing properties in the Permian Basin of Texas from Chevron for approximately $43.7 million. Our purchase price allocation included $47.3 million to proved properties, $0.2 million to current liabilities and $3.4 million to asset retirement obligation. The acquisition was funded by cash on hand and borrowings from our credit facility.

In November 2021, we completed the acquisition of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO 2 assets in Colorado from Chevron for approximately $179.3 million. Our purchase price allocation included $150.9 million to proved properties, $34.4 million to other properties, $3.6 million to other current assets, $2.2 million to other current liabilities and $7.4 million to asset retirement obligation. The acquisition was funded by cash on hand from the October 2021 capital raise (see Note 10) and borrowings from our credit facility. In the 2021 statement of operations, we recorded $15.0 million of revenues and income of $2.8 million from this acquisition.

Pro forma financial information (Unaudited)

The following pro forma financial information represents the results for the Partnership and the properties acquired in November 2021 in the Permian Basin of New Mexico and CO 2 assets in Colorado from Chevron as if the acquisition and the required financing had occurred on January 1, 2021.

For the pro forma year ended December 31, 2021, pro forma revenues were $278.7 million and pro forma net income was $61.4 million. For the purposes of the pro forma, it was assumed that $40.0 million of the Partnership’s revolving credit facility was used to finance the acquisition resulting in additional interest expense of $1.3 million. The pro forma financial information includes the effects of adjustments for depreciation, depletion, and amortization of $7.8 million, and accretion of asset retirement obligations expense of $0.3 million.

The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Partnership to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

3. Related Party Transactions

We earned management fees from the joint venture of $6.2 million for the year ended December 31, 2023, $5.9 million for the year ended December 31, 2022, and $6.1 million for the year ended December 31, 2021. As of December 31, 2023, 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).

We earned management fees from Southland of less than $0.1 million for the year ended December 31, 2023, less than $0.1 million for the year ended December 31, 2022, and $5.0 million for the year ended December 31, 2021.

Since the purpose of the management fees is to share costs between the various entities, the management fees from the joint venture and Southland 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 our Chief Executive Officer and 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 $0.8 million in 2023, $0.9 million in 2022 and $0.9 million in 2021.

4. Debt

November 2021 Credit Facility

On November 1, 2021, we entered into a newfour-year, $165 million senior secured credit facility with certain commercial banks, with JPMorgan Chase Bank, N.A. as administrative agent. The facility has a maturity date of November 1, 2025. We use the facility for general corporate purposes. On June 28, 2023, we entered into an amendment to the Credit Facility (the “Second Amendment”) to make certain changes as described below. On October 25, 2023, the borrowing base was reaffirmed. In connection with entering into the credit facility, we incurred financing fees and expenses of approximately $3.0 million as of December 31, 2023 and $2.8 million as of December 31, 2022 before accumulated amortization of $1.5 million as of December 31, 2023 and $0.8 million as of December 31, 2022. 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. Effective with the Second Amendment, 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 tohedge 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 as amended by the Second Amendment, we were in compliance with all of our debt covenants as of December 31, 2023. From September 30, 2022 through the date of the spring redetermination in June 2023, we received waivers to reduce the hedging requirement from 30 months to 15 months and from 50% to 45% of the reasonably projected production. As a result, we were in compliance with all of our debt covenants as of December 31, 2022. 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 8.4% in 2023 and 5.4% in 2022.

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 January 31, 2026, 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) London Interbank Offered Rate (“LIBOR”) 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 8.5% in 2023 and 5.1% in 2022.

Paycheck Protection Program Loans

On April 13, 2020, we received a loan of approximately $7.2 million under the US Government’s Paycheck Protection Program from the Small Business Administration (“SBA”). Under the terms of the loan, it was required to be repaid beginning November 13, 2020 in equal installments until April 13, 2022, unless we qualified for loan forgiveness.

The loan bore interest at a rate of 1% per annum. In August 2020, we sent in our loan forgiveness application for the entire loan amount. As a result of filing the application, we did not make any payments on the loan, nor did we accrue any interest on the loan in 2021. On June 14, 2021 we received notice that the loan was forgiven in full. We recorded this loan forgiveness as other income on the statements of operations.

On January 27, 2021, we received a second loan for $2.0 million under an extension of the US Government’s Paycheck Protection Program from the SBA. On July 2, 2021 we received notice that the loan was forgiven in full. We recorded this loan forgiveness as other income on the statements of operations.

5. Note Receivable from Related Party

As of December 31, 2023 and 2022, 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 LIBOR rate per an active international exchange and is paid monthly. Interest income totaled $0.1 million in 2023, $0.1 million in 2022 and less than $0.1 million in 2021.

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.

6. 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 2023, 2022 and 2021, we entered into futures contracts and swap agreements that effectively fixed natural gas and crude oil prices. See Note 9.

7. Asset Retirement Obligation

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, 2023 and 2022:

(1)Revisions in the estimated cash flows for the years ended December 31, 2023 and 2022 are primarily the result of revised cost estimates.

8. 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, 2023 and 2022. 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 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 the income approach, which incorporates a number of assumptions involving expectations of future product prices, which the Partnership bases on the forward-price curves, estimates of oil and gas reserves, estimates of future expected operating and capital costs and a risk adjusted discount rate of 10%. These inputs are categorized as Level 3 in the fair value hierarchy. We recorded an impairment of long-lived assets of $223.4 million for the year ended December 31, 2023. We didnot recognize an impairment of long-lived assets during the years ended December 31, 2022 and 2021.

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 8.

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.

9. 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 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. See Note 9.

Net settlement losses in 2023 and 2022 and gains in 2021 on oil futures and sell basis swap contracts decreased oil revenues by $7.1 million in 2023 and by $32.8 million in 2022 and increased oil revenues by $0.0 million in 2021. An unrealized gain in 2023 and 2021 and an unrealized loss in 2022 to record the fair value of derivative contracts increased oil revenues by $9.5 million in 2023, decreased oil revenues by $13.0 million in 2022 and increased oil revenues by $0.3 million in 2021.

Natural Gas Liquids

We have entered into natural gas liquids futures contracts and swap agreements for certain components—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. See Note 9.

Net settlement gains in 2023 and losses in 2022 and 2021 on NGL futures contracts and swap agreements increased NGL revenues by $0.4 million in 2023 and decreased revenues by $4.6 million in 2022 and $0.0 million in 2021. An unrealized gain in 2023 and 2021 and an unrealized loss in 2022 to record the fair value of derivative contracts increased NGL revenues by $1.0 million in 2023, decreased NGL revenues by $1.0 million.in 2022 and increased NGL revenues by $0.5 million in 2021.

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. See Note 9.

We have also entered into gas collars that set a ceiling and floor price for the production and periods shown below.

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 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 losses on gas futures and sell basis swap contracts decreased gas revenues by $76.4 million in 2023, $52.6 million in 2022 and $0.0 million in 2021. An unrealized gain in 2023 and 2021 and an unrealized loss in 2022 to record the fair value of derivative contracts increased gas revenues by $95.8 million in 2023, decreased gas revenues by $99.2 million in 2022 and increased gas revenues by $8.2 million in 2021.

10. Partners’ Capital

Partners’ Units

Under the terms of the amended partnership agreement, there are two classes of units, Common Units and Preferred Units. The general partner establishes the number of authorized units and as of December 31, 2023, the general partner has not established the authorized number of Common Units. All of the Common Unit and per Common Unit amounts herein are presented as if the January 2023, one-for-25.33 reverse stock split had taken place January 1, 2021.

In conjunction with an offering in August 2019, we created a new class of Preferred Units, Series 3 Preferred Units. Each Series 3 Preferred Unit cost $25 per preferred unit and also included warrants to purchase an additional 0.1 common units for $25.33. The Series 3 Preferred Units received semi-annual distributions in the amount of $0.625 per preferred unit. A holder of Series 3 Preferred Units will received in-kind distributions of Common Units for their Series 3 Preferred Units. The semi-annual distributions were paid in April and October. The Series 3 Preferred Units automatically converted to 0.2 Common Units for each preferred unit on October 1, 2022. Additionally, all of the warrants were exercised on October 1, 2022.

In conjunction with an offering in July 2020, we created an additional class of Preferred Units, Series 4 Preferred Units. Each Series 4 Preferred Unit was issued at $95,000 per preferred unit (an original issue discount of $5,000 per preferred unit) and also included warrants equal to, in the aggregate,20% non-dilutable common units, at the time of exercise. These warrants had a term offive years from the date of closing and an exercise price of $0.25 each. If holders of a majority of the warrants elected to exercise the warrants, then all warrants were required to be exercised at the same time. There was also a group of backstop investors that provided a minimum amount of capital of a least $35 million. These backstop investors received an arrangement fee in the form of warrants to purchase common units for $0.25 per common unit, with warrants equal to, in the aggregate,10% non-dilutable common units at the time of exercise. These warrants had a term of 15 years. The Series 4 Preferred Units received a semi-annual payment of 12% paid-in-kind common units at $5.07 per common unit or 10% cash pay as permitted. The Partnership could call the Series 4 Preferred Units at any time and at a cost of $100,000 per preferred unit plus any accrued dividends at such date. However, if we called the Series 4 Preferred Units on or prior to the second anniversary of the offering, we were required to pay $130,000 per preferred unit. Beginning August 1, 2025, the Series 4 Preferred Units could be put back to us for repayment at a cost of $100,000 per preferred unit plus any accrued dividends at such date. As a result of our offering, we issued 533.63 preferred units for total proceeds of $50.4 million net of $0.3 million of offering costs. The proceeds were used to pay down $35 million on our Credit Facility (see Note 4) and the remainder was retained for future cash needs.

In conjunction with an offering in October 2021, we created an additional class of Preferred Units, Series 5 Preferred Units. Each Series 5 Preferred Unit was issued at $100,000 per preferred unit. The Series 5 Preferred Units receive a semi-annual payment of 6.25% paid-in cash. The Series 5 Preferred Units automatically convert to Common Units at a rate of $20.26 per unit no later than October 15, 2024. In conjunction with our offering, all Series 4 Preferred Units were exchanged into Series 5 Preferred Units at a rate of 1.4 Series 5 Preferred Units for each Series 4 Preferred Unit. Additionally, all Series 4 warrants were converted to Common Units effective October 2021 at no cost to the warrant holder. The impact of the exchange of Series 4 Preferred Units to Series 5 Preferred Units coupled with the non-cash conversion of Series 4 warrants to Common Units accrued to the benefit of the Series 4 Preferred unitholders, who also own approximately 90% of the Common Units. The actual effect of this conversion was to transfer $22.7 million of value from the Common Unit holders to the Series 4 Preferred Unit holders. As a result of the offering, we issued 2,073.69 preferred units for total proceeds of $132.6 million net of $0.1 million of offering costs. There areno Series 4 Preferred Units or warrants still outstanding.

The proceeds, in conjunction with cash on hand and borrowings under our credit facility, were used to acquire producing properties and a gas processing plant in the Permian Basin of New Mexico and CO 2 assets in Colorado from Chevron (see Note 2).

Effective with the public listing of our common units on January 31, 2023, all of the outstanding Series 5 Preferred Units were exchanged for 10,644,484 Common Units, such that there is only one class of units outstanding. After the exchange, we had 25,000,000 Common Units outstanding.

Prior to April 1 st of each year, the general partner shall determine the fair value of a Common Unit as of January 1 st of such year. However, the general partner can change the fair value of a Common Unit should circumstances indicate that a material change in value has occurred. The fair value was determined to be $10.13 per Common Unit as of January 1, 2021 and $22.03 per Common Unit as of January 1, 2022. The fair value was not calculated for January 1, 2023, since the Common Units are now publicly traded. The fair value established by the general partner was used for all purposes until the next redetermination.

The following reflects our partners’ Common Unit and Preferred Unit activity for the years ended December 31, 2023, 2022 and 2021 (in thousands):

Distributions

During 2023, we paidno in-kind distributions to our Series 5 Preferred holders. During 2022, we paid in-kind distributions of 37,615 units with a value of $1.7 million to our Series 3 Preferred holders. During 2021, we paid in-kind distributions of 1.3 million units with a value of $6.4 million to our Series 4 Preferred holders and 37,615 units with a value of $1.8 million to our Series 3 Preferred holders.

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

Our fourth quarter distribution of $0.58 per unit with respect to cash available for distribution for the three months ended December 31, 2023, was declared on March 05, 2024 and will be paid on March 28, 2024 to unitholders of record on March 15, 2024.

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.

See Note 12.

11. 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 538 thousand units, were excluded from the calculation of earnings per share for the year ended December 31, 2023, because the units are anti-dilutive.

12. 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 (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 of directors of our general partner 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. Under the terms of the LTIP,2.0 million units are available for grants of awards.

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 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.

We recognized non-cash restricted unit compensation expense of $3.5 million in 2023, $0.0 million in 2022 and $2.4 million in 2021 related to a fully-vested grant of 118,457 units. Total deferred compensation at December 31, 2023 related to restricted units was $7.2 million. We estimate that incentive compensation for service periods after December 31, 2023 will be approximately $3.5 million in 2024, $3.5 million in 2025, and $0.3 million in 2026. The weighted-average remaining vesting period is 2.0 years for restricted units.

13. 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 sold at the wellhead 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. This treatment after the adoption of ASC 606 is consistent with the treatment under ASC 605 and has no impact on revenues or expenses on the statement of operations.

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.

14. Accrued Liabilities

Accrued liabilities consist of the following at December 31, 2023 and 2022:

15. Supplemental Cash Flow Information

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

•The following restricted share activity (Note 12):

◦Forfeitures of 10,000 restricted units in 2023 andno forfeitures in 2022 and 2021.

•The payment of in-kind dividends ofno units in 2023,37,615 units in 2022 and 1,301,862 units in 2021 (Note 12).

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

•The exchange of 533.63 Series 4 Preferred Units for 747.09 Series 5 Preferred Units in 2021 (Note 10).

•Accrued capital expenditures were $0.7 million at December 31, 2023 and $6.7 million at December 31, 2022.

Interest payments totaled $3.5 million in 2023, $7.9 million in 2022 and $4.1 million in 2021. State income tax payments totaled $3.6 million in 2023, $0.5 million in 2022 and $0.1 million in 2021.

16. Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued.

17. 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 and the Permian Basin of West Texas and New Mexico.

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 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 were primarily related to drilling the San Juan

Basin and Permian Basin. 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).

In 2022, the 6.1 Mboe of purchases in place represent the reserves acquired from Vendera (5.6 MBoe) and Kaiser Francis (0.4 MBoe). The 1.4 MBoe of extensions, additions and discoveries in proved reserves in 2022 were primarily related to drilling the San Juan Basin and Permian Basin. The 14.6 MBoe of upward revisions in proved reserves for 2022 were the result of a combination of higher commodity prices (14.9 MBoe) partially offset by changes in the development plan (0.2 MBoe).

In 2021, the 32.0 Mboe of purchases in place represent the reserves acquired from Chevron in November 2021 (24.9 Mboe) and in December 31, 2022 (7.1 Mboe). The 1.1 MBoe of extensions, additions and discoveries in proved reserves in 2021 were primarily related to drilling the San Juan Basin. The 35.5 Mboe of upward revisions in proved reserves for 2021 were the result of a combination of higher commodity prices (34.9 Mboe) and changes in the development plan (0.6 Mboe).

(a)The December 31, 2023 standardized measure includes a reduction of $292.0 million ($292.5 million before income tax) for estimated property abandonment costs. 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.

(b)The December 31, 2022 standardized measure includes a reduction of $248.0 million ($248.4 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2022 includes a liability of $126.5 million for the same asset retirement obligation, which was calculated using different cost and present value assumptions.

(c)The December 31, 2021 standardized measure includes a reduction of $213.1 million ($213.6 million before income tax) for estimated property abandonment costs. The consolidated balance sheet at December 31, 2021 includes a liability of $104.5 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 $76.58 for 2023, $92.94 for 2022 and $64.76 for 2021. Average realized natural gas liquids prices were $18.44 for 2023, $29.72 for 2022 and $19.62 for 2021. Average realized gas prices were $1.58 for 2023, $4.35 for 2022 and $2.31 for 2021. We used 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period.