TXO Partners, L.P.

TXOPARTNERS, L.P.

Notes to Consolidated Financial Statements (Unaudited)

1. 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 Partners 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 members of the board of directors of our General Partner are appointed by MorningStar Oil & Gas, LLC (“MSOG”), as the sole member of our General Partner. 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, Cross Timbers Energy, LLC (“Cross Timbers Energy”). TXO Partners owns 50% of Cross Timbers Energy, and TXO Partners is the manager of Cross Timbers Energy. Cross Timbers Energy 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, Cross Timbers Energy 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. Cross Timbers Energy’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.

2. Basis of Presentation and Significant Accounting Policies

The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and on the same basis as our audited financial statements as of December 31, 2024 included in our Annual Report on Form 10-K for the year ended December 31, 2024. The consolidated balance sheet as of March 31, 2025 and the consolidated statements of operations and cash flows for the periods presented herein are not audited but reflect all adjustments that are of a normal recurring nature and are necessary for a fair statement of results for the periods shown. Certain information and note disclosures normally included in annual financial statements have been omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). Because the consolidated interim financial statements do not include all of the information and notes required by US GAAP for a complete set of financial statements, they should be read in conjunction with the audited consolidated financial statements referred to above. The results and trends in these interim financial statements may not be indicative of results for the full year.

Significant Accounting Policies

For a complete description of TXO Partners’ significant accounting policies, see our annual audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2024.

3. Acquisitions

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$243.5 million and 2.5 million common units of TXO valued at$50.0 million (the “EMEP Acquisition”). Our purchase price allocation included $314.1 million to proved properties, $0.6 million to other properties, $0.3 million to other current assets,$1.0 millionto 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 public offering and borrowings under our Credit Facility (Note 5).

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”), subject to customary purchase price adjustments. Our preliminary 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 public offering.

In the statements of operations for the three months ended March 31, 2025, we recorded$28.8 millionof revenues and net income of$9.0 million from these acquisitions.

Pro forma financial information (Unaudited)

The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for thethree months ended March 31, 2024, assuming the 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.

4. Related Party Transactions

We earned management fees from Cross Timbers Energy of $1.2 million for the three months ended March 31, 2025 and $1.1 million for the three months ended March 31, 2024.

5. Debt

November 2021 Credit Facility

On August 30, 2024, we entered into Amendment No. 4 and Borrowing Base Agreement (“Amendment No. 4”) 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. 4 extended the maturity date of the Credit Facility to August 30, 2028, increased the borrowing base from $165 million to $275 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$6.2 million as of March 31, 2025 and December 31, 2024 before accumulated amortization of$2.7 million as of March 31, 2025 and$2.5 million as of December 31, 2024. 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 current liabilities shall exclude the fair value of derivative instruments and any advances under the Credit 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 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. We expect to complete our spring redetermination in May 2025. Under the terms of the Credit Facility as amended by the Fourth Amendment, we were in compliance with all of our debt covenants as of March 31, 2025 and December 31, 2024. Additionally, we believe wehave 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.

September 2016 Loan

On September 30, 2016, TXO Partners entered into an unsecured loan agreement with Cross Timbers Energy (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 6). The loan matures on November 29, 2028, but is automatically extended should the maturity date of the 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 the Credit Facility.

6. Note Receivable from Related Party

As of March 31, 2025 and December 31, 2024, we, through our 5% ownership interest in investment assets at Cross Timbers Energy, had a note receivable totaling $7.1 million outstanding with a highly-rated, offshore subsidiary of Exxon Mobil Corporation. Under the terms of the agreement, there is no stated maturity date and Cross Timbers Energy 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 and is paid monthly. Interest income totaled $0.1 million in the first three months of 2025 and $0.1 million in the first three months of 2024.

The note receivable is treated as a non-current asset, since Cross Timbers Energy 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 Cross Timbers Energy MMC.

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 changes in TXO Partners’ asset retirement obligation activity for the three months ended March 31, 2025:

8. 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 and occupational health and safety laws and 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.

9. Fair Value

We periodically 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 10).

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 March 31, 2025 and December 31, 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 6). 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 5).

The fair value of our note receivable from related party (Note 6), derivative asset/(liability) (Note 10) and our long-term debt (Note 5) 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 note receivable and 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 has been applied to the 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. Such fair value estimates require assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, what constitutes adequate restoration, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental and political environments.

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. 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.

Commodity Price Hedging Instruments

We periodically enter into futures contracts, energy swaps, swaptions, 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 10.

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 income statements, 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, marketing 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.

10. 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 periodically enter futures contracts, energy swaps, swaptions 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 settlements on oil futures and sell basis swap contracts increased oil revenues by $0.1 million in the first three months of 2025 and decreased oil revenues by $2.5 million in the first three months of 2024. An unrealized gain increased oil revenues by $3.1 million in the first three months of 2025 and an unrealized loss decreased oil revenues by $0.3 million in the first three months of 2024.

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. See Note 9.

Net settlements on NGL futures contracts hadno impact on NGL revenues in the first three months of 2025 and increased NGL revenues by $0.2 million in the first three months of 2024. An unrealized loss decreased NGL revenues by $0.0 million in the first three months of 2025 and $0.2 million in the first three months of 2024.

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.

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 settlements on gas futures and sell basis swap contracts decreased gas revenues by $2.0 million in the first three months of 2025 and increased gas revenues by $1.9 million in the first three months of 2024. An unrealized loss to record the fair value of derivative contracts decreased gas revenues by $10.6 million in the first three months of 2025 and $0.2 million in the first three months of 2024.

11. Earnings per Unit

The following represents basic and diluted earnings per Common Unit for thethree months ended March 31, 2025 and 2024:

12. Partners’ Capital

On May 1, 2025, the board of directors of our general partner declared a cash distribution of $0.61 per common unit for the quarter ended March 31, 2025. The distribution will be paid on May 23, 2025, to unitholders of record on May 16, 2025.

Our fourth quarter distribution of$0.61 per unit with respect to cash available for distribution for the three months ended December 31, 2024, was paid on March 21, 2025.

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 10, 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 when control transfers to the purchaser at the wellhead at the net price received from the customer.

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. Employee Benefit Plans

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 target grants of 249,380 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 2025 calendar year according to certain performance objectives and will vest in one-half increments on January 31, 2027 and January 31, 2028. Prior to determination of the achievement of the performance objectives, distribution equivalent rights will be paid according to the target number of phantom units 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 of the Board granted the following awards, effective April 1, 2025, to each of Mr. Clum and Mr. Simpson: (i)100,000 phantom units which vest on April 1, 2025 and (ii)100,000 phantom units, along with distribution equivalent rights, which vest on April 1, 2026.

In January 2024, the compensation committee approved target 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.

We recognized compensation expense related to these and prior grants of $2.1 million for thethree months ended March 31, 2025 and $1.1 millionfor the three months ended March 31, 2024. As of March 31, 2025, we had total deferred compensation expense of $17.1 million. For these non-vested unit awards, we estimate that compensation expense for service periods after March 31, 2025 will be $7.2 million in 2025, $6.1 million in 2026, $3.5 million in 2027 and $0.3 million in 2028. The weighted average remaining vesting period is 1.9 years.

15. Accrued Liabilities

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

16. 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 Officers. 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:

17. Supplemental Cash Flow Information

Interest payments totaled $3.2 million for the three months ended March 31, 2025 and $0.8 million for the three months ended March 31, 2024. State income tax payments on behalf of our unitholders were $0.2 million during the three months ended March 31, 2025 and $1.5 million during the three months ended March 31, 2024.

18. Subsequent Events

We have evaluated subsequent events through the date the financial statements were available to be issued. See Notes 10 and 14.