BATTALION OIL CORP

1. FINANCIAL STATEMENT PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

Battalion Oil Corporation (“Battalion” or the “Company”) is the successor reporting company to Halcón Resources Corporation (“Halcón”). On January 21, 2020, Battalion filed a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Halcón Resources Corporation to Battalion Oil Corporation.

Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States (“U.S.”). The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements. These consolidated financial statements of the Company have been presented in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”).

Liquidity and Capital Resources

The Company has incurred significant net losses available to common stockholders in recent years driven by primarily by deemed dividends on preferred stock resulting an accumulated deficit of $273.0 million and total stockholders’ deficit of $32.8 million as of December 31, 2025. For the years ended December 31, 2025 and 2024, the Company generated $39.1 million and $35.4 million, respectively, of cash flows from operating activities. As of December 31, 2025, the Company had cash and cash equivalents of $28.0 million. Historically, the Company has funded its operations principally through the sales of its oil, natural gas and NGLs production, issuance of preferred equity securities, debt financing and divestiture proceeds.

The Company’s financial statements have been prepared on the basis of the Company continuing as a going concern for the next 12 months. Management believes that the Company’s cash and cash equivalents will allow the Company to continue its planned operations for at least the next 12 months from the date of the issuance of these financial statements.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations and fair value estimates. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statement and the results presented in this Annual Report on Form 10-K are not necessarily indicative of future operating results.

Cash, Cash Equivalents and Restricted Cash

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the

consolidated balance sheets included in “Cash and cash equivalents” and “Restricted cash” reconcile to the Company’s consolidated statements of cash flows as follows:

Restricted cash consists primarily of funds to collateralize company credit cards.

Accounts Receivable and Allowance for Doubtful Accounts

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. Payment of the Company’s accounts receivable is typically received within 30-60 days. The Company’s historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of the Company’s counterparties.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company’s accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. The Company didnot capitalize any interest for the years ended December 31, 2025 and 2024.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining

lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

Other Operating Property and Equipment

Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: buildings, twenty years; automobiles andcomputers, three years; computer software, fixtures, furniture and equipment, five years; trailers, seven years; heavy equipment, eight toten years and leasehold improvements, lease term. Land and artwork are not depreciated. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its other operating property and equipment for impairment in accordance with the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC”) Topic 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

Concentrations of Credit Risk

The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable and of nonperformance by two counterparties under the Company’s derivative contracts. Each reporting period, the Company assesses the recoverability of material receivables using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions to determine expected collectability of its material receivables.

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts from its oil and natural gas purchasers. In 2025 and 2024, two individual purchasers of the Company’s production, Western Refining Company L.P. and Sunoco Inc., each accounted for more than 10% of total sales for the year, collectively representing 83% and 86% of its total sales, respectively.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. Joint operating agreements govern the operations of an oil or natural gas well and, in most instances, provide for offsetting of amounts payable or receivable between the Company and its joint interest owners. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

At December 31, 2025, the Company’s exposure to credit risk under its derivative contracts is currently limited totwo counterparties – a major financial institution that is a lender under the 2024 Amended Term Loan Agreement (as defined in Note 6, “Debt”) and a large multi-strategy alternative investment manager, both of which have investment

grade credit ratings. The Company has master netting agreements with both counterparties which provide for offsetting of amounts payable or receivable between the Company and the counterparty. To manage counterparty risk associated with derivative contracts, the Company selects and monitors counterparties based on an assessment of their financial strength and/or credit ratings.

Risk Management Activities

From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil and natural gas production. The Company recognizes all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

Income Taxes

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

The evaluation of a tax position in accordance with ASC Topic 740, Income Taxes (“ASC 740”) is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

Asset Retirement Obligations

The Company records asset retirement obligations (“AROs”) to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred.

The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its

ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.

Recently Issued Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09,Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”), which focuses on the income tax rate reconciliation and income taxes paid. ASU 2023-09 requires an entity to disclose, on an annual basis, a tabular rate reconciliation using both percentages and currency amounts, broken out into specified categories, with certain reconciling items further broken out by nature and jurisdiction to the extent those items exceed a specified threshold. In addition, entities are required to disclose income taxes paid, net of refunds received disaggregated by federal, state/local, and foreign, and by jurisdiction if the amount is at least 5% of total income tax payments, net of refunds received. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. An entity may apply the amendments in ASU 2023-09 prospectively by providing the revised disclosures for the period ending December 31, 2025 and continuing to provide the pre-ASU disclosures for the prior periods, or may apply the amendments retrospectively by providing the revised disclosures for all period presented. The requirements of ASU 2023-09 are disclosure-related and did not have an impact on the Company’s consolidated financial position or results of operations. See Note 13,“Income Taxes” for the updated income tax disclosures resulting from the adoption of ASU 2023-09.

In November 2024, the FASB issued ASU 2024-03,Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”), which requires public entities to disclose additional information about specific expense categories in the notes to the financial statements on an interim and annual basis. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim periods within the fiscal year beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2024-03.

2. SEGMENTS

The Company has determined that it operates asone reportable segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company evaluates performance based on consolidated income or loss from operations. The Company’s chief executive officer and chief operating officer together function as the Company’s chief operating decision maker (the “CODM”). The CODM evaluates and manages performance and resource allocation based on consolidated production and operating expenses. Significant expenses provided to the CODM for review consist of lease operating, workover and other, and gathering and other expenses. The Company’s significant segment expenses are derived from and can be found within the consolidated statement of operations. The measure of segment assets for the Company’s single reportable segment is “Total assets” as reported on the consolidated balance sheet.

3. LEASES

The Company leases equipment and office space pursuant to operating leases. The Company determines if an arrangement is or contains a lease at inception and combines lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. Operating leases with a lease term greater than 12 months where the Company is the lessee are included in*“Operating lease right of use assets”* and*“Operating lease liabilities”* on the consolidated balance sheets and recorded based on the present value of the future minimum lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The Company does not recognize right of use assets and lease liabilities for short-term leases that have a lease term of 12 months or less, but rather recognizes the lease payments associated with its short-term leases when incurred.

Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. Variable lease payments, if applicable, associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as*“Gathering and other”* or*“General and administrative”* in the consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

The table below summarizes the Company’s leases for the periods indicated (in thousands, except years and discount rate):

The*“Operating lease right of use assets”* outstanding on the consolidated balance sheet as of December 31, 2025 and 2024 resulted fromtwo operating leases initially entered into during the year ended December 31, 2023 with lease terms at inception of 1.9 years and 2.7 years. Both operating leases were extended during 2025 with one lease having an

extension of 18 months with an effective date of June 27, 2025 and the other extended for 12 months beyond its original expiration of July 1, 2026.

Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2025, are presented in the table below (in thousands):

4. OPERATING REVENUES

Substantially all of the Company’s oil, natural gas, and NGLs revenues are derived from the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. Revenue is presented disaggregated in the statement of operations by major product, and depicts how the nature, timing and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations.

Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the performance obligation is satisfied. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of each unit (e.g. barrel of oil, Mcf of natural gas) of commodity to the customer. Revenue is measured based on contract consideration allocated to each unit of commodity and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue.

Since the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $8.5 million and $23.5 million as of December 31, 2025 and 2024, respectively, as*“Accounts receivable, net”* on the consolidated balance sheets. The Company utilizes the practical expedient exempting the disclosure of the transaction price of unsatisfied performance obligations for (i) contracts with an original expected duration of one year or less and (ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied).

The Company records revenue in the month its production is delivered to the purchaser. However, to the extent settlement statements and/or payments are not available, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Oil Sales

The Company recognizes revenue when control of the crude oil transfers at the delivery point at the net price received. Generally, this occurs when the Company (i) sells its crude oil production at the wellhead where control of the

crude oil transfers to the customer at an index price, averaged over the daily settlement prices for a production month, and adjusted for pricing differentials and other deduction or (ii) when delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, averaged over the daily settlement prices for a production month, and net of applicable market-related adjustments. Settlement statements for the Company’s crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded.

Natural Gas and NGLs Sales

The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are treated as a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity’s processing plant, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as*“Natural gas”* or*“Natural gas liquids”* and any fees incurred to gather or process the natural gas are presented separately as*“Gathering and other”* on the consolidated statements of operations.

Under certain contracts, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “Gathering and other” on the consolidated statements of operations.

The majority of the Company’s natural gas and NGLs prices are based on daily average pricing for the month. Settlement statements for the Company’s natural gas and NGLs production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company’s estimates and the actual revenue received have not been material.

5. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consisted of the following (in thousands):

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $50.7 million and $51.3 million for the years ended December 31, 2025 and 2024, respectively. Depletion expense is recorded in*“Depletion, depreciation and accretion”* in the Company’s consolidated statements of operations.

The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

The ceiling test value of the Company’s reserves was calculated based on the following prices:

The Company's net book value of oil and natural gas properties for both 2025 and 2024 did not exceed the ceiling amount. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods.

West Quito Divestiture

On December 18, 2025, the Company entered into an agreement of sale and purchase with MCM Delaware Resources, LLC (“MCM”) (the “West Quito Divestiture Agreement”) to sell substantially all of its oil and natural gas properties and related assets in the West Quito Draw area located in the Southern Delaware Basin in Ward County, Texas for a total sales price of approximately $62.6 million, subject to adjustment for accounting between the effective date of December 1, 2025 and the closing date and other customary adjustments (the “West Quito Divestiture”).

6. DEBT

As of December 31, 2025 and 2024, the Company’s debt consisted of the following (in thousands):

Amended and Restated Credit Agreement

On December 26, 2024 (the “Initial Closing Date”), Halcón Holdings, LLC (the “Borrower”), a wholly-owned subsidiary of the Company, entered into a Second Amended and Restated Senior Secured Credit Agreement (the “2024 Term Loan Agreement”) with Fortress Credit Corp., as administrative agent, and certain other financial institutions party thereto, as lenders. The 2024 Term Loan Agreement amends and restates in its entirety the Company’s 2021 Amended Term Loan Agreement (as defined below). Pursuant to the 2024 Term Loan Agreement, the lenders party thereto agreed to provide the Borrower with (i) an initial term loan facility in the aggregate principal amount of $162.0 million, funded on December 26, 2024 and (ii) an incremental term loan facility in the aggregate principal amount of up to $63.0 million to be made available to the Borrower from January 3, 2025 until the date that is the earliest to occur of (x) the date on which such incremental term facility is fully drawn, (y) the date on which such incremental term facility is terminated and (z) January 11, 2025, subject to the satisfaction of certain conditions. On January 9, 2025, the Borrower entered into a first amendment (the “First Amendment”) to its 2024 Term Loan Agreement (as amended, the “2024 Amended Term Loan Agreement”). Pursuant to the First Amendment, the Borrower incurred incremental term loans in the aggregate principal amount of $63.0 million (the “Incremental Term Loans”).

The net proceeds of the 2024 Term Loan Agreement were used to repay all outstanding indebtedness under the 2021 Amended Term Loan Agreement, including accrued and unpaid interest, in an aggregate amount of approximately $152.1 million and to pay related fees and expenses. Upon extinguishment of the 2021 Amended Term Loan Agreement, the difference between the repayment amount of the extinguished debt and its respective carrying amount is recorded as a gain or loss on extinguishment of debt in the consolidated statement of operations. For the year ended December 31, 2024, the Company recognized a loss on extinguishment of debt in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt. Additionally, the Company deferred $4.3 million of original issue discount and financing costs on the consolidated balance sheet at December 31, 2024.

The maturity date of the 2024 Amended Term Loan Agreement is December 26, 2028.

Borrowings under the 2024 Amended Term Loan Agreement bear interest at a rate per annum equal to a forward-looking term rate based on the Secured Overnight Financing Rate (“SOFR”) for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.

On November 12, 2025, the Company entered into the Second Amendment to the Second Amended and Restated Senior Secured Credit Agreement (the “Second Amendment”), effective November 12, 2025, which amended the Applicable Margin (as defined in the 2024 Amended Term Loan Agreement) to be the rate per annum set forth below under the caption “SOFR Loans Spread” or “ABR Loans Spread”, as the case may be, based on the Total Net Leverage Ratio; provided that (a) until the Adjustment Date (the date of delivery of financial statements pursuant to the 2024 Amended Term Loan Agreement) following the Second Amendment effective date, the Applicable Margin shall be the applicable rate per annum set forth below in Category 1 and (b) the Applicable Margin shall be the applicable rate per annum set forth in Category 4 below at any time that an Event of Default (as defined in the 2024 Amended Term Loan Agreement) exists:

The Second Amendment provides that the Borrower shall not permit the Total Net Leverage Ratio, as of the last day of each fiscal quarter (commencing with the fiscal quarter ending March 31, 2025), to be greater than the levels set forth

in the following table for the applicable quarter:

Additionally, the Second Amendment provides that the Borrower shall not permit the Asset Coverage Ratio, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2025) to be less than the applicable level set forth in the following table for the applicable fiscal quarter:

The Second Amendment was accounted for as a debt modification in accordance with applicable accounting guidance.

The Borrower may elect, at its option, to prepay any borrowing outstanding under the 2024 Amended Term Loan Agreement. Such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:

In the event the Borrower shall receive a disapproval notice (as defined in the 2024 Term Loan Agreement) from the required lenders under the 2024 Amended Term Loan Agreement rejecting or otherwise disqualifying a proposed buyer in connection with a permitted change in control thereunder to be consummated within 12 months following the Initial Closing Date, such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:

The Borrower is required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding on the Initial Closing Date plus the Incremental Term Loans commencing with the fiscal quarter ending June 30, 2025. The Borrower may be required to make mandatory prepayments of the loans under the 2024 Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales and with excess cash on hand in excess of certain maximum levels.

Accordingly, upon closing of the West Quito Divestiture, the Company made a mandatory prepayment of $40.0 million on February 24, 2026.

Amounts outstanding under the 2024 Amended Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by the Company.

The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement), including the maintenance of the following ratios.

Under the 2024 Amended Term Loan Agreement, the Company is required to hedge approximately 85% to 50% of its anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. Entry into the 2024 Term Loan Agreement did not result in any material changes to the Company’s hedges. The 2024 Amended Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

In conjunction with entering into the 2024 Term Loan Agreement, the Company agreed to pay an exit fee equal to the amount resulting from multiplying 3.50% by the difference, if any, of (x) Total proved developed producing (“PDP”) PV-10 (the “PDP PV-10”) as of the date that is the earlier of (i) Payment in Full, (ii) the Maturity Date, or (iii) the loans and other obligations otherwise becoming immediately due and payable pursuant to Section 10.02 of the 2024 Term Loan Agreement (including whether, in the case of clauses (i) or (iii), such Payment in Full or acceleration, respectively, may be made in connection with a refinancing transaction or a disposition of all or substantially all of the assets of the Company) (such earlier date, the “Exit Fee Determination Date”), less (y) the Total PDP PV-10 reflected in the Initial Reserve Report (as defined in the 2024 Term Loan Agreement) (the “Exit Fee”). Upon evaluation of the payoff profiles associated with the Exit Fee, the Company concluded that such embedded features resulting from the application of this fee were not clearly and closely related to the host debt instrument. The fair value analysis for such derivative was performed and the fair value was deemed to bezero at commencement and at December 31, 2025. Refer to Note 7, “Fair Value Measurements,” for a discussion of the valuation approach used and the significant inputs to the valuation for the Exit Fee derivative.

Debt Maturities

Aggregate debt maturities under the 2024 Amended Term Loan Agreement due in future years as of December 31, 2025 are as follows (in thousands):

7. FAIR VALUE MEASUREMENTS

The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company separates the fair value of its financial instruments using a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There wereno transfers between fair value hierarchy levels for any period presented.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities associated with commodity-based derivative contracts that were accounted for at fair value as of December 31, 2025 and 2024 (in thousands):

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in*“Net gain on derivative contracts”* in the Company’s consolidated statements of operations. The Level 2 observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8,“Derivative and Hedging Activities,” for additional discussion of derivatives.

The Company’s derivative contracts are with a major financial institution and a large multi-strategy alternative investment manager, both of which have investment grade credit ratings and are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

As discussed in Note 6,“Debt,” the Company evaluated the 2024 Amended Term Loan Agreement and identified the Exit Fee to be an embedded derivative not clearly and closely related to the host debt instrument. The fair value analysis for such derivative was performed and the fair value was deemed to bezero at commencement and at December 31, 2025. The fair value of the Exit Fee derivative will be subsequently remeasured each reporting period with fair value changes recorded in “Interest expense and other” on the consolidated statement of operations. The valuation of the Exit Fee derivative included significant inputs such as the timing of potential exit scenarios, forward NYMEX strip pricing, forecasted capital and other expenditures and discount rates. The fair value of the Exit Fee derivative is classified as Level 3 in the fair value hierarchy.

Estimated fair value amounts have been determined at discrete points in time based on relevant market information. The estimated fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of borrowings under the Company’s Amended Term Loan Agreement approximate carrying value because the interest rates approximate current market rates.

The Company follows the provisions of the FASB’s ASC Topic 820,Fair Value Measurement for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of AROs for which fair value is used. The ARO estimates are derived from historical costs and

management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 9,“Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s AROs.

8. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the 2024 Amended Term Loan Agreement, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in*“Net gain on derivative contracts”* on the consolidated statements of operations. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.

The Company’s purchaser, gathering and/or processing, or transportation contracts have no net settlement provisions and no market mechanism to facilitate net settlement. As such, those contracts qualify for the normal purchase and normal sale exception under ASC 815. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2025, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s 2024 Amended Term Loan Agreement.

The Company’s crude oil and natural gas derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls further described as follows:

The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets (in thousands):

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands):

At December 31, 2025, the Company had the following open crude oil and natural gas derivative contracts:

The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2025 and 2024 (in thousands):

The Company enters into an International Swap Dealers Association Master Agreement (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting

of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

9. ASSET RETIREMENT OBLIGATIONS

The Company records an ARO on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records AROs to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities.

The Company recorded the following activity related to its ARO liability (inclusive of the current portion) (in thousands):

10. COMMITMENTS AND CONTINGENCIES

Commitments

In May 2022, the Company entered into a joint venture agreement to develop a strategic acid gas treatment and carbon sequestration facility andentered into a gas treating agreement. The Company hada minimum volume commitment of 20,000 Mcf per day under the gas treating agreement, with certain rollover rights and start-up flexibility, for an initial term offive years from the in-service date of the facility. Under the gas treating agreement, the Company paid a treating rate that varied based on volumes delivered to the facility. The gas treating agreement was terminated on January 19, 2026. For additional information on this joint venture, see Note 15,“Additional Financial Information.”

The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of December 31, 2025, the Company had in place multiple long-term crude oil and natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging fromone totwenty years from the date of first production.

Contingencies

In addition to the matters described below, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s consolidated operating results, financial position or cash flows.

Surface owners of properties in Louisiana, where the Company formerly operated, often file lawsuits or assert claims against oil and gas companies claiming that operators and working interest owners are liable for environmental

damages arising from operations conducted on the leased properties. These damages are frequently measured by the cost to restore the leased properties to their original condition. Currently and in the past, the Company has been party to such matters in Louisiana. With regard to pending matters, the overall exposure is not currently determinable. The Company intends to vigorously oppose these claims.

11. REDEEMABLE CONVERTIBLE PREFERRED STOCK

The table below summarizes the Company’s Redeemable Convertible Preferred Stock issuances as of December 31, 2025:

For accounting purposes, upon issuance of the preferred stock (collectively, the “Redeemable Convertible Preferred Stock”), the Company recorded the net proceeds as mezzanine equity (temporary equity) on the unaudited condensed consolidated balance sheets because it is not mandatorily redeemable but does contain a redemption feature at the option of the preferred holders that is considered not solely within the Company’s control.

The Company paid-in-kind its dividend on the preferred stock of $48.7 million and $31.0 million for the years ended December 31, 2025 and 2024, respectively. The carrying value of the preferred stock, inclusive of PIK dividends, is approximately $226.2 and $177.5 million for the years ended December 31, 2025 and 2024, respectively. PIK dividends are recognized first using the dividend date fair value and then adjusted to redemption value as long as the redemption value exceeds the initial dividend date fair value.

Voting Rights. Holders of shares of the Redeemable Convertible Preferred Stock haveno voting rights with respect to the shares of Redeemable Convertible Preferred Stock.

Dividends. Holders of Redeemable Convertible Preferred Stock are entitled to receive cumulative dividends at a fixed rate of 14.5% per annum on the Liquidation Preference ($1,000 per share, or $98.0 million, increased for any PIK accruals), compounding and accruing quarterly in arrears. Dividends may be paid in cash or, if not declared and paid in cash, the amount of any such dividend shall automatically accrue at a fixed rate of 16.0% per annum on the Liquidation Preference and be added to the Liquidation Preference (a “PIK Accrual”). Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends. Additionally, while the Company has not declared or paid dividends on its common stock since its inception, holders of preferred stock will be entitled to participate in any dividends or permitted distributions to holders of common stock on an as-converted basis should they occur.

Conversion Features. In addition to the conversion rights noted in “Redemption Features (Change of Control)” below, holders of Redeemable Convertible Preferred Stock may convert their shares into common stock at the Conversion Ratio equal to the then applicable Liquidation Preference at the time of conversion divided by the then applicable Conversion Price (initially equal to an 18% premium to the volume weighted average price of common stock for the 20 trading days immediately preceding the closing date). Additionally, the Company has the right, at its option, to convert outstanding shares of Redeemable Convertible Preferred Stock into common stock at the Conversion Ratio should the Company meet certain calculated valuation metrics which when divided by the number of outstanding shares of common stock equals or exceeds 130% of the Conversion Price.

*Redemption Features (Issuer).*The Company has the option to redeem the preferred stock in cash for an amount per share of Preferred Stock equal to (the “Redemption Price”):

Redemption Features (Change of Control). In the event of a change of control, holders have the right to receive:

12. STOCKHOLDERS’ (DEFICIT) EQUITY

Common Stock

Pursuant to the Company’s amended and restated certificate of incorporation with the Delaware Secretary of State, , among other things, (i) the total number of shares of all classes of capital stock that Battalion has the authority to issue is 101,000,000 of which 100,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share and (ii) Battalion is restricted from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code.

Incentive Plans

The Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the “Plan”), as amended in 2021, in which an aggregate of approximately 1.8 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. As of December 31, 2025, a maximum of 1.3 million shares of the Company’s common stock remained reserved for issuance under the Plan. For the years ended December 31, 2025 and 2024, the Company recognized an expense of less than $0.1 million and approximately $0.2 million, respectively, related to stock-based compensation awards granted to employees and directors, primarily related to restricted stock unit grants. Stock-based compensation is recorded as a component of*“General and administrative”*on the consolidated statements of operations.

Restricted Stock Units

From time to time, the Company grants shares of restricted stock units (“RSUs”) under the Plan to employees of the Company. Under the Plan, employee RSUs will vest and convert to shares typically in equal amounts over athree orfour year vesting period from the date of the grant, depending on award, or when the performance or market conditions

described below occur. At December 31, 2025, the Company hadno unrecognized compensation expense of unrecognized compensation expense related to non-vested RSU awards. At December 31, 2024, the Company had less than $0.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of 0.1 years.

The following table sets forth the restricted stock unit transactions for the periods indicated:

Equity Grant Units

During September and November 2024, the Company issued in aggregate 229,023 equity grant units (“EGUs”) to Company executives and certain eligible employees. Each EGU represented the right to receive a cash payment equivalent to the value of a share of the Company’s common stock upon the closing of a change of control event. In March 2025, all outstanding EGU awards were rescinded and cancelled. The Company didnot record any expense related to the EGUs during the year ended December 31, 2025.

Stock Options

Prior to 2020, the Company granted stock options under the Plan covering shares of common stock to employees of the Company. Stock options, if exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. Stock option awards granted under the Plan vest over afour-year period at a rate ofone-fourth on the annual anniversary date of the grant and expire seven years from the date of grant.

At December 31, 2025, the Company had 106,257 options outstanding (three equal tranches of 35,419 options atexercise prices of $18.91, $28.23, and $37.83 per share) with a weighted average exercise price of $28.32 per share and an expiration date of February 20, 2027. As of December 31, 2025, no options were either exercisable nor had intrinsic value due to service performance conditions and/or based on the exercise price of the option exceeding the closing market price. The weighted average remaining contractual life at December 31, 2025 was approximately 1.1 years. There isno unrecognized compensation expense remaining as the stock options were fully expensed as of December 31, 2025.** **

13. INCOME TAXES

Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands):

The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the year ended December 31, 2025:

The following table presents the required disclosures prior to the adoption of ASU 2023-09 and reconciles the actual income tax benefit (provision) to the expected income tax benefit (provision) as computed by applying the U.S. federal corporate income tax rate of 21% for the period presented (in thousands):

The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):

The amount of U.S. consolidated Net Operating Losses (“NOLs”) available as of December 31, 2025 after attribute reduction is estimated to be approximately $1.4 billion, but the amount after attribute reduction and the Section 382 limitation is $970.4 million. Of this amount, $88.9 million is subject to the 20-year carryforward period and will expire in 2037. The remaining $881.5 million may be carried forward indefinitely but is in part subject to a Section 382 limitation.

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2025, a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2025 of $316.4 million, a decrease of $1.0 million from December 31, 2024. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized.

ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company hasno unrecognized tax benefits for the year ended December 31, 2025 and 2024. Accordingly, there isno amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there isno amount of interest or penalties currently recognized in the consolidated statements of operations in*“Interest expense and other”*or consolidated balance sheets as of December 31, 2025 and 2024. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.

Generally, the Company’s income tax years 2021 through 2025 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three-year statue expiration period for federal purposes.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was enacted in the U.S. The OBBBA includes significant provisions, such as the permanent extension of certain expiring provisions of the Tax Cust and Jobs Act, modifications to the international tax framework and the restoration of favorable tax treatment for certain business provisions. The legislation has multiple effective dates, with certain provisions effective in 2025 and other implemented through 2027. These provisions had no impact on the Company’s consolidated financial statements for the year ended December 31, 2025. The Company is evaluating the impact of provisions required at future dates but does not expect such to have a material impact on its results of operations, cash flows or financial condition.

14. EARNINGS PER SHARE

The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):

For the year ended December 31, 2025, common stock equivalents, including stock options and certain restricted stock units, totaling 0.1 million weighted-average shares were anti-dilutive and not included in the computation of diluted earnings per share of common stock. For the year ended December 31, 2024, common stock equivalents, including stock options and certain restricted stock units, totaling 0.2 million weighted-average shares were anti-dilutive and not included in the computation of diluted earnings per share of common stock. Additionally, the Company also has less than 0.1 million restricted stock units that vest only upon achievement of certain business combination goals as further described in Note 12, “Stockholder’s Equity”.

15. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following (in thousands) for the periods presents:

Investment in Unconsolidated Affiliate. In May 2022, the Company entered into a joint venture with Caracara Services, LLC (“Caracara”) to develop an acid gas treatment facility to remove hydrogen sulfide and carbon dioxide from its produced natural gas. Caracara provided the initial capital for the construction of the treatment facility. The Company contributed certain full cost pool assets to the related party joint venture in a non-cash exchange for a retained 5% equity interest in Wink Amine Treater, LLC (“WAT”), an unconsolidated subsidiary. For accounting purposes, since the Company does not control thekey activities (e.g. operating and maintaining the facility) which most significantly impact economic performance, the Company is not the primary beneficiary of WAT. Accordingly, the Company accounted for its investment in WAT (a related party) using the equity method of accounting based on its ability to exercise significant influence, but not control, over thekey activities of the joint venture. During the fourth quarter of 2025, as a result of the AGI Facility’s continued shut-down, the Company concluded that the fair value of its equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on the consolidated balance sheet and recorded an impairment of $1.1 million to reduce the carrying value of the investment in unconsolidated affiliate asset tozero as of December 31, 2025. For more information related to this joint venture, see Note 10, “Commitments and Contingencies”.

Certain income statement amounts are comprised of the following (in thousands) for the periods presents:

16. SUBSEQUENT EVENTS

Subsequent events have been evaluated through the date of issuance of these financial statements and there have been no events subsequent to December 31, 2025, other than those items disclosed below, that would require additional adjustments to or disclosure in our financial statements during the period.

Pursuant to the West Quito Divestiture Agreement, on February 24, 2026, the Company completed the closing of the West Quito Divestiture and MCM acquired from the Company approximately 7,600 gross (6,100 net) acres of leasehold interests in the West Quito Draw area, including production from interests in producing wells, for net proceeds of approximately $60.1 million, reflecting adjustment for accounting effective date of December 1, 2025 and other customary adjustments. The Company will not record a gain or loss related to the divestiture as it was not significant to the full cost pool. Subsequent to closing, the Company used $45.6 million of the net proceeds from closing to repay amounts outstanding under the 2024 Amended Term Loan Agreement on February 24, 2026 - $40.0 million pursuant to the Third Amendment and prepayment of $5.6 million for the scheduled quarterly amortization payment for the quarterly period ending March 31, 2026.

On February 24, 2026, the Company entered into the Limited Consent, Third Amendment to Second Amended and Restated Senior Secured Credit Agreement and First Amendment to Fee Letter (the “Third Amendment”) to the 2024 Amended Term Loan Agreement. Pursuant to the Third Amendment, among other changes specified therein, (a) the lenders consented to the transactions contemplated by the West Quito Divestiture sale agreement; and (b) the Company was required, upon receipt of the net cash proceeds from the West Quito Divestiture, to prepay the outstanding principal amount of the 2024 Amended Term Loan Agreement borrowings in an aggregate amount equal to $40.0 million. The Company may retain the remaining net cash proceeds received from the West Quito Divestiture, subject to certain reinvestment requirements, set forth in the Third Amendment.

On March 3, 2026, the Company entered into a definitive agreement to sell in a private placement to an institutional investor 1,800,000 shares of its common stock and 927,273 prefunded warrants for the purchase of common stock at $5.50 per share for total proceeds of $15.0 million. The offering closed on March 4, 2026, on satisfaction of customary closing conditions.

On March 10, 2026, the Company entered into a purchase and sale agreement to acquire certain oil and natural gas assets, comprising 7,090 net acres located in Ward County, Texas, from RoadRunner Resource Holding LLC (formerly, Sundown Energy LP) (“RoadRunner”), effective March 1, 2026, in an all-stock transaction. Under the terms of the agreement, and upon closing on March 19, 2026, the Company issued 485,000 shares of its common stock to RoadRunner in exchange for the assets. The acquired acreage is directly adjacent to the Company’s existing Monument Draw acreage. The transaction is subject to customary post-closing adjustments and will be accounted for as an asset acquisition for the quarterly period ending March 31, 2026, allocating the relative amounts of the purchase price to proved and unproved oil and natural gas properties.