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Table of Contents

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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FORM 10-Q

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☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2025
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

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Commission File Number: 001-35467

Battalion Oil Corp oration

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) | 1311 (Primary Standard Industrial Classification Code Number) | 20-0700684 (I.R.S. Employer Identification Number)

820 Gessner Road, Suite 1100, Houston, TX 77024

(Address of principal executive offices)

(832) 538-0300

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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Securities registered pursuant to Section 12(b) of the Act:

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​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​
Title of each class | ​ | Trading Symbol | ​ | Name of each exchange on which registered
Common Stock, par value $0.0001 | ​ | BATL | ​ | NYSE American

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ⌧ No ◻

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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ⌧ No ◻

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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Large accelerated filer ◻ | Accelerated filer ◻ | Non-accelerated filer ☒ | ​ | ​

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Smaller reporting company ☒ | Emerging growth company ◻

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ⌧

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Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities made under a plan confirmed by a court. Yes ⌧ No ◻

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At August 7, 2025, 16,456,563 shares of the Registrant’s Common Stock were outstanding.

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Table of Contents

TABLE OF CONTENTS

​ | ​ | ​ | ​ | ​
​ |  | ​ |  | PAGE
PART I | ​ | FINANCIAL INFORMATION | ​ | ​
ITEM 1. | ​ | Condensed Consolidated Financial Statements (Unaudited) | ​ | 5
​ | ​ | Condensed Consolidated Statements of Operations (Unaudited) for the Three and Six Months Ended June 30, 2025 and 2024 | ​ | 5
​ | ​ | Condensed Consolidated Balance Sheets (Unaudited) at June 30, 2025 and December 31, 2024 | ​ | 6
​ | ​ | Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) for the Three and Six Months Ended June 30, 2025 and the Year Ended December 31, 2024 | ​ | 7
​ | ​ | Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2025 and 2024 | ​ | 8
​ | ​ | Notes to Unaudited Condensed Consolidated Financial Statements | ​ | 9
ITEM 2. | ​ | Management’s Discussion and Analysis of Financial Condition and Results of Operations | ​ | 25
ITEM 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk | ​ | 32
ITEM 4. | ​ | Controls and Procedures | ​ | 33
​ | ​ | ​ | ​ | ​
PART II | ​ | OTHER INFORMATION | ​ | ​
ITEM 1. | ​ | Legal Proceedings | ​ | 34
ITEM 1A. | ​ | Risk Factors | ​ | 34
ITEM 2. | ​ | Unregistered Sales of Equity Securities and Use of Proceeds | ​ | 34
ITEM 3. | ​ | Defaults Upon Senior Securities | ​ | 34
ITEM 4. | ​ | Mine Safety Disclosures | ​ | 34
ITEM 5. | ​ | Other Information | ​ | 34
ITEM 6. | ​ | Exhibits | ​ | 35
Signatures | ​ | ​ | ​ | 36
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Special note regarding forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, may be forward-looking statements, should be evaluated as such and may concern, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. These forward-looking statements may be identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “objective,” “believe,” “predict,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2024, as well as the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, which include, but are not limited to, the following factors:

| ● | volatility in prices for oil, natural gas and natural gas liquids (“NGLs”);

| ● | our ability to generate sufficient cash flows from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions;

| ● | contractual limitations that affect our management’s discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

| ● | our indebtedness, which may increase in the future, and higher levels of indebtedness can make us more vulnerable to economic downturns and adverse developments in our business;

| ● | our ability to replace our oil and natural gas reserves and production;

| ● | the presence or recoverability of estimated oil and natural gas reserves attributable to our properties and the actual future production rates and associated costs of producing those oil and natural gas reserves;

| ● | our ability to successfully develop our large inventory of undeveloped acreage;

| ● | the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars, which may be subject to inflation caused by labor shortages, supply shortages and increased demand, and other inflationary pressures;

| ● | our ability to secure adequate sour gas treating and/or sour gas take-away capacity, including the acid gas treatment facility for our Monument Draw area attaining targeted production volumes and costs in treating our sour gas;

| ● | drilling and operating risks, including accidents, equipment failures, fires, and releases of toxic or hazardous materials, such as hydrogen sulfide (H2S), which can result in injury, loss of life, pollution, property damage and suspension of operations;

| ● | senior management’s ability to execute our plans to meet our goals;

| ● | access to and availability of water, sand and other treatment materials to carry out fracture stimulations in our completion operations;

| ● | the possibility that our industry may be subject to future regulatory or legislative actions (including, but not limited to, additional taxes and changes in environmental regulations);

| ● | access to adequate gathering systems, processing and treating facilities and transportation take-away capacity to move our production to marketing outlets to sell our production at market prices;

| ● | our ability to pursue and integrate strategic mergers and acquisitions;

| ● | the potential for production decline rates for our wells to be greater than we expect;

| ● | competition, including competition for acreage in our resource play;

| ● | environmental risks, such as accidental spills of toxic or hazardous materials, and the potential for environmental liabilities;

| ● | exploration and development risks;

| ● | our ability to retain key members of senior management, the board of directors and key technical employees;

| ● | social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States (“U.S.”), such as the conflict between Ukraine and Russia, and acts of terrorism or sabotage;

| ● | impacts of climate regulations or lawsuits;

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| ● | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the U.S. will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

| ● | changes in U.S. trade policies, including the imposition of tariffs and retaliatory tariffs and their related impacts on the economy;

| ● | impacts and potential risks related to actual or anticipated pandemics, including any associated impact to our operations, financial results, liquidity, contractors, customers, employees and vendors;

| ● | impacts and potential risks of extreme weather;

| ● | other economic, competitive, governmental, regulatory, legislative, including federal and state regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

| ● | our insurance coverage may not adequately cover all losses that we may sustain; and

| ● | title to the properties in which we have an interest that may be impaired by title defects.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

BATTALION OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | June 30, | ​ | June 30,
​ | ​ | 2025 | ​ | 2024 | ​ | 2025 | ​ | 2024
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 36,291 | ​ | $ | 45,699 | ​ | $ | 75,991 | ​ | $ | 88,128
Natural gas | ​ | ​ | 935 | ​ | ​ | (2,119) | ​ | ​ | 3,758 | ​ | ​ | (72)
Natural gas liquids | ​ | ​ | 5,350 | ​ | ​ | 5,503 | ​ | ​ | 10,212 | ​ | ​ | 10,559
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 42,576 | ​ | ​ | 49,083 | ​ | ​ | 89,961 | ​ | ​ | 98,615
Other | ​ | ​ | 236 | ​ | ​ | 21 | ​ | ​ | 326 | ​ | ​ | 359
Total operating revenues | ​ | ​ | 42,812 | ​ | ​ | 49,104 | ​ | ​ | 90,287 | ​ | ​ | 98,974
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,670 | ​ | ​ | 11,005 | ​ | ​ | 21,028 | ​ | ​ | 22,591
Workover and other | ​ | ​ | 2,309 | ​ | ​ | 951 | ​ | ​ | 3,742 | ​ | ​ | 1,839
Taxes other than income | ​ | ​ | 2,522 | ​ | ​ | 3,349 | ​ | ​ | 5,322 | ​ | ​ | 6,340
Gathering and other | ​ | ​ | 10,958 | ​ | ​ | 12,126 | ​ | ​ | 22,958 | ​ | ​ | 29,412
General and administrative | ​ | ​ | 2,567 | ​ | ​ | 3,340 | ​ | ​ | 6,980 | ​ | ​ | 7,411
Depletion, depreciation and accretion | ​ | ​ | 13,939 | ​ | ​ | 13,213 | ​ | ​ | 27,019 | ​ | ​ | 26,238
Total operating expenses | ​ | ​ | 42,965 | ​ | ​ | 43,984 | ​ | ​ | 87,049 | ​ | ​ | 93,831
(Loss) income from operations | ​ | ​ | (153) | ​ | ​ | 5,120 | ​ | ​ | 3,238 | ​ | ​ | 5,143
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | 11,548 | ​ | ​ | 1,223 | ​ | ​ | 20,850 | ​ | ​ | (22,964)
Interest expense and other | ​ | ​ | (6,599) | ​ | ​ | (6,448) | ​ | ​ | (13,269) | ​ | ​ | (13,486)
Total other income (expenses) | ​ | ​ | 4,949 | ​ | ​ | (5,225) | ​ | ​ | 7,581 | ​ | ​ | (36,450)
Income (loss) before income taxes | ​ | ​ | 4,796 | ​ | ​ | (105) | ​ | ​ | 10,819 | ​ | ​ | (31,307)
Income tax benefit (provision) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Net income (loss) | ​ | $ | 4,796 | ​ | $ | (105) | ​ | $ | 10,819 | ​ | $ | (31,307)
Preferred dividends | ​ | ​ | (8,270) | ​ | ​ | (8,586) | ​ | ​ | (20,090) | ​ | ​ | (14,218)
Net loss available to common stockholders | ​ | $ | (3,474) | ​ | $ | (8,691) | ​ | $ | (9,271) | ​ | $ | (45,525)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss per share of common stock available to common stockholders: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | $ | (0.21) | ​ | $ | (0.53) | ​ | $ | (0.56) | ​ | $ | (2.77)
Diluted | ​ | $ | (0.21) | ​ | $ | (0.53) | ​ | $ | (0.56) | ​ | $ | (2.77)
Weighted average common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457
Diluted | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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BATTALION OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2025 | ​ | December 31, 2024
Current assets: | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 44,621 | ​ | $ | 19,712
Accounts receivable, net | ​ | ​ | 24,464 | ​ | ​ | 26,298
Assets from derivative contracts | ​ | ​ | 13,717 | ​ | ​ | 6,969
Restricted cash | ​ | ​ | 91 | ​ | ​ | 91
Prepaids and other | ​ | ​ | 569 | ​ | ​ | 982
Total current assets | ​ | ​ | 83,462 | ​ | ​ | 54,052
Oil and natural gas properties (full cost method): | ​ | ​ | ​ | ​ | ​ | ​
Evaluated | ​ | ​ | 876,736 | ​ | ​ | 816,186
Unevaluated | ​ | ​ | 49,091 | ​ | ​ | 49,091
Gross oil and natural gas properties | ​ | ​ | 925,827 | ​ | ​ | 865,277
Less: accumulated depletion | ​ | ​ | (523,500) | ​ | ​ | (497,272)
Net oil and natural gas properties | ​ | ​ | 402,327 | ​ | ​ | 368,005
Other operating property and equipment: | ​ | ​ | ​ | ​ | ​ | ​
Other operating property and equipment | ​ | ​ | 4,677 | ​ | ​ | 4,663
Less: accumulated depreciation | ​ | ​ | (2,696) | ​ | ​ | (2,455)
Net other operating property and equipment | ​ | ​ | 1,981 | ​ | ​ | 2,208
Other noncurrent assets: | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | ​ | 6,344 | ​ | ​ | 4,052
Operating lease right of use assets | ​ | ​ | 1,000 | ​ | ​ | 453
Other assets | ​ | ​ | 3,667 | ​ | ​ | 2,278
Total assets | ​ | $ | 498,781 | ​ | $ | 431,048
​ | ​ | ​ | ​ | ​ | ​ | ​
Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable and accrued liabilities | ​ | $ | 62,286 | ​ | $ | 52,682
Liabilities from derivative contracts | ​ | ​ | 4,483 | ​ | ​ | 12,330
Current portion of long-term debt | ​ | ​ | 22,553 | ​ | ​ | 12,246
Operating lease liabilities | ​ | ​ | 720 | ​ | ​ | 406
Total current liabilities | ​ | ​ | 90,042 | ​ | ​ | 77,664
Long-term debt, net | ​ | ​ | 191,467 | ​ | ​ | 145,535
Other noncurrent liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | ​ | 4,764 | ​ | ​ | 6,954
Asset retirement obligations | ​ | ​ | 19,812 | ​ | ​ | 19,156
Operating lease liabilities | ​ | ​ | 307 | ​ | ​ | 84
Commitments and contingencies (Note 9) | ​ | ​ | ​ | ​ | ​ | ​
Temporary equity: | ​ | ​ | ​ | ​ | ​ | ​
Redeemable convertible preferred stock: 138,000 shares | ​ | ​ | 197,625 | ​ | ​ | 177,535
of $0.0001 par value authorized, issued and outstanding | ​ | ​ | ​ | ​ | ​ | ​
at June 30, 2025 and December 31, 2024 | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity: | ​ | ​ | ​ | ​ | ​ | ​
Common stock: 100,000,000 shares of $0.0001 par value authorized; | ​ | ​ | ​ | ​ | ​ | ​
16,456,563 shares issued and outstanding at June 30, 2025 and | ​ | ​ | ​ | ​ | ​ | ​
December 31, 2024 | ​ | ​ | 2 | ​ | ​ | 2
Additional paid-in capital | ​ | ​ | 268,818 | ​ | ​ | 288,993
Accumulated deficit | ​ | ​ | (274,056) | ​ | ​ | (284,875)
Total stockholders' (deficit) equity | ​ | ​ | (5,236) | ​ | ​ | 4,120
Total liabilities, temporary equity and stockholders' equity | ​ | $ | 498,781 | ​ | $ | 431,048
​ | ​ | ​ | ​ | ​ | ​ | ​

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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BATTALION OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Retained | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Additional | ​ | Earnings | ​ | ​ | ​
​ | ​ | Common Stock | ​ | Paid-In | ​ | (Accumulated | ​ | Stockholders'
​ |  | Shares |  | Amount |  | Capital |  | Deficit) |  | Equity
Balances at December 31, 2023 | ​ | 16,457 | ​ | $ | 2 | ​ | $ | 321,012 | ​ | $ | (252,993) | ​ | $ | 68,021
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (31,203) | ​ | ​ | (31,203)
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (5,632) | ​ | ​ | — | ​ | ​ | (5,632)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 127 | ​ | ​ | — | ​ | ​ | 127
Balances at March 31, 2024 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 315,507 | ​ | ​ | (284,196) | ​ | ​ | 31,313
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (105) | ​ | ​ | (105)
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (8,586) | ​ | ​ | — | ​ | ​ | (8,586)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 48 | ​ | ​ | — | ​ | ​ | 48
Balances at June 30, 2024 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 306,969 | ​ | ​ | (284,301) | ​ | ​ | 22,670
Net income | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 21,628 | ​ | ​ | 21,628
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (9,321) | ​ | ​ | — | ​ | ​ | (9,321)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 7 | ​ | ​ | — | ​ | ​ | 7
Balances at September 30, 2024 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 297,655 | ​ | ​ | (262,673) | ​ | ​ | 34,984
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (22,202) | ​ | ​ | (22,202)
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (8,680) | ​ | ​ | — | ​ | ​ | (8,680)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 18 | ​ | ​ | — | ​ | ​ | 18
Balances at December 31, 2024 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 288,993 | ​ | ​ | (284,875) | ​ | ​ | 4,120
Net income | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6,023 | ​ | ​ | 6,023
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (11,820) | ​ | ​ | — | ​ | ​ | (11,820)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | (85) | ​ | ​ | — | ​ | ​ | (85)
Balances at March 31, 2025 | ​ | 16,457 | ​ | $ | 2 | ​ | $ | 277,088 | ​ | $ | (278,852) | ​ | $ | (1,762)
Net income | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 4,796 | ​ | ​ | 4,796
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (8,270) | ​ | ​ | — | ​ | ​ | (8,270)
Balances at June 30, 2025 | ​ | 16,457 | ​ | $ | 2 | ​ | $ | 268,818 | ​ | $ | (274,056) | ​ | $ | (5,236)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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BATTALION OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Six Months Ended
​ | June 30,
​ | 2025 | ​ | 2024
Cash flows from operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | 10,819 | ​ | $ | (31,307)
Adjustments to reconcile net income (loss) to net cash | ​ | ​ | ​ | ​ | ​ | ​
provided by operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Depletion, depreciation and accretion | ​ | ​ | 27,019 | ​ | ​ | 26,238
Stock-based compensation, net | ​ | ​ | (109) | ​ | ​ | 135
Unrealized (gain) loss on derivative contracts | ​ | ​ | (19,076) | ​ | ​ | 15,327
Amortization/accretion of financing related costs | ​ | ​ | 792 | ​ | ​ | 3,390
Accrued settlements on derivative contracts | ​ | ​ | (537) | ​ | ​ | 774
Change in fair value of embedded derivative liability | ​ | ​ | — | ​ | ​ | (1,365)
Other | ​ | ​ | 109 | ​ | ​ | 179
Change in assets and liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | 3,186 | ​ | ​ | (445)
Prepaids and other | ​ | ​ | 412 | ​ | ​ | 85
Accounts payable and accrued liabilities | ​ | ​ | 321 | ​ | ​ | 20,730
Net cash provided by operating activities | ​ | ​ | 22,936 | ​ | ​ | 33,741
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​
Oil and natural gas capital expenditures | ​ | ​ | (53,090) | ​ | ​ | (44,849)
Proceeds received from sale of oil and natural gas assets | ​ | ​ | — | ​ | ​ | 7,015
Acquisition of oil and natural gas properties | ​ | ​ | — | ​ | ​ | (47)
Contract asset | ​ | ​ | — | ​ | ​ | (7,795)
Other operating property and equipment capital expenditures | ​ | ​ | (14) | ​ | ​ | (17)
Other | ​ | ​ | (370) | ​ | ​ | (13)
Net cash used in investing activities | ​ | ​ | (53,474) | ​ | ​ | (45,706)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: | ​ | ​ | ​ | ​ | ​ | ​
Proceeds from borrowings | ​ | ​ | 63,000 | ​ | ​ | —
Repayments of borrowings | ​ | ​ | (5,678) | ​ | ​ | (39,853)
Debt issuance costs | ​ | ​ | (1,875) | ​ | ​ | —
Payment of debt financing costs | ​ | ​ | — | ​ | ​ | (129)
Proceeds from issuance of preferred stock | ​ | ​ | — | ​ | ​ | 38,849
Merger deposit | ​ | ​ | — | ​ | ​ | 10,000
Net cash provided by financing activities | ​ | ​ | 55,447 | ​ | ​ | 8,867
​ | ​ | ​ | ​ | ​ | ​ | ​
Net increase (decrease) in cash, cash equivalents and restricted cash | ​ | ​ | 24,909 | ​ | ​ | (3,098)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash, cash equivalents and restricted cash at beginning of period | ​ | ​ | 19,803 | ​ | ​ | 57,619
Cash, cash equivalents and restricted cash at end of period | ​ | $ | 44,712 | ​ | $ | 54,521
​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow information: | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for interest | ​ | $ | 13,892 | ​ | $ | 12,512
​ | ​ | ​ | ​ | ​ | ​ | ​

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

Battalion Oil Corporation (“Battalion” or the “Company”) 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. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated.

These unaudited condensed consolidated financial statements reflect, in the opinion of the Company’s management, all adjustments, consisting of normal and recurring adjustments, necessary to present fairly the financial position as of, and the results of operations for, the periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”), has been condensed or omitted. During interim periods, Battalion follows the accounting policies disclosed in its Annual Report on Form 10-K, as filed with the U.S. Securities and Exchange Commission (the “SEC”) on March 31, 2025. Please refer to the notes in the Annual Report on Form 10-K for the year ended December 31, 2024 when reviewing interim financial results. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Liquidity and Cash Requirements

The accompanying unaudited condensed consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

​

The Company’s ability to execute its operating strategy is dependent on its ability to maintain adequate liquidity and continue to access capital, as needed. The Company generated net income of $10.8 million for the six months ended June 30, 2025 and had negative working capital of $6.6 million as of June 30, 2025. At June 30, 2025, the Company had $44.6 million of cash and cash equivalents, no additional borrowing capacity under the 2024 Amended Term Loan Agreement (as defined in Note 5, “Debt” to the unaudited condensed consolidated financial statements) and a total of $22.5 million in debt repayments due through June 30, 2026 under its 2024 Amended Term Loan Agreement. The Company’s current business estimates and forecasts indicate that it will require additional liquidity to meet its debt covenant requirements for the next 12 months from the issuance of these unaudited condensed consolidated financial statements. In response to these events and conditions, the Company has continued to execute on a plan to reduce operating and capital costs to improve cash flows. The Company also has obtained a support letter from its three largest current related party investors to purchase additional preferred equity securities in an amount up to $30.0 million on or before August 31, 2026. Management believes that based upon its operational forecasts, cash and cash equivalents on hand, cost reduction measures and the commitment of the investors to purchase up to $30.0 million in additional preferred equity, it is probable the Company will have sufficient liquidity to maintain compliance with its debt covenants, as described in Note 5, “Debt,” for the next 12 months from the issuance of these unaudited condensed consolidated financial statements.

Use of Estimates

The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with 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 unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 (“AROs”), 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 unaudited condensed consolidated financial statements.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | June 30, 2025 | ​ | December 31, 2024
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 44,621 | ​ | $ | 19,712
Restricted cash | ​ | ​ | 91 | ​ | ​ | 91
Total cash, cash equivalents and restricted cash | ​ | $ | 44,712 | ​ | $ | 19,803

​

Restricted cash consists 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.

Concentrations of Credit Risk

The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable and of nonperformance by 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 exposure to credit risk under its derivative contracts is currently limited to one major financial institution with investment grade credit ratings, where it has master netting agreements 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. At June 30, 2025, the Company’s derivative counterparty is a major financial institution and a lender under the 2024 Amended Term Loan Agreement (as defined in Note 5, “Debt”).

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Recently Issued Accounting Pronouncements and Legislation

In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 Company is currently evaluating the impact of adopting ASU 2023-09 but does not expect it to have a material impact on its disclosures, with no impact to its results of operations, cash flows, or financial condition.

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40) (“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.

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 Cuts 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 others implemented through 2027. The Company is currently assessing the OBBBA's impact on its consolidated financial statements.

2. SEGMENTS

The Company has determined that it operates as one 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 expenses, workover and other expense and gathering and other expense. The Company’s significant segment expenses are derived from and can be found within the unaudited condensed consolidated statement of operations. The measure of segment assets for the Company’s single reportable segment is “Total assets” as reported on the unaudited condensed consolidated balance sheets.

3. OPERATING REVENUES

Substantially all of the Company’s oil, natural gas and natural gas liquids (“NGLs”) revenues are derived from the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. Revenue is presented disaggregated in the unaudited condensed consolidated statements 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

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transaction price to the performance obligations in the contract and (5) recognize revenue when the performance obligation is satisfied. Revenues from the sale of crude oil, natural gas and NGLs 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 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.

Because 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 for sales of oil, natural gas and NGLs of $19.3 million and $23.5 million at June 30, 2025 and December 31, 2024, respectively, as “Accounts receivable, net” on the unaudited condensed 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).

For additional information regarding the Company’s operating revenues, refer to its Annual Report on Form 10-K for the year ended December 31, 2024.

4. OIL AND NATURAL GAS PROPERTIES

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. 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.

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.

At June 30, 2025 and 2024, using first-day-of-the-month average West Texas Intermediate (“WTI”) crude oil spot prices and Henry Hub natural gas prices for the respective prior 12-month periods, the Company’s net book value of oil and natural gas properties at June 30, 2025 and 2024, did not exceed the ceiling test value of the Company’s reserves. Oil and natural gas prices utilized for the ceiling test calculations at June 30, 2025 and 2024 were $71.20 per barrel and $79.45 per barrel of oil, respectively, and $2.86 per MMBtu and $2.32 per MMBtu for natural gas, respectively.

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. Additionally, because oil and natural gas prices are inherently volatile, sustained lower commodity prices would reduce the calculated first-day-of-the-month average prices which

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could result in non-cash impairment charges of the Company’s oil and natural gas properties under its full cost ceiling test calculation, negatively impacting earnings and financial position.

5. DEBT

The Company’s debt consisted of the following for the periods presented (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2025 | ​ | ​ | December 31, 2024
Term loan credit facility | ​ | $ | 219,375 | ​ | ​ | $ | 162,000
Other | ​ | ​ | 53 | ​ | ​ | ​ | 106
Total debt (Face Value) | ​ | ​ | 219,428 | ​ | ​ | ​ | 162,106
Less: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Current portion of long-term debt(1) | ​ | ​ | (22,553) | ​ | ​ | ​ | (12,246)
Other(2) | ​ | ​ | (5,408) | ​ | ​ | ​ | (4,325)
Long-Term Debt, net | ​ | $ | 191,467 | ​ | ​ | $ | 145,535

(1) | Amounts primarily reflect amortization payments of $22.5 million and $12.2 million due under the Company’s 2024 Amended Term Loan Agreement within one year at June 30, 2025 and December 31, 2024, respectively.

(2) | Amounts reflect unamortized debt discount and issuance costs of approximately $5.4 million and $4.3 million at June 30, 2025 and December 31, 2024, respectively. For the six months ended June 30, 2025 and 2024, the Company recorded approximately $0.8 million and $3.4 million, respectively, in interest expense reflecting the amortization/accretion of deferred financing costs and debt discount.

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 was 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. 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 included 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 unaudited condensed consolidated balance sheet at December 31, 2024 in conjunction with entry into the 2024 Term Loan Agreement and deferred an additional $1.8 million of original issue discount and financing costs on the unaudited condensed consolidated balance sheet at June 30, 2025 in conjunction with the issuance of the Incremental Term Loans in January 2025.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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%. The weighted average interest rate on the Company’s borrowings under the 2024 Amended Term Loan Agreement for the quarter ended June 30, 2025 was 12.20%.

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:

​

​ | ​ | ​ | ​
Period | ​ | ​ | Premium
Months 0 - 12 | ​ | ​ | Make-whole amount equal to 12 months of interest plus 4.00%
Months 13 - 30 | ​ | ​ | 2.00%
Thereafter | ​ | ​ | 0.00%

​

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:

​

​ | ​ | ​ | ​
Period | ​ | ​ | Premium
Months 0 - 9 | ​ | ​ | Make-whole amount equal to 9 months of interest plus 2.00%
Months 10 - 30 | ​ | ​ | 2.00%
Thereafter | ​ | ​ | 0.00%

​

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. The Borrower is required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the total aggregate principal amount of the loans outstanding and such payments commenced with the $5.6 million repayment for fiscal quarter ending June 30, 2025.

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:

| ● | Asset Coverage Ratio not to fall below 1.70 x as of March 31, 2025 through and including June 30, 2025, 1.85 x as of September 30, 2025 through and including December 31, 2025 and 2.00 x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

| ● | Total Net Leverage Ratio not to exceed 2.75 x as of March 31, 2025 through and including June 30, 2025 and 2.50 x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

| ● | Current Ratio not to fall below 1.00 x, determined on the last day of each calendar month commencing with the calendar month ending March 31, 2025; and

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| ● | Liquidity not to fall below the greater of (x) $10,000,000 and (y) the amount equal to the scheduled principal and interest payments for the immediately succeeding three-month period, determined as of the last day of any fiscal quarter.

At June 30, 2025, the Company was in compliance with all financial covenants under the 2024 Amended Term Loan Agreement.

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 be zero at commencement, at December 31, 2024 and at June 30, 2025. Refer to Note 6, “Fair Value Measurements,” for a discussion of the valuation approach used and the significant inputs to the valuation for the Exit Fee derivative.

Term Loan Credit Facility

On November 24, 2021, the Company and Borrower entered into an Amended and Restated Senior Secured Credit Agreement (the “2021 Term Loan Agreement”) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders, having a maturity date of November 24, 2025 (as subsequently amended, the “2021 Amended Term Loan Agreement”).

All obligations under the 2021 Amended Term Loan Agreement were refunded, refinanced and repaid in full by the loans under the 2024 Term Loan Agreement on December 26, 2024.

Borrowings under the 2021 Amended Term Loan Agreement bore interest at a variable interest rate based on SOFR plus an applicable margin of 7.5%. The weighted average interest rate on the Company’s term loan borrowings under the 2021 Amended Term Loan Agreement for the quarter ended June 30, 2024 was approximately 12.95%.

6. 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 unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined 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

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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 were no 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 at June 30, 2025 and December 31, 2024 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2025
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ | $ | 20,061 | ​ | $ | — | ​ | $ | 20,061
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | $ | 9,247 | ​ | $ | — | ​ | $ | 9,247

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2024
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ | $ | 11,021 | ​ | $ | — | ​ | $ | 11,021
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | $ | 19,284 | ​ | $ | — | ​ | $ | 19,284

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, 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 (loss) on derivative contracts” in the Company’s unaudited condensed 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 7, “Derivative and Hedging Activities,” for additional discussion of derivatives.

The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which 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 5, “Debt,” the Company evaluated the 2024 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 be zero at commencement, at December 31, 2024 and at June 30, 2025. The fair value of the Exit Fee derivative is remeasured each reporting period with fair value changes recorded in “Interest Expense and other” on the unaudited condensed consolidated statement of operations. The valuation of the Exit Fee derivative includes significant inputs such as the timing of potential exit scenarios, forward NYMEX strip

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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. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and 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 approximates carrying value because the variable interest rates approximate current market rates.

The Company follows the provisions of the FASB’s Accounting Standards Codification (“ASC”) 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 8, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s AROs.

7. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to commodity price risks relating to its ongoing business operations. In accordance with the Company’s policy and the requirements under the 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 unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed 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 (loss) on derivative contracts” on the unaudited condensed 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.

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. At June 30, 2025, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s 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:

| ● | Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas.

| ● | Costless collars consist of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price and are generally utilized less frequently by the Company than fixed-price swaps.

| ● | Basis swaps effectively lock in a price differential between regional prices (i.e., Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e., Cushing).

| ● | WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing.

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The following table summarizes the location and fair value amounts of all commodity derivative contracts in the unaudited condensed consolidated balance sheets at June 30, 2025 and December 31, 2024 (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance sheet location |  | June 30, 2025 |  | December 31, 2024 |  | Balance sheet location |  | June 30, 2025 |  | December 31, 2024
Current assets | ​ | $ | 13,717 | ​ | $ | 6,969 | ​ | Current liabilities | ​ | $ | (4,483) | ​ | $ | (12,330)
Other noncurrent assets | ​ | ​ | 6,344 | ​ | ​ | 4,052 | ​ | Other noncurrent liabilities | ​ | ​ | (4,764) | ​ | ​ | (6,954)
​ | ​ | $ | 20,061 | ​ | $ | 11,021 | ​ | ​ | ​ | $ | (9,247) | ​ | $ | (19,284)

​

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 unaudited condensed consolidated statements of operations (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Location of gain (loss) | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | on derivative contracts on | ​ | June 30, | ​ | June 30,
Type |  | Statement of Operations | ​ | 2025 | ​ | 2024 | ​ | 2025 | ​ | 2024
Commodity contracts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unrealized gain (loss) | ​ | Other income (expenses) | ​ | $ | 7,248 | ​ | $ | 4,434 | ​ | $ | 19,076 | ​ | $ | (15,327)
Realized (loss) gain | ​ | Other income (expenses) | ​ | ​ | 4,300 | ​ | ​ | (3,211) | ​ | ​ | 1,774 | ​ | ​ | (7,637)
Total net gain (loss) | ​ | ​ | ​ | $ | 11,548 | ​ | $ | 1,223 | ​ | $ | 20,850 | ​ | $ | (22,964)

​

At June 30, 2025, the Company had the following open crude oil and natural gas derivative contracts:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Instrument |  | ​ | 2025 |  | ​ | 2026 | ​ | ​ | 2027 | ​ | ​ | 2028 | ​ | ​ | 2029 | ​
Crude oil: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed-price swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 1,042,821 | ​ | ​ | 1,452,884 | ​ | ​ | 976,223 | ​ | ​ | 692,020 | ​ | ​ | 140,544 | ​
Weighted average price | ​ | $ | 65.37 | ​ | $ | 64.57 | ​ | $ | 62.16 | ​ | $ | 62.31 | ​ | $ | 60.14 | ​
Basis swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 1,051,329 | ​ | ​ | 1,459,912 | ​ | ​ | 980,339 | ​ | ​ | 692,020 | ​ | ​ | 140,544 | ​
Weighted average price | ​ | $ | 0.46 | ​ | $ | 0.50 | ​ | $ | 0.55 | ​ | $ | 0.66 | ​ | $ | 0.68 | ​
WTI NYMEX roll: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 1,051,329 | ​ | ​ | 1,459,912 | ​ | ​ | 980,339 | ​ | ​ | 692,020 | ​ | ​ | 140,544 | ​
Weighted average price | ​ | $ | 0.46 | ​ | $ | 0.03 | ​ | $ | (0.04) | ​ | $ | (0.23) | ​ | $ | (0.29) | ​
Natural gas: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed-price swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 2,582,845 | ​ | ​ | 1,098,125 | ​ | ​ | 1,739,001 | ​ | ​ | 2,010,469 | ​ | ​ | 527,049 | ​
Weighted average price | ​ | $ | 3.36 | ​ | $ | 3.90 | ​ | $ | 3.77 | ​ | $ | 3.36 | ​ | $ | 3.84 | ​
Two-way collar: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 773,358 | ​ | ​ | 3,780,627 | ​ | ​ | 1,811,553 | ​ | ​ | 539,931 | ​ | ​ | — | ​
Weighted average price (call) | ​ | $ | 6.36 | ​ | $ | 4.53 | ​ | $ | 4.67 | ​ | $ | 3.90 | ​ | $ | — | ​
Weighted average price (put) | ​ | $ | 3.74 | ​ | $ | 3.65 | ​ | $ | 3.62 | ​ | $ | 3.50 | ​ | $ | — | ​
Basis swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 3,345,416 | ​ | ​ | 4,839,568 | ​ | ​ | 3,531,961 | ​ | ​ | 2,550,400 | ​ | ​ | 527,049 | ​
Weighted average price | ​ | $ | (0.88) | ​ | $ | (1.01) | ​ | $ | (0.84) | ​ | $ | (0.86) | ​ | $ | (0.89) | ​

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed 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 June 30, 2025 and December 31, 2024 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Assets from Derivative Contracts | ​ | Liabilities from Derivative Contracts
Offsetting of Derivative Assets and Liabilities |  | June 30, 2025 |  | December 31, 2024 |  | June 30, 2025 |  | December 31, 2024
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gross amounts recognized in the Unaudited Condensed Consolidated Balance Sheet | ​ | $ | 20,061 | ​ | $ | 11,021 | ​ | $ | (9,247) | ​ | $ | (19,284)
Amounts not offset in the Unaudited Condensed Consolidated Balance Sheet | ​ | ​ | (9,247) | ​ | ​ | (11,021) | ​ | ​ | 9,247 | ​ | ​ | 11,021
Net amount | ​ | $ | 10,814 | ​ | $ | — | ​ | $ | — | ​ | $ | (8,263)

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.

8. 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 the ARO liability on the unaudited condensed 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 unaudited condensed consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.

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

​ | ​ | ​ | ​
Liability for asset retirement obligations at December 31, 2024 | ​ | $ | 19,156
Accretion expense | ​ | ​ | 550
Liabilities incurred | ​ | ​ | 106
Liability for asset retirement obligations at June 30, 2025 | ​ | $ | 19,812

​

9. COMMITMENTS AND CONTINGENCIES

Commitments

In May 2022, the Company entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility and entered into a gas treating agreement with Wink Amine Treater, LLC (“WAT”). The Company has a 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 of five years from the in-service date of the facility. Under the gas treating agreement, the Company currently pays a treating rate that begins at $1.44/Mcf and varies based on volumes delivered to the facility. For additional information on this joint venture, see Note 12, “Additional Financial Statement 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. At June 30, 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

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 from one to twenty years from the date of first production.

Contingencies

In addition to the matter 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 unaudited condensed 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 natural 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.

10. REDEEMABLE CONVERTIBLE PREFERRED STOCK

The table below summarizes the Company’s Redeemable Convertible Preferred Stock issuances at June 30, 2025:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Preferred Stock (1) | ​ | Issuance Date | ​ | Shares | ​ | Conversion Price | ​ | Net Equity Recorded (2) (in thousands) | ​ | Cumulative Non-cash Deemed Dividends (2) (in thousands) | ​ | Total Net Equity & Cumulative Deemed Dividends (in thousands) | ​ | Initial Deemed Dividend Date | ​
Series A | ​ | March 28, 2023 | ​ | 25,000 | ​ | $ | 9.03 | ​ | $ | 23,541 | ​ | $ | 19,226 | ​ | $ | 42,767 | ​ | March 31, 2023 | ​
Series A-1 | ​ | September 6, 2023 | ​ | 38,000 | ​ | $ | 7.63 | ​ | ​ | 36,941 | ​ | ​ | 17,639 | ​ | ​ | 54,580 | ​ | September 30, 2023 | ​
Series A-2 | ​ | December 15, 2023 | ​ | 35,000 | ​ | $ | 6.21 | ​ | ​ | 34,006 | ​ | ​ | 14,149 | ​ | ​ | 48,155 | ​ | December 31, 2023 | ​
Series A-3 | ​ | March 27, 2024 | ​ | 20,000 | ​ | $ | 6.83 | ​ | ​ | 19,397 | ​ | ​ | 6,925 | ​ | ​ | 26,322 | ​ | March 31, 2024 | ​
Series A-4 | ​ | May 13, 2024 | ​ | 20,000 | ​ | $ | 6.42 | ​ | ​ | 19,385 | ​ | ​ | 6,416 | ​ | ​ | 25,801 | ​ | June 30, 2024 | ​
​ | ​ | ​ | ​ | 138,000 | ​ | ​ | ​ | ​ | $ | 133,270 | ​ | $ | 64,355 | ​ | $ | 197,625 | ​ | ​ | ​

(1) | At the option of the Company, Series A through A-4 receive either annual dividends paid in cash at a fixed rate of 14.5% or accrued annually at a fixed PIK rate of 16.0%.

(2) | The preferred stock is originally recorded net of original issue discount and accrued offering costs as mezzanine equity (temporary equity) and subsequently a non-cash deemed dividend is recorded to increase the carrying value of the preferred stock to its redemption amount.

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.

For the three and six months ended June 30, 2025, the Company paid-in-kind dividends on the preferred stock of $8.3 million and $20.1 million, respectively. For the three and six months ended June 30, 2024, the Company PIK dividends on the preferred stock of $7.9 million and $13.0 million, respectively. At June 30, 2025, the carrying value of the preferred stock, inclusive of PIK dividends, is approximately $197.6 million.

Voting Rights. Holders of shares of the Redeemable Convertible Preferred Stock have no voting rights with respect to the shares of Redeemable Convertible Preferred stock.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 $138.0 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 2024 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 a conversion ratio (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 Redeemable Convertible Preferred Stock in cash for an amount per share of Preferred Stock equal to (the “Redemption Price”):

| ● | at any time after the first anniversary of the closing date but on or prior to the second anniversary of the closing date, 108% of the Liquidation Preference at such time; and

| ● | at any time after the second anniversary of the closing date, 120% of the Liquidation Preference at such time.

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

| ● | at any time after the one hundred fiftieth (150th) day following the issuance date, the Company shall offer each Holder a cash payment equal to the Redemption Price. Holders shall also have the ability to elect conversion into common stock at the Conversion Ratio. Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

11. EARNINGS PER SHARE

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | June 30, | ​ | June 30,
​ |  | 2025 | ​ | 2024 | ​ | 2025 | ​ | 2024
Basic: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | 4,796 | ​ | $ | (105) | ​ | $ | 10,819 | ​ | $ | (31,307)
Less: Preferred stock dividend | ​ | ​ | (8,270) | ​ | ​ | (8,586) | ​ | ​ | (20,090) | ​ | ​ | (14,218)
Less: Undistributed earnings allocable to preferred stockholders | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Net loss available to common stockholders | ​ | $ | (3,474) | ​ | $ | (8,691) | ​ | $ | (9,271) | ​ | $ | (45,525)
Weighted average basic number of common shares outstanding basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457
Basic net loss per share of common stock | ​ | $ | (0.21) | ​ | $ | (0.53) | ​ | $ | (0.56) | ​ | $ | (2.77)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net loss available to common stockholders basic | ​ | $ | (3,474) | ​ | $ | (8,691) | ​ | $ | (9,271) | ​ | $ | (45,525)
Reallocation of undistributed earnings | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Net loss available to common stockholders diluted | ​ | $ | (3,474) | ​ | $ | (8,691) | ​ | $ | (9,271) | ​ | $ | (45,525)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average basic number of common shares outstanding basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457
Common stock equivalent shares representing shares issuable upon: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercise of stock options | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Vesting of restricted stock units | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Weighted average diluted number of common shares outstanding diluted | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457
Diluted net loss per share of common stock | ​ | $ | (0.21) | ​ | $ | (0.53) | ​ | $ | (0.56) | ​ | $ | (2.77)

​

The Company computes earnings per share in accordance with ASC Topic 260, Earnings per Share (“ASC 260”), which requires earnings per share for each class of stock (common stock and participating preferred stock) to be calculated using the two-class method which allocates earnings for the reporting period between common shareholders and other security holders based on their respective participation rights in undistributed earnings. Diluted earnings per share was calculated using the two-class method, as this computation was more dilutive than the calculation using the if-converted method. For additional information on the Company’s preferred stock, which is considered a participating security, see Note 10, “Redeemable Convertible Preferred Stock”.

For the three and six months ended June 30, 2025, common stock equivalents, including options and restricted stock units (“RSUs”), totaling 0.1 million were anti-dilutive and not included in the computation of diluted earnings per share of common stock. For the three and six months ended June 30, 2024, common stock equivalents, including options and RSUs, totaling 0.3 million were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

12. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | June 30, 2025 |  | December 31, 2024
Accounts receivable, net: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 19,258 | ​ | $ | 23,516
Joint interest accounts | ​ | ​ | 4,333 | ​ | ​ | 2,140
Other | ​ | ​ | 873 | ​ | ​ | 642
​ | ​ | $ | 24,464 | ​ | $ | 26,298
Prepaids and other: | ​ | ​ | ​ | ​ | ​ | ​
Prepaids | ​ | $ | 342 | ​ | $ | 572
Funds in escrow | ​ | ​ | 170 | ​ | ​ | 349
Other | ​ | ​ | 57 | ​ | ​ | 61
​ | ​ | $ | 569 | ​ | $ | 982
Other assets (Non-current): | ​ | ​ | ​ | ​ | ​ | ​
Investment in unconsolidated affiliate | ​ | $ | 1,319 | ​ | $ | 940
Funds in escrow | ​ | ​ | 589 | ​ | ​ | 578
Other | ​ | ​ | 1,759 | ​ | ​ | 760
​ | ​ | $ | 3,667 | ​ | $ | 2,278
Accounts payable and accrued liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Trade payables | ​ | $ | 15,708 | ​ | $ | 15,663
Accrued oil and natural gas capital costs | ​ | ​ | 16,843 | ​ | ​ | 7,800
Revenues and royalties payable | ​ | ​ | 18,861 | ​ | ​ | 19,816
Accrued interest expense | ​ | ​ | 74 | ​ | ​ | 330
Accrued employee compensation | ​ | ​ | 1,361 | ​ | ​ | 1,472
Accrued lease operating expenses | ​ | ​ | 7,645 | ​ | ​ | 7,597
Other | ​ | ​ | 1,794 | ​ | ​ | 4
​ | ​ | $ | 62,286 | ​ | $ | 52,682

​

Investment in Unconsolidated Affiliate. In May 2022, the Company entered into a joint venture with 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 WAT (previously Brazos Amine Treater, LLC (“BAT”)), an unconsolidated subsidiary. For accounting purposes, since the Company does not control the key 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 accounts 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 the key activities of the joint venture. For more information related to this joint venture, see Note 9, “Commitments and Contingencies”.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended June 30, | ​ | Six Months Ended June 30,
​ |  | 2025 | ​ | 2024 | ​ | 2025 |  | 2024
Interest expense and other | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Interest expense | ​ | $ | 7,341 | ​ | $ | 7,610 | ​ | $ | 14,530 | ​ | $ | 16,001
Interest income | ​ | ​ | (764) | ​ | ​ | (634) | ​ | ​ | (1,343) | ​ | ​ | (1,335)
Mark-to-market of derivatives - change of control call option | ​ | ​ | — | ​ | ​ | (437) | ​ | ​ | — | ​ | ​ | (1,365)
Other | ​ | ​ | 22 | ​ | ​ | (91) | ​ | ​ | 82 | ​ | ​ | 185
​ | ​ | $ | 6,599 | ​ | $ | 6,448 | ​ | $ | 13,269 | ​ | $ | 13,486

​

​

13. SUBSEQUENT EVENTS

On August 11, 2025, the Company received notice from WAT that it decided to cease taking deliveries of gas and to cease operations effective immediately. The cessation of operations is expected to materially increase processing costs and decrease production and revenue projections in the near-term. Management is actively working to identify and execute on a plan for alternative gas processing. See Note 9, “Commitments and Contingencies - Commitments,” for additional discussion of the gas treating agreement with WAT.

​

​

​

​

​

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ITEM 2. MANAGEMENT’S DISCUSSION A ND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2025 and 2024 and should be read in conjunction with our unaudited condensed consolidated financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the consolidated financial statements, notes and management’s discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. The results presented in this Form 10-Q are not necessarily indicative of future operating results.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “Special note regarding forward-looking statements.”

Overview

We are 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. Our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, attempts by foreign oil and natural gas producers to control the global supply, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding, developing and producing oil and natural gas reserves at economical costs are critical to our long-term success.

When commodity prices decline significantly our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our Amended Term Loan Agreement and extend, on a rolling basis, for a limited period of time (generally, four years). These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Recent Developments

Term Loan Credit Facility. On December 26, 2024 (the “Initial Closing Date”), we and our wholly-owned subsidiary Halcón Holdings, LLC entered into the 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. Pursuant to the 2024 Term Loan Agreement, the lenders agreed to provide us 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 (the “Incremental Term Loans”), of which such incremental borrowings in the amount of $63.0 million were incurred on January 9, 2025 pursuant to a first amendment to our 2024 Term Loan Agreement (as amended, the “2024 Amended Term Loan Agreement”). The 2024 Amended Term Loan Agreement matures on December 26, 2028.

All obligations under the 2021 Amended Term Loan Agreement were refunded, refinanced and repaid in full by the loans under the 2024 Term Loan Agreement as the net proceeds of the 2024 Term Loan Agreement were used to repay

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all outstanding indebtedness under the 2021 Amended Term Loan Agreement in an aggregate amount of approximately $152.1 million, including accrued and unpaid interest, and to pay related fees and expenses related to the new credit agreement.

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 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%.

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

| ● | Asset Coverage Ratio not to fall below 1.70x as of March 31, 2025 through and including June 30, 2025, 1.85x as of September 30, 2025 through and including December 31, 2025 and 2.00x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

| ● | Total Net Leverage Ratio not to exceed 2.75x as of March 31, 2025 through and including June 30, 2025 and 2.50x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

| ● | Current Ratio not to fall below 1.00x, determined on the last day of each calendar month commencing with the calendar month ending March 31, 2025; and

| ● | Liquidity not to fall below the greater of (x) $10,000,000 and (y) the amount equal to the scheduled principal and interest payments for the immediately succeeding three-month period, determined as of the last day of any fiscal quarter.

Under the 2024 Amended Term Loan Agreement, we are required to hedge approximately 85% to 50% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. 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.

We are 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. Under the 2024 Amended Term Loan Agreement, we must make scheduled amortization payments in the aggregate amount of $16.9 million and $22.5 million in 2025 and 2026, respectively. During the quarter ended June 30, 2025, we made a scheduled amortization payment in the amount of $5.6 million.

We recognized a loss on extinguishment of debt for the year ended December 31, 2024 in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which included 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 unaudited condensed consolidated balance sheet at December 31, 2024 in conjunction with entry into the 2024 Term Loan Agreement and deferred an additional $1.8 million of original issue discount and financing costs on the unaudited condensed consolidated balance sheet at June 30, 2025 in conjunction with the issuance of the Incremental Term Loans in January 2025.

H 2 S Treating Joint Venture. The acid gas injection facility (“AGI Facility”) to which we are a party to a joint venture has been processing gas since March 9, 2024. On August 11, 2025, we received notice from WAT that it decided to cease taking deliveries of gas and to cease operations effective immediately. In response, we are temporarily shutting in a portion of our Monument Draw field production. The cessation of operations is expected to materially increase processing costs and decrease production and revenue projections in the near-term. Management is actively working to identify and execute on a plan for alternative gas processing. In addition to general facility downtime, the AGI Facility had continued to experience interruptions in processing due to the completion of improvement and maintenance projects, including pump and other facility equipment replacement. The continued processing delays and interruptions resulted in higher processing fees than forecasted as we pay higher processing rates with other service providers.

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Under a gas treating agreement (“GTA”) with the AGI Facility, we paid a treating rate that varied based on volumes delivered to the AGI Facility and had a minimum volume commitment of 20 MMcf per day. The GTA has a tiered-rate structure based on actual volumes delivered.

Capital Resources and Liquidity

Overview. Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves. We generated net income of $10.8 million for the six months ended June 30, 2025 and had negative working capital of $6.6 million at June 30, 2025. At June 30, 2025, we had $44.6 million of cash and cash equivalents, no additional borrowing capacity under the 2024 Amended Term Loan Agreement (as defined in Note 5, “Debt” to the unaudited condensed consolidated financial statements) and a total of $22.5 million in debt repayments due through June 2026 under our 2024 Amended Term Loan Agreement. At June 30, 2025, $30.0 million remained available for issuance on or before August 29, 2025 under a support letter from our investors.

We continue to execute on a plan to reduce operating and capital costs to improve cash flows. Changes to our current business estimates and forecasts, based primarily on recent commodity prices and modifications to our planned drilling schedule to achieve better overall well economics, indicate that we will require additional liquidity to meet our debt covenant requirements for the next 12 months from the issuance of these unaudited condensed consolidated financial statements. In response to these events and conditions, the Company has continued to execute on a plan to reduce operating and capital costs to improve cash flows. The Company also has obtained a support letter from its three largest current related party investors to purchase additional preferred equity securities in an amount up to $30.0 million on or before August 31, 2026. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the sale of $30 million in additional preferred equity, it is probable that we will have sufficient liquidity to maintain compliance with our future debt covenants as described in Note 5, “Debt,” for the next 12 months from the issuance of these unaudited condensed consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include a sale of a portion of our non-core assets, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, the sale of the Company, or pursuing additional general and administrative or other cost reduction opportunities. Our estimates and forecasts are based upon assumptions that may prove to be incorrect due to many factors that are currently unknown, such as prevailing economic conditions, many of which are beyond our control.

In the event the assumptions underlying our estimates and forecasts prove to be incorrect, our operating plans, capital requirements, and covenant compliance may be adversely impacted. In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants. We continue to explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term. In this regard, we have considered whether it is advisable to continue to bear the ongoing costs of the listing of our common stock on the NYSE American and of being a reporting company under the Securities Exchange Act of 1934. We believe that we currently qualify to suspend these obligations should we elect to do so. While such a determination has not yet been made, we expect that the cost savings, particularly over the longer term, would be significant. Accordingly, we will continue to consider the matter while we simultaneously pursue strategic and financial alternatives that may render it unnecessary.

On May 30, 2025, we received written notice (the “Notice”) on behalf of the NYSE American indicating that we are no longer in compliance with NYSE American’s continued listing standards. Specifically, the letter stated that we are not in compliance with the continued listing standards set forth in Sections 1003(a)(i) and 1003(a)(ii) of the NYSE American

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Company Guide (the “Company Guide”). Section 1003(a)(i) requires a listed company to have stockholders’ equity of $2 million or more if the listed company has reported losses from continuing operations and/or net losses in two of its three most recent fiscal years. Section 1003(a)(ii) requires a listed company to have stockholders’ equity of $4 million or more if the listed company has reported losses from continuing operations and/or net losses in three of its four most recent fiscal years. Our noncompliance resulted from our reporting stockholders’ equity of $(1.8) million as of March 31, 2025, and losses from continuing operations and/or net losses in three of our four most recent fiscal years ended December 31, 2024. We continue to report negative stockholders’ equity at June 30, 2025 of $(5.2) million and additional losses from continuing operations. The Notice further provided that we must submit a plan of compliance (the “Plan”) by June 30, 2025 addressing how we intend to regain compliance with the continued listing standards by November 30, 2026. Such Plan was submitted by the required deadline and our Plan submission continues to be under review by the NYSE. The Notice has no immediate impact on the listing of our shares of common stock, which will continue to be listed and traded under the symbol “BATL” on the NYSE American during this period, subject to our compliance with the other listing requirements of the NYSE American. The notice does not affect our ongoing business operations or our reporting requirements with the Securities and Exchange Commission.

Other Risks and Uncertainties. Our ability to complete transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

Additionally, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.

Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the United States or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain pandemics or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our Amended Term Loan Agreement. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our Amended Term Loan Agreement.

Debt Obligations. Under our 2024 Amended Term Loan, we are 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 commencing with the fiscal quarter ending June 30, 2025 and such payments total $22.5 million through June 2026.

Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with the covenants under our 2024 Amended Term Loan Agreement. As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders to address any such issues ahead of time.

While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain

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compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowings under our 2024 Amended Term Loan Agreement.

Cash Flows

Net increase in cash and cash equivalents is summarized as follows (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended
​ | ​ | June 30,
​ |  | 2025 | ​ | 2024
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows provided by operating activities | ​ | $ | 22,936 | ​ | $ | 33,741
Cash flows used in investing activities | ​ | ​ | (53,474) | ​ | ​ | (45,706)
Cash flows provided by financing activities | ​ | ​ | 55,447 | ​ | ​ | 8,867
Net increase (decrease) in cash, cash equivalents and restricted cash | ​ | $ | 24,909 | ​ | $ | (3,098)

Operating Activities. Net cash flows provided by operating activities for the six months ended June 30, 2025 and 2024, were $22.9 million and $33.7 million, respectively. Items impacting the decrease in operating cash flows were primarily driven by lower operating revenues coupled with changes in working capital for the six months ended June 30, 2025 compared to the six months ended June 30, 2024.

Investing Activities. Net cash flows used in investing activities for the six months ended June 30, 2025 and 2024 were approximately $53.5 million and $45.7 million, respectively, primarily for drilling and completion activities.

During the six months ended June 30, 2025, we spent $53.1 million on oil and natural gas capital expenditures, of which $47.2 million related to drilling and completion costs and $5.0 million related to the development of our treating equipment and gathering support infrastructure. In the first six months of 2025, we ran one operated rig in the Delaware Basin, drilled and cased six gross (5.5 net) operated wells, and completed and put online four gross (4.0 net) operated wells.

During the six months ended June 30, 2024, we spent $44.8 million on oil and natural gas capital expenditures, of which $42.2 million related to drilling and completion costs and $2.0 million related to the development of our treating equipment and gathering support infrastructure. During the first half of 2024, our cash capital expenditures included amounts related to the drilling and completion activities that occurred in the fourth quarter of 2023. In the first six months of 2024, we ran one operated rig in the Delaware Basin, drilled and cased four gross (3.73 net), and completed and put online two gross (1.925 net) operated wells. We also received $7.0 million in proceeds from the sale of oil and natural gas assets that were deemed to be unnecessary for future operations.

Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2025 and 2024 were $55.5 million and $8.9 million, respectively. During the six months ended June 30, 2025, we received net proceeds of $61.1 million from the incurrence of the Incremental Term Loans and repaid $5.6 million under our 2024 Amended Term Loan Agreement. During the six months ended June 30, 2024, we received $38.8 million from our preferred stock equity issuances and repaid $39.9 million under our 2021 Amended Term Loan Agreement. Our net cash flows provided by financing activities during the six months ended June 30, 2024 also reflect the receipt of $10.0 million distributed from escrow to the Company in accordance with the terms of a merger agreement that was subsequently terminated on December 20, 2024.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these unaudited condensed consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and

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expenses. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.

Results of Operations

The table below sets forth financial information for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | June 30, | ​ | June 30,
In thousands (except per unit and per Boe amounts) |  | 2025 | ​ | 2024 | ​ | 2025 | ​ | 2024
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 36,291 | ​ | $ | 45,699 | ​ | $ | 75,991 | ​ | $ | 88,128
Natural gas | ​ | ​ | 935 | ​ | ​ | (2,119) | ​ | ​ | 3,758 | ​ | ​ | (72)
Natural gas liquids | ​ | ​ | 5,350 | ​ | ​ | 5,503 | ​ | ​ | 10,212 | ​ | ​ | 10,559
Other | ​ | ​ | 236 | ​ | ​ | 21 | ​ | ​ | 326 | ​ | ​ | 359
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,670 | ​ | ​ | 11,005 | ​ | ​ | 21,028 | ​ | ​ | 22,591
Workover and other | ​ | ​ | 2,309 | ​ | ​ | 951 | ​ | ​ | 3,742 | ​ | ​ | 1,839
Taxes other than income | ​ | ​ | 2,522 | ​ | ​ | 3,349 | ​ | ​ | 5,322 | ​ | ​ | 6,340
Gathering and other | ​ | ​ | 10,958 | ​ | ​ | 12,126 | ​ | ​ | 22,958 | ​ | ​ | 29,412
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2,567 | ​ | ​ | 3,304 | ​ | ​ | 6,932 | ​ | ​ | 7,276
Stock-based compensation | ​ | ​ | — | ​ | ​ | 36 | ​ | ​ | 48 | ​ | ​ | 135
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 13,554 | ​ | ​ | 12,809 | ​ | ​ | 26,228 | ​ | ​ | 25,438
Depreciation – Other | ​ | ​ | 107 | ​ | ​ | 161 | ​ | ​ | 241 | ​ | ​ | 323
Accretion expense | ​ | ​ | 278 | ​ | ​ | 243 | ​ | ​ | 550 | ​ | ​ | 477
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | 11,548 | ​ | ​ | 1,223 | ​ | ​ | 20,850 | ​ | ​ | (22,964)
Interest expense and other | ​ | ​ | (6,599) | ​ | ​ | (6,448) | ​ | ​ | (13,269) | ​ | ​ | (13,487)
Net income (loss) | ​ | $ | 4,796 | ​ | $ | (105) | ​ | $ | 10,819 | ​ | $ | (31,307)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 584 | ​ | ​ | 577 | ​ | ​ | 1,153 | ​ | ​ | 1,143
Natural Gas - MMcf | ​ | ​ | 2,136 | ​ | ​ | 1,929 | ​ | ​ | 3,935 | ​ | ​ | 4,109
Natural gas liquids – MBbls | ​ | ​ | 242 | ​ | ​ | 271 | ​ | ​ | 444 | ​ | ​ | 524
Total MBoe(1) | ​ | ​ | 1,182 | ​ | ​ | 1,170 | ​ | ​ | 2,253 | ​ | ​ | 2,352
Average daily production – Boe(1) | ​ | ​ | 12,989 | ​ | ​ | 12,857 | ​ | ​ | 12,448 | ​ | ​ | 12,923
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 62.14 | ​ | $ | 79.20 | ​ | $ | 65.91 | ​ | $ | 77.10
Natural gas price - Mcf | ​ | ​ | 0.44 | ​ | ​ | (1.10) | ​ | ​ | 0.96 | ​ | ​ | (0.02)
Natural gas liquids price - Bbl | ​ | ​ | 22.11 | ​ | ​ | 20.31 | ​ | ​ | 23.00 | ​ | ​ | 20.15
Total per Boe(1) | ​ | ​ | 36.02 | ​ | ​ | 41.95 | ​ | ​ | 39.93 | ​ | ​ | 41.93
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 9.03 | ​ | $ | 9.41 | ​ | $ | 9.33 | ​ | $ | 9.61
Workover and other | ​ | ​ | 1.95 | ​ | ​ | 0.81 | ​ | ​ | 1.66 | ​ | ​ | 0.78
Taxes other than income | ​ | ​ | 2.13 | ​ | ​ | 2.86 | ​ | ​ | 2.36 | ​ | ​ | 2.70
Gathering and other | ​ | ​ | 9.27 | ​ | ​ | 10.36 | ​ | ​ | 10.19 | ​ | ​ | 12.51
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.17 | ​ | ​ | 2.82 | ​ | ​ | 3.08 | ​ | ​ | 3.09
Stock-based compensation | ​ | ​ | — | ​ | ​ | 0.03 | ​ | ​ | 0.02 | ​ | ​ | 0.06
Depletion | ​ | ​ | 11.47 | ​ | ​ | 10.95 | ​ | ​ | 11.64 | ​ | ​ | 10.82

(1) | Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or natural gas liquids (“NGLs”) based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.

(2) | Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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Operating Revenues. Oil, natural gas and NGLs revenues were $42.6 million and $49.1 million for the three months ended June 30, 2025 and 2024, respectively. The decrease in revenues is primarily attributable to a decrease in average realized prices. Production averaged 12,989 Boe per day for the three months ended June 30, 2025 compared to 12,857 Boe per day for the three months ended June 30, 2024. Average realized prices (excluding the effects of hedging arrangements) decreased approximately $5.93 per Boe for three months ended June 30, 2025 when compared with the same period in 2024.

Oil, natural gas and NGLs revenues were $90.0 million and $98.6 million for the six months ended June 30, 2025 and 2024, respectively. The decrease in revenues is primarily attributable to a combination of a decrease in our average realized prices and lower production volumes in 2025 compared to 2024. Production averaged 12,448 Boe per day for the six months ended June 30, 2025 compared to 12,923 Boe per day for the six months ended June 30, 2024. Average realized prices (excluding the effects of hedging arrangements) decreased approximately $2.00 per Boe for the six months ended June 30, 2025 when compared with the same period in 2024. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease Operating Expenses. Lease operating expenses were $10.7 million and $11.0 million for the three months ended June 30, 2025 and 2024, respectively, and $21.0 million and $22.6 million for the six months ended June 30, 2025 and 2024, respectively. On a per unit basis, lease operating expenses were $9.03 per Boe and $9.41 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $9.33 per Boe and $9.61 per Boe for the six months ended June 30, 2025 and 2024, respectively. The decrease in lease operating expenses on a per unit basis for the three and six months ended June 30, 2025 compared to the same periods of 2024 is primarily a result of contract negotiations with water disposal companies resulting in lower water production costs, lower chemical costs and aggressive preventative maintenance programs yielding decreased reactive repairs and maintenance costs.

Workover and Other Expenses. Workover and other expenses were $2.3 million and $0.9 million for the three months ended June 30, 2025 and 2024, respectively, and $3.7 million and $1.8 million for the six months ended June 30, 2025 and 2024, respectively. On a per unit basis, workover and other expenses were $1.95 per Boe and $0.81 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $1.66 per Boe and $0.78 per Boe for the six months ended June 30, 2025 and 2024, respectively. The increase in workover and other expenses for the three and six months ended June 30, 2025 compared to the same periods of 2024 relates to increased workover activity during 2025 and include costs related to a non-recurring well cleanout program.

Taxes Other than Income. Taxes other than income were $2.5 million and $3.3 million for the three months ended June 30, 2025 and 2024, respectively, and $5.3 million and $6.3 million for the six months ended June 30, 2025 and 2024, respectively. Severance taxes are based on realized prices and volumes at the wellhead, while ad valorem taxes are tied to the annual valuation of our properties. As revenues or volumes from oil and natural gas sales increase or decrease, severance taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.13 per Boe and $2.86 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $2.36 per Boe and $2.70 per Boe for the six months ended June 30, 2025 and 2024, respectively.

Gathering and Other Expenses. Gathering and other expenses were $11.0 million and $12.1 million for the three months ended June 30, 2025 and 2024, respectively, and $23.0 million and $29.4 million for the six months ended June 30, 2025 and 2024, respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production and operating expenses of our gathering support infrastructure. Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H 2 S in our sour gas produced, and the amounts paid to treat our sour gas volumes, either through our own hydrogen sulfide treating plant or through third parties. On a per unit basis, gathering and other expenses were $9.27 per Boe and $10.36 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $10.19 per Boe and $12.51 per Boe for the six months ended June 30, 2025 and 2024, respectively. The decrease in gathering and other expenses per Boe for the three and six months ended June 30, 2025 compared to the same periods of 2024 is primarily related to progress made at the central production facilities yielding lower labor and repair costs as well as increased throughput and overall production volumes being treated by the AGI facility during 2025. The AGI facility did not come online until March 2024.

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General and Administrative Expense. General and administrative expense was $2.6 million and $3.3 million for the three months ended June 30, 2025 and 2024, respectively, and $6.9 million and $7.3 million for the six months ended June 30, 2025 and 2024, respectively. On a per unit basis, general and administrative expenses were $2.17 per Boe and $2.82 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $3.08 per Boe and $3.09 per Boe for the six months ended June 30, 2025 and 2024, respectively. The decrease in general and administrative expense for the three and six months ended June 30, 2025 compared with the same prior year periods is primarily due to lower merger costs.

Depletion, Depreciation, and Amortization Expense. 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 $13.6 million and $12.8 million for the three months ended June 30, 2025 and 2024, respectively, and $26.2 million and $25.4 million for the six months ended June 30, 2025 and 2024, respectively. On a per unit basis, depletion expense was $11.47 per Boe and $10.95 per Boe for the three months ended June 30, 2025 and 2024, respectively, and $11.64 per Boe and $10.82 per Boe for the six months ended June 30, 2025 and 2024, respectively. The increase in our depletion rate per Boe is primarily due to a period over period increase in net oil and natural gas properties combined with the associated period over period decrease in proved reserves.

Net gain (loss) on derivative contracts. We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and NGLs production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the unaudited condensed consolidated statements of operations.

For the three months ended June 30, 2025, we recorded a net derivative gain of $11.5 million ($7.2 million net unrealized gain on unsettled contracts and $4.3 million net realized gain on settled contracts). For the three months ended June 30, 2024, we recorded a net derivative gain of $1.2 million ($4.4 million net unrealized gain on unsettled contracts offset by a $3.2 million net realized loss on settled contracts). For the six months ended June 30, 2025, we recorded a net derivative gain of $20.9 million ($19.1 million net unrealized gain on unsettled contracts and $1.8 million net realized gain on settled contracts). For the six months ended June 30, 2024, we recorded a net derivative loss of $22.9 million ($15.3 million net unrealized loss on unsettled contracts and $7.6 million net realized loss on settled contracts). At June 30, 2025, we had a $20.1 million derivative asset ($13.7 million current) and a $9.2 million derivative liability ($4.5 million current).

Interest Expense and Other. Interest expense and other totaled $6.6 million and $6.5 million for the three months ended June 30, 2025 and 2024, respectively and $13.3 million and $13.5 million for the six months ended June 30, 2025 and 2024, respectively. Our weighted average interest rate was approximately 12.20% for the three and six months ended June 30, 2025. Comparatively, our weighted average interest rate was approximately 12.95% for the quarter ended June 30, 2024 and 12.97% for the six months ended June 30, 2024. For the third quarter of 2025, our interest rate will be approximately 12.20% on outstanding borrowings.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil and natural gas prices decline, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include fixed-price swaps, costless collars, basis swaps and WTI NYMEX rolls. The total volumes that

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we hedge through the use of our derivative instruments varies from period to period; however, our requirement under our Term Loan Agreement, as amended, is to hedge approximately 50% to 85% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. Our hedge policies and objectives may change significantly as our operational profile and contractual obligations change but remain consistent with the requirements in effect under our Term Loan Agreement, as amended. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. At June 30, 2025, we did not post collateral under any of our derivative contracts as they are secured under our Term Loan Agreement, as amended. We account for our derivative activities on the balance sheet as either an asset or liability measured at fair value. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, “Derivative and Hedging Activities,” for more details.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information, involve uncertainties, and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 6, “Fair Value Measurements,” for additional information.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are SOFR (and previously, the London Interbank Offered Rate or “LIBOR”) based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At June 30, 2025, the principal amount of our term loan debt was $219.4 million, which bears interest at floating and variable interest rates that are tied to SOFR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2025, the weighted average interest rate on our variable rate debt was 12.20% per year. If the balance of our variable interest rate debt at June 30, 2025 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $2.7 million per yea r.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Principal Financial Officer, we evaluated the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act) as of June 30, 2025. On the basis of this review, our management, including our Chief Executive Officer and Principal Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Principal Financial Officer, in a manner that allows timely decisions regarding required disclosure.

We did not have any change in our internal controls over financial reporting during the six months ended June 30, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, “Commitments and Contingencies,” which is incorporated herein by reference.

ITEM 1A. RISK FACTORS

There have been no changes to the risk factors described in our Annual Report on Form 10-K for the fiscal year ended December 31, 2024.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

N o n e.

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ITEM 6. EXHIBITS

The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

3.1 | ​ | Ninth Amended and Restated Certificate of Incorporation of Battalion Oil Corporation, dated June 12, 2025 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed June 18, 2025).
3.2 | ​ | Seventh Amended and Restated Bylaws of Battalion Oil Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed January 27, 2020).
10.1 | ​ | Second Amended and Restated Senior Secured Credit Agreement dated as of December 26, 2024, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 27, 2024).
10.1.1 | ​ | First Amendment to Second Amended and Restated Senior Secured Credit Agreement dated as of January 9, 2025, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 10, 2025).
31 | * | Sarbanes-Oxley Section 302 certification of Principal Executive Officer and Principal Financial Officer
32 | * | Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS | * | Inline XBRL Instance Document
101.SCH | * | Inline XBRL Taxonomy Extension Schema Document
101.CAL | * | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF | * | Inline XBRL Taxonomy Extension Definition Document
101.LAB | * | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE | * | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 | * | Cover Page Interactive Data File (embedded within the Inline XBRL document)

* | Attached hereto.

† | Indicates management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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​ |  | BATTALION OIL CORPORATION
​ | ​ | ​
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August 13, 2025 | ​ | By: | /s/ MATTHEW B. STEELE
​ | ​ | ​ | ​
​ | ​ | Name: | Matthew B. Steele
​ | ​ | Title: | Chief Executive Officer
​ | ​ | ​ | (Principal Executive Officer and Principal Financial Officer)
​ | ​ | ​

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