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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, 2024
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

​

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 ◻

​

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 ◻

​

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.

​

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

​

​ | ​
Smaller reporting company ☒ | Emerging growth company ◻

​

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. ◻

​

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

​

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 ◻

​

At August 8, 2024, 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, 2024 and 2023 | ​ | 5
​ | ​ | Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2024 and December 31, 2023 | ​ | 6
​ | ​ | Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) for the Three and Six Months Ended June 30, 2024 and the Year Ended December 31, 2023 | ​ | 7
​ | ​ | Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2024 and 2023 | ​ | 9
​ | ​ | Notes to Unaudited Condensed Consolidated Financial Statements | ​ | 10
ITEM 2. | ​ | Management’s Discussion and Analysis of Financial Condition and Results of Operations | ​ | 26
ITEM 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk | ​ | 37
ITEM 4. | ​ | Controls and Procedures | ​ | 37
​ | ​ | ​ | ​ | ​
PART II | ​ | OTHER INFORMATION | ​ | ​
ITEM 1. | ​ | Legal Proceedings | ​ | 38
ITEM 1A. | ​ | Risk Factors | ​ | 38
ITEM 2. | ​ | Unregistered Sales of Equity Securities and Use of Proceeds | ​ | 38
ITEM 3. | ​ | Defaults Upon Senior Securities | ​ | 38
ITEM 4. | ​ | Mine Safety Disclosures | ​ | 38
ITEM 5. | ​ | Other Information | ​ | 38
ITEM 6. | ​ | Exhibits | ​ | 39
Signatures | ​ | ​ | ​ | 40
​ | ​ | ​ | ​ | ​

​

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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, the structure, timing and completion of the proposed Merger (as defined below); any anticipated effects of the announcement, pendency or completion of the proposed Merger on the value of our common stock; ability to obtain any required regulatory approvals in connection with the proposed Merger; expenses related to the proposed Merger and any potential future costs; 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, 2023, 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;

| ● | our ability to generate sufficient cash flow 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;

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

| ● | impacts of climate regulations;

| ● | 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 United States 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;

| ● | 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,
​ | ​ | 2024 | ​ | 2023 | ​ | 2024 | ​ | 2023
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 45,699 | ​ | $ | 46,168 | ​ | $ | 88,128 | ​ | $ | 100,383
Natural gas | ​ | ​ | (2,119) | ​ | ​ | 2,060 | ​ | ​ | (72) | ​ | ​ | 4,960
Natural gas liquids | ​ | ​ | 5,503 | ​ | ​ | 5,657 | ​ | ​ | 10,559 | ​ | ​ | 12,815
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 49,083 | ​ | ​ | 53,885 | ​ | ​ | 98,615 | ​ | ​ | 118,158
Other | ​ | ​ | 21 | ​ | ​ | 387 | ​ | ​ | 359 | ​ | ​ | 1,256
Total operating revenues | ​ | ​ | 49,104 | ​ | ​ | 54,272 | ​ | ​ | 98,974 | ​ | ​ | 119,414
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 11,005 | ​ | ​ | 11,365 | ​ | ​ | 22,591 | ​ | ​ | 23,056
Workover and other | ​ | ​ | 951 | ​ | ​ | 2,634 | ​ | ​ | 1,839 | ​ | ​ | 3,969
Taxes other than income | ​ | ​ | 3,349 | ​ | ​ | 3,180 | ​ | ​ | 6,340 | ​ | ​ | 6,370
Gathering and other | ​ | ​ | 12,126 | ​ | ​ | 16,828 | ​ | ​ | 29,412 | ​ | ​ | 33,345
General and administrative | ​ | ​ | 3,340 | ​ | ​ | 5,243 | ​ | ​ | 7,411 | ​ | ​ | 10,380
Depletion, depreciation and accretion | ​ | ​ | 13,213 | ​ | ​ | 14,713 | ​ | ​ | 26,238 | ​ | ​ | 30,861
Total operating expenses | ​ | ​ | 43,984 | ​ | ​ | 53,963 | ​ | ​ | 93,831 | ​ | ​ | 107,981
Income from operations | ​ | ​ | 5,120 | ​ | ​ | 309 | ​ | ​ | 5,143 | ​ | ​ | 11,433
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | 1,223 | ​ | ​ | 4,473 | ​ | ​ | (22,964) | ​ | ​ | 23,946
Interest expense and other | ​ | ​ | (6,448) | ​ | ​ | (9,530) | ​ | ​ | (13,486) | ​ | ​ | (17,316)
Total other (expenses) income | ​ | ​ | (5,225) | ​ | ​ | (5,057) | ​ | ​ | (36,450) | ​ | ​ | 6,630
(Loss) income before income taxes | ​ | ​ | (105) | ​ | ​ | (4,748) | ​ | ​ | (31,307) | ​ | ​ | 18,063
Income tax benefit (provision) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Net (loss) income | ​ | $ | (105) | ​ | $ | (4,748) | ​ | $ | (31,307) | ​ | $ | 18,063
Preferred dividends | ​ | ​ | (8,586) | ​ | ​ | (997) | ​ | ​ | (14,218) | ​ | ​ | (2,489)
Net (loss) income available to common stockholders | ​ | $ | (8,691) | ​ | $ | (5,745) | ​ | $ | (45,525) | ​ | $ | 15,574
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net (loss) income per share of common stock available to common stockholders: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | $ | (0.53) | ​ | $ | (0.35) | ​ | $ | (2.77) | ​ | $ | 0.87
Diluted | ​ | $ | (0.53) | ​ | $ | (0.35) | ​ | $ | (2.77) | ​ | $ | 0.86
Weighted average common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,425
Diluted | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,520

​

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, 2024 | ​ | December 31, 2023
Current assets: | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 54,430 | ​ | $ | 57,529
Accounts receivable, net | ​ | ​ | 24,894 | ​ | ​ | 23,021
Assets from derivative contracts | ​ | ​ | 5,869 | ​ | ​ | 8,992
Restricted cash | ​ | ​ | 91 | ​ | ​ | 90
Prepaids and other | ​ | ​ | 821 | ​ | ​ | 907
Total current assets | ​ | ​ | 86,105 | ​ | ​ | 90,539
Oil and natural gas properties (full cost method): | ​ | ​ | ​ | ​ | ​ | ​
Evaluated | ​ | ​ | 791,908 | ​ | ​ | 755,482
Unevaluated | ​ | ​ | 51,896 | ​ | ​ | 58,909
Gross oil and natural gas properties | ​ | ​ | 843,804 | ​ | ​ | 814,391
Less: accumulated depletion | ​ | ​ | (471,413) | ​ | ​ | (445,975)
Net oil and natural gas properties | ​ | ​ | 372,391 | ​ | ​ | 368,416
Other operating property and equipment: | ​ | ​ | ​ | ​ | ​ | ​
Other operating property and equipment | ​ | ​ | 4,657 | ​ | ​ | 4,640
Less: accumulated depreciation | ​ | ​ | (2,141) | ​ | ​ | (1,817)
Net other operating property and equipment | ​ | ​ | 2,516 | ​ | ​ | 2,823
Other noncurrent assets: | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | ​ | 4,614 | ​ | ​ | 4,877
Operating lease right of use assets | ​ | ​ | 749 | ​ | ​ | 1,027
Other assets | ​ | ​ | 20,916 | ​ | ​ | 17,656
Total assets | ​ | $ | 487,291 | ​ | $ | 485,338
​ | ​ | ​ | ​ | ​ | ​ | ​
Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable and accrued liabilities | ​ | $ | 76,456 | ​ | $ | 66,525
Liabilities from derivative contracts | ​ | ​ | 25,554 | ​ | ​ | 17,191
Current portion of long-term debt | ​ | ​ | 52,606 | ​ | ​ | 50,106
Operating lease liabilities | ​ | ​ | 634 | ​ | ​ | 594
Total current liabilities | ​ | ​ | 155,250 | ​ | ​ | 134,416
Long-term debt, net | ​ | ​ | 101,185 | ​ | ​ | 140,276
Other noncurrent liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | ​ | 19,635 | ​ | ​ | 16,058
Asset retirement obligations | ​ | ​ | 18,135 | ​ | ​ | 17,458
Operating lease liabilities | ​ | ​ | 162 | ​ | ​ | 490
Other | ​ | ​ | 10,719 | ​ | ​ | 2,084
Commitments and contingencies (Note 8) | ​ | ​ | ​ | ​ | ​ | ​
Temporary equity: | ​ | ​ | ​ | ​ | ​ | ​
Redeemable convertible preferred stock: 138,000 shares and 98,000 shares | ​ | ​ | 159,535 | ​ | ​ | 106,535
of $0.0001 par value authorized, issued and outstanding as of | ​ | ​ | ​ | ​ | ​ | ​
June 30, 2024 and December 31, 2023, respectively | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity: | ​ | ​ | ​ | ​ | ​ | ​
Common stock: 100,000,000 shares of $0.0001 par value authorized; | ​ | ​ | ​ | ​ | ​ | ​
16,456,563 shares issued and outstanding as of June 30, 2024 and | ​ | ​ | ​ | ​ | ​ | ​
December 31, 2023 | ​ | ​ | 2 | ​ | ​ | 2
Additional paid-in capital | ​ | ​ | 306,969 | ​ | ​ | 321,012
Accumulated deficit | ​ | ​ | (284,301) | ​ | ​ | (252,993)
Total stockholders' equity | ​ | ​ | 22,670 | ​ | ​ | 68,021
Total liabilities, temporary equity and stockholders' equity | ​ | $ | 487,291 | ​ | $ | 485,338
​ | ​ | ​ | ​ | ​ | ​ | ​

​

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 | ​ | — | ​ | ​ | — | ​ | ​ | 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 | ​ | — | ​ | ​ | — | ​ | ​ | 48 | ​ | ​ | — | ​ | ​ | 48
Balances at June 30, 2024 | ​ | 16,457 | ​ | $ | 2 | ​ | $ | 306,969 | ​ | $ | (284,301) | ​ | $ | 22,670

​

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, 2022 | ​ | 16,345 | ​ | $ | 2 | ​ | $ | 334,571 | ​ | $ | (249,945) | ​ | $ | 84,628
Net income | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 22,811 | ​ | ​ | 22,811
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (1,492) | ​ | ​ | — | ​ | ​ | (1,492)
Long-term incentive plan vestings | ​ | 159 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Tax withholding on vesting of restricted stock units | ​ | (47) | ​ | ​ | — | ​ | ​ | (454) | ​ | ​ | — | ​ | ​ | (454)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 327 | ​ | ​ | — | ​ | ​ | 327
Balances at March 31, 2023 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 332,952 | ​ | ​ | (227,134) | ​ | ​ | 105,820
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (4,748) | ​ | ​ | (4,748)
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (997) | ​ | ​ | — | ​ | ​ | (997)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | (754) | ​ | ​ | — | ​ | ​ | (754)
Balances at June 30, 2023 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 331,201 | ​ | ​ | (231,882) | ​ | ​ | 99,321
Net loss | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (53,799) | ​ | ​ | (53,799)
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (3,863) | ​ | ​ | — | ​ | ​ | (3,863)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | (827) | ​ | ​ | — | ​ | ​ | (827)
Balances at September 30, 2023 | ​ | 16,457 | ​ | ​ | 2 | ​ | ​ | 326,511 | ​ | ​ | (285,681) | ​ | ​ | 40,832
Net income | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 32,688 | ​ | ​ | 32,688
Deemed dividends for preferred stock | ​ | — | ​ | ​ | — | ​ | ​ | (5,695) | ​ | ​ | — | ​ | ​ | (5,695)
Stock-based compensation and other | ​ | — | ​ | ​ | — | ​ | ​ | 196 | ​ | ​ | — | ​ | ​ | 196
Balances at December 31, 2023 | ​ | 16,457 | ​ | $ | 2 | ​ | $ | 321,012 | ​ | $ | (252,993) | ​ | $ | 68,021

​

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,
​ | 2024 | ​ | 2023
Cash flows from operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Net (loss) income | ​ | $ | (31,307) | ​ | $ | 18,063
Adjustments to reconcile net (loss) income to net cash | ​ | ​ | ​ | ​ | ​ | ​
provided by operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Depletion, depreciation and accretion | ​ | ​ | 26,238 | ​ | ​ | 30,861
Stock-based compensation, net | ​ | ​ | 135 | ​ | ​ | (545)
Unrealized loss (gain) on derivative contracts | ​ | ​ | 15,327 | ​ | ​ | (23,336)
Amortization/accretion of financing related costs | ​ | ​ | 3,390 | ​ | ​ | 3,843
Accrued settlements on derivative contracts | ​ | ​ | 774 | ​ | ​ | (929)
Change in fair value of embedded derivative liability | ​ | ​ | (1,365) | ​ | ​ | (704)
Other | ​ | ​ | 179 | ​ | ​ | 53
Change in assets and liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | (445) | ​ | ​ | 15,965
Prepaids and other | ​ | ​ | 85 | ​ | ​ | 81
Accounts payable and accrued liabilities | ​ | ​ | 20,730 | ​ | ​ | (34,703)
Net cash provided by operating activities | ​ | ​ | 33,741 | ​ | ​ | 8,649
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​
Oil and natural gas capital expenditures | ​ | ​ | (44,849) | ​ | ​ | (32,633)
Proceeds received from sale of oil and natural gas assets | ​ | ​ | 7,015 | ​ | ​ | 1,189
Acquisition of oil and natural gas properties | ​ | ​ | (47) | ​ | ​ | —
Contract asset | ​ | ​ | (7,795) | ​ | ​ | —
Other operating property and equipment capital expenditures | ​ | ​ | (17) | ​ | ​ | (284)
Other | ​ | ​ | (13) | ​ | ​ | (11)
Net cash used in investing activities | ​ | ​ | (45,706) | ​ | ​ | (31,739)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: | ​ | ​ | ​ | ​ | ​ | ​
Repayments of borrowings | ​ | ​ | (39,853) | ​ | ​ | (15,043)
Payment of debt financing costs | ​ | ​ | (129) | ​ | ​ | —
Proceeds from issuance of preferred stock | ​ | ​ | 38,849 | ​ | ​ | 24,375
Merger deposit | ​ | ​ | 10,000 | ​ | ​ | —
Other | ​ | ​ | — | ​ | ​ | (454)
Net cash provided by financing activities | ​ | ​ | 8,867 | ​ | ​ | 8,878
​ | ​ | ​ | ​ | ​ | ​ | ​
Net decrease in cash, cash equivalents and restricted cash | ​ | ​ | (3,098) | ​ | ​ | (14,212)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash, cash equivalents and restricted cash at beginning of period | ​ | ​ | 57,619 | ​ | ​ | 32,816
Cash, cash equivalents and restricted cash at end of period | ​ | $ | 54,521 | ​ | $ | 18,604
​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow information: | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for interest | ​ | $ | 12,512 | ​ | $ | 14,561
​ | ​ | ​ | ​ | ​ | ​ | ​

​

​

​

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. 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 United States (“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 United States Securities and Exchange Commission (the “SEC”) on April 1, 2024. Please refer to the notes in the Annual Report on Form 10-K for the year ended December 31, 2023 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 a net loss of $45.5 million for the six months ended June 30, 2024 and had a negative working capital of $69.1 million as of June 30, 2024. The Company’s current business estimates and forecasts indicate that it will require additional liquidity to continue its operations, satisfy debt payment requirements and meet its debt covenant requirements for the next 12 months from the issuance of these 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 flow. 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 over the next 12 months. 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 fund its operations, meet its continuous drilling obligations and near-term debt payment requirements and maintain compliance with its debt covenants, as described in Note 5, “Debt,” for the next 12 months from the issuance of these 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. 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

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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):

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​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | June 30, 2024 | ​ | December 31, 2023
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 54,430 | ​ | $ | 57,529
Restricted cash | ​ | ​ | 91 | ​ | ​ | 90
Total cash, cash equivalents and restricted cash | ​ | $ | 54,521 | ​ | $ | 57,619

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Restricted cash consists of funds to collateralize lines of credit.

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 varied among major financial institutions 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, 2024, the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Amended Term Loan Agreement (as defined in Note 4, “Debt”).

Recently Issued Accounting Pronouncements

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”), in response to the risk of cessation of the London Interbank Offered Rate (“LIBOR”). This amendment provides optional expedients and exceptions for applying GAAP to contracts, hedging arrangements, and other transactions that reference LIBOR. On December 21, 2022, the FASB issued

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ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848” (“ASU 2022-06”). ASU 2022-06 defers the sunset date from December 31, 2022 to December 31, 2024. As of the date of this filing, neither ASU 2020-04 nor ASU 2022-06 had a material impact on the Company’s operating results, financial position or disclosures.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which requires an entity, even one with only one reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis, and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. Additionally, it requires an entity to disclose the title and position of the chief operating decision maker. ASU 2023-07 does not change how an entity identifies its operating segments, aggregates them or applies the quantitative thresholds to determine its reportable segments. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. Entities should apply the amendments in ASU 2023-07 retrospectively to all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2023-07 and does not expect it to have a material impact on the Company’s financial position, results of operations and cash flows or disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”), which focuses on the income tax rate reconciliation and income taxes paid. ASU 2023-09 requires an entity to disclose, on an annual basis, a tabular rate reconciliation using both percentages and currency amounts, broken out into specified categories, with certain reconciling items further broken out by nature and jurisdiction to the extent those items exceed a specified threshold. In addition, entities are required to disclose income taxes paid, net of refunds received disaggregated by federal, state/local, and foreign, and by jurisdiction if the amount is at least 5% of total income tax payments, net of refunds received. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. An entity may apply the amendments in ASU 2023-09 prospectively by providing the revised disclosures for the period ending December 31, 2025 and continuing to provide the pre-ASU disclosures for the prior periods, or may apply the amendments retrospectively by providing the revised disclosures for all period presented. The 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.

2. 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 statement of operations by major product, and depicts how the nature, timing and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations.

Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract and (5) recognize revenue when the reporting organization satisfies a performance obligation. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of each unit (e.g. barrel of oil, Mcf of 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 of $21.2 million

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and $19.8 million as of June 30, 2024 and December 31, 2023, 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, 2023.

3. 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, 2024 and 2023, 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, 2024 and 2023, did not exceed the ceiling test value of the Company’s reserves. Oil and natural gas prices utilized for the ceiling test calculations as of June 30, 2024 and 2023 were $79.45 per barrel and $83.23 per barrel of oil, respectively, and $2.32 per MMBtu and $4.76 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 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.

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4. DEBT

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2024 | ​ | ​ | December 31, 2023
Term loan credit facility | ​ | $ | 160,201 | ​ | ​ | $ | 200,000
Other | ​ | ​ | 162 | ​ | ​ | ​ | 215
Total debt (Face Value) | ​ | ​ | 160,363 | ​ | ​ | ​ | 200,215
Less: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Current portion of long-term debt(1) | ​ | ​ | (52,606) | ​ | ​ | ​ | (50,106)
Other(2) | ​ | ​ | (6,572) | ​ | ​ | ​ | (9,833)
Long-Term Debt, net | ​ | $ | 101,185 | ​ | ​ | $ | 140,276

(1) | Amounts primarily reflect amortization payments due of $52.5 million and $50.0 million under the Amended Term Loan Agreement due within one year as of June 30, 2024 and December 31, 2023, respectively.

(2) | Amounts primarily reflect unamortized debt issuance costs of approximately $4.4 million and $6.9 million at June 30, 2024 and December 31, 2023, respectively, but also includes an unamortized debt discount associated with an embedded derivative. For the six months ended June 30, 2024 and 2023, the Company recorded approximately $3.4 million and $3.8 million, respectively, in interest expense reflecting the amortization/accretion of these amounts.

Term Loan Credit Facility

On November 24, 2021, the Company and its wholly owned subsidiary, Halcón Holdings, LLC (the “Borrower”) entered into an Amended and Restated Senior Secured Credit Agreement (the “Term Loan Agreement”) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. On November 14, 2022, the Company paid approximately $2.4 million and entered into a further Amended Credit Agreement (the “Amended Term Loan Agreement”) with its lenders which modified certain provisions of its original Term Loan Agreement including, but not limited to, its Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

On March 28, 2024, the Company entered into the Third Amendment to the Amended Term Loan Agreement (the “Third Amendment”) with its lenders. The Third Amendment, amended the Amended Term Loan Agreement to, among other things, (a) amend the approved plan of development (“APOD”) for certain properties, (b) remove the PDP Production Test and APOD Economic Test (each defined in the Term Loan Agreement), (c) require the Borrower to receive cash proceeds from equity issuances and/or cash contributions in an aggregate amount of not less than $38.0 million during the period from Amendment Effective Date through March 31, 2024 (the “Specified Additional Equity Capital”), which such Specified Additional Equity Capital shall be excluded from the calculation of Consolidated Cash Balance (as defined in the Term Loan Agreement) through December 31, 2024, and (d) make amendments to certain other affirmative covenants in connection with the foregoing.

As of June 30, 2024, the Company had $160.2 million of indebtedness and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement. An additional $4.7 million is available for the issuance of letters of credit as of June 30, 2024 and as of the date of this filing. The maturity date of the Amended Term Loan Agreement is November 24, 2025. Borrowings under the Amended Term Loan Agreement bear a variable interest rate based on the Secured Overnight Financing Rate (“SOFR”) plus 0.15% plus a fixed applicable margin of 7.5%. The weighted average interest rate on the Company’s borrowings for the quarter ended June 30, 2024 was approximately 12.95%.

The Company may elect, at its option, to prepay any borrowing outstanding under the Amended Term Loan Agreement subject to the following prepayment premiums:

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​ | ​ | ​ | ​
Period (after applicable borrowing date(1)) | ​ | ​ | Premium
Months 0-12 | ​ | ​ | Make-whole amount equal to 12 months of interest plus 2.00%
Months 13-24 | ​ | ​ | 2.00%
Months 25-36 | ​ | ​ | 1.00%
Months 37-48 | ​ | ​ | 0.00%

(1) | Applicable borrowing dates are November 2021 for the original $200.0 million borrowed and April and November 2022 for the $20.0 million and $15.0 million in delayed draw borrowings, respectively.

The Company’s prepayment premiums would differ from those noted in the table above if a change of control results in prepayment within the second anniversary of the amendment date, as a 2% prepayment premium will apply.

The Company may be required to make mandatory prepayments under the Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. For each fiscal quarter after January 1, 2023, the Company is required to make mandatory prepayments when the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, exceeds $20.0 million. Until December 31, 2024, the forecasted capital expenditures for the succeeding fiscal quarter on the APOD wells (i.e. oil and natural gas wells located within a specified boundary as set by the Amended Term Loan Agreement) are excluded for purposes of determining the Consolidated Cash Balance. As of June 30, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement and excluding the Specified Additional Equity Capital, did not exceed $20.0 million; therefore, no mandatory prepayment was necessary.

The Company is required to make scheduled remaining amortization payments in the aggregate amount of $62.5 million from the fiscal quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 with $12.5 million due at the end of the third quarter of 2024, $15.0 million due at the end of each of the fourth quarter of 2024 and the first quarter of 2025, and $10.0 million due at the end of each of the second and third quarters of 2025. The Company will be required to make a final payment of $97.7 million at maturity on November 24, 2025. Amounts outstanding under the Amended Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and by the equity interests of the Borrower held by the Company. As part of the Amended Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.

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

| ● | Asset Coverage Ratio of not less than 1.80 to 1.00 as of June 30, 2024 and the last day of each fiscal quarter thereafter

| ● | Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of June 30, 2024, and each fiscal quarter thereafter, and

| ● | Current Ratio of not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, as of June 30, 2024 and for each fiscal quarter thereafter.

At March 31, 2024, subject to the cure provision discussed below, the Company was not in compliance with the Total Net Leverage Ratio covenant under the Amended Term Loan Agreement but was in compliance with the other financial covenants. Under the Amended Term Loan Agreement, the Company has a right to cure noncompliance with the Total Net Leverage Ratio covenant within 15 days of delivery of financial statements by making an optional prepayment in an amount not greater than the amount required for purposes of complying with the Total Net Leverage Ratio and such prepayment shall not be subject to the applicable prepayment premium. Once such prepayment is made, the Total Net Leverage Ratio shall be recalculated giving effect to the reduction in the outstanding amount of borrowings as if such prepayment had occurred on the last day of the quarter. Accordingly, on May 14, 2024, the Company made a

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prepayment of outstanding borrowings under the Amended Term Loan Agreement in the amount of $17.3 million resulting in total borrowings outstanding of $172.7 million. Upon giving effect to such prepayment for the calculation of the Total Net Leverage Ratio at March 31, 2024, the Company was in compliance with such financial covenant.

As of June 30, 2024, the Company was in compliance with the financial covenants under the Amended Term Loan Agreement.

The Amended Term Loan Agreement contains an APOD for the Company’s Monument Draw acreage through the drilling and completion of certain wells.

The 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 original Term Loan Agreement in November 2021, the Company agreed to pay a premium to the lenders upon a future change of control event in which a majority of the board of directors or the Chief Executive Officer (the “CEO”) or the Principal Financial Officer positions do not remain held by the same persons as before the change of control event (“Change of Control Call Option”). The premium is reduced over time through the payment of interest and certain fees. The Change of Control Call Option is accounted for as an embedded derivative not clearly and closely related to the host debt instrument. Accordingly, the Company recorded the initial fair value separately on the unaudited condensed consolidated balance sheet within “Other noncurrent liabilities” and records changes in the fair value of the embedded derivative each reporting period in “Interest expense and other” on the unaudited condensed consolidated statements of operations. Refer to Note 5, “Fair Value Measurements,” for a discussion of the valuation approach used, the significant inputs to the valuation, and for a reconciliation of the change in fair value of the Change of Control Call Option.

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5. 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 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 as of June 30, 2024 and December 31, 2023 (in thousands):

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2024
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from commodity-based derivative contracts | ​ | $ | — | ​ | $ | 10,483 | ​ | $ | — | ​ | $ | 10,483
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from commodity-based derivative contracts | ​ | $ | — | ​ | $ | 45,189 | ​ | $ | — | ​ | $ | 45,189

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2023
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from commodity-based derivative contracts | ​ | $ | — | ​ | $ | 13,869 | ​ | $ | — | ​ | $ | 13,869
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from commodity-based derivative contracts | ​ | $ | — | ​ | $ | 33,249 | ​ | $ | — | ​ | $ | 33,249

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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 (loss) gain 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 6, “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.

The Company recorded the fair value of the Change of Control Call Option separately on the unaudited condensed consolidated balance sheets in “Other noncurrent liabilities”. The fair value of the Change of Control Call Option is subsequently remeasured each reporting period with changes to the fair value of the embedded derivative recorded in “Interest expense and other” on the unaudited condensed consolidated statements of operations. The valuation of the Change of Control Call Option includes significant inputs such as the timing and probability of discrete potential exit scenarios, forward interest rate curves, and discount rates based on implied and market yields. The following table sets forth a reconciliation of the changes in fair value of the Change of Control Call Option classified as Level 3 in the fair value hierarchy (in thousands):

​

​ | ​ | ​ | ​
​ | ​ | Change of Control
​ | ​ | Call Option
Balance at December 31, 2023 | ​ | $ | 2,084
Change in fair value | ​ | ​ | (1,365)
Balance at June 30, 2024 | ​ | $ | 719

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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

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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 7, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s AROs.

6. 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 (loss) gain 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. As of June 30, 2024, 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.

The following table summarizes the location and fair value amounts of all commodity derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2024 and December 31, 2023 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Balance sheet location |  | June 30, 2024 |  | December 31, 2023 |  | Balance sheet location |  | June 30, 2024 |  | December 31, 2023
Current assets | ​ | $ | 5,869 | ​ | $ | 8,992 | ​ | Current liabilities | ​ | $ | (25,554) | ​ | $ | (17,191)
Other noncurrent assets | ​ | ​ | 4,614 | ​ | ​ | 4,877 | ​ | Other noncurrent liabilities | ​ | ​ | (19,635) | ​ | ​ | (16,058)
​ | ​ | $ | 10,483 | ​ | $ | 13,869 | ​ | ​ | ​ | $ | (45,189) | ​ | $ | (33,249)

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 net (loss) gain | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | on derivative contracts on | ​ | June 30, | ​ | June 30,
Type |  | Statement of Operations | ​ | 2024 | ​ | 2023 | ​ | 2024 | ​ | 2023
Commodity derivative contracts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unrealized (loss) gain | ​ | Other income (expenses) | ​ | $ | 4,434 | ​ | $ | 2,332 | ​ | $ | (15,327) | ​ | $ | 23,336
Realized (loss) gain | ​ | Other income (expenses) | ​ | ​ | (3,211) | ​ | ​ | 2,141 | ​ | ​ | (7,637) | ​ | ​ | 610
Total net (loss) gain | ​ | ​ | ​ | $ | 1,223 | ​ | $ | 4,473 | ​ | $ | (22,964) | ​ | $ | 23,946

​

At June 30, 2024, the Company had the following open crude oil and natural gas derivative contracts:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Instrument |  | ​ | 2024 |  | ​ | 2025 |  | ​ | 2026 | ​ | ​ | 2027 | ​
Crude oil: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed-price swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 861,244 | ​ | ​ | 1,435,236 | ​ | ​ | 1,029,685 | ​ | ​ | 786,989 | ​
Weighted average price | ​ | $ | 62.78 | ​ | $ | 61.77 | ​ | $ | 63.59 | ​ | $ | 61.87 | ​
Basis swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 862,178 | ​ | ​ | 1,451,319 | ​ | ​ | 1,036,713 | ​ | ​ | 791,105 | ​
Weighted average price | ​ | $ | 0.26 | ​ | $ | 0.25 | ​ | $ | 0.05 | ​ | $ | 0.44 | ​
WTI NYMEX roll: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (Bbls) | ​ | ​ | 850,708 | ​ | ​ | 1,451,319 | ​ | ​ | 1,036,713 | ​ | ​ | 791,105 | ​
Weighted average price | ​ | $ | 0.21 | ​ | $ | 0.13 | ​ | $ | (0.01) | ​ | $ | (0.03) | ​
Natural gas: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Fixed-price swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 2,537,743 | ​ | ​ | 4,326,712 | ​ | ​ | 2,431,053 | ​ | ​ | 2,135,815 | ​
Weighted average price | ​ | $ | 3.48 | ​ | $ | 3.42 | ​ | $ | 3.96 | ​ | $ | 3.71 | ​
Two-way collar: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 875,400 | ​ | ​ | 1,651,321 | ​ | ​ | 2,063,812 | ​ | ​ | 1,355,000 | ​
Weighted average price (call) | ​ | $ | 4.81 | ​ | $ | 5.12 | ​ | $ | 5.26 | ​ | $ | 5.57 | ​
Weighted average price (put) | ​ | $ | 3.48 | ​ | $ | 3.72 | ​ | $ | 3.70 | ​ | $ | 3.66 | ​
Basis swap: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Total volumes (MMBtu) | ​ | ​ | 3,412,284 | ​ | ​ | 5,950,283 | ​ | ​ | 4,455,681 | ​ | ​ | 3,472,222 | ​
Weighted average price | ​ | $ | (0.84) | ​ | $ | (0.68) | ​ | $ | (0.77) | ​ | $ | (0.73) | ​

​

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, 2024 and December 31, 2023 (in thousands):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Derivative Assets | ​ | Derivative Liabilities
Offsetting of Derivative Assets and Liabilities |  | June 30, 2024 |  | December 31, 2023 |  | June 30, 2024 |  | December 31, 2023
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gross Amounts - Consolidated Balance Sheet | ​ | $ | 10,483 | ​ | $ | 13,869 | ​ | $ | (45,189) | ​ | $ | (33,249)
Amounts Not Offset - Consolidated Balance Sheet | ​ | ​ | (10,483) | ​ | ​ | (13,218) | ​ | ​ | 10,483 | ​ | ​ | 13,218
Net Amount | ​ | $ | — | ​ | $ | 651 | ​ | $ | (34,706) | ​ | $ | (20,031)

​

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.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

7. 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 as of December 31, 2023 | ​ | $ | 17,458
Accretion expense | ​ | ​ | 477
Liabilities incurred | ​ | ​ | 200
Liability for asset retirement obligations as of June 30, 2024 | ​ | ​ | 18,135

​

8. 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 $1.71/Mcf and varies based on volumes delivered to the facility. For additional information on this joint venture, see Note 11, “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. As of June 30, 2024, the Company had in place multiple long-term crude oil and natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging 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.

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

9. REDEEMABLE CONVERTIBLE PREFERRED STOCK

The table below summarizes the Company’s Redeemable Convertible Preferred Stock issuances:

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Preferred Stock (1) | ​ | Issuance Date | ​ | Shares | ​ | Conversion Price | ​ | Net Equity Recorded (2) (in thousands) | ​ | Deemed Dividend Date | ​ | Non-cash Deemed Dividends (2) (in thousands) | ​
Series A | ​ | March 28, 2023 | ​ | 25,000 | ​ | $ | 9.03 | ​ | $ | 23,541 | ​ | March 31, 2023 | ​ | $ | 1,459 | ​
Series A-1 | ​ | September 6, 2023 | ​ | 38,000 | ​ | $ | 7.63 | ​ | $ | 36,941 | ​ | September 30, 2023 | ​ | $ | 1,059 | ​
Series A-2 | ​ | December 15, 2023 | ​ | 35,000 | ​ | $ | 6.21 | ​ | $ | 34,006 | ​ | December 31, 2023 | ​ | $ | 994 | ​
Series A-3 | ​ | March 27, 2024 | ​ | 20,000 | ​ | $ | 6.83 | ​ | $ | 19,397 | ​ | March 31, 2024 | ​ | $ | 603 | ​
Series A-4 | ​ | May 13, 2024 | ​ | 20,000 | ​ | $ | 6.42 | ​ | $ | 19,385 | ​ | June 30, 2024 | ​ | $ | 615 | ​

(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.

On March 27, 2024, the Company sold, in a private placement, an aggregate of 20,000 shares of Series A-3 Redeemable Convertible Preferred Stock (the “Series A-3 Preferred Stock”) in a private placement to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, the Company’s largest three existing stockholders (the “Investors”). The Company received $19.5 million in proceeds, net of $0.5 million in original issue discount. Each of the Investors has an employee that has been elected to and serves on the Company’s board of directors, comprised of six members. The issuance of Series A-3 Preferred Stock was approved by the Company’s board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the Series A-3 Preferred Stock. Holders of Series A-3 Preferred Stock will have no voting rights with respect to the shares of Series A-3 Preferred Stock. The Series A-3 Preferred Stock will receive annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed paid-in-kind (“PIK”) accrual rate of 16.0% annually at the option of the Company. Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends. PIK dividends will be cumulative, compound and accrue quarterly in arrears and will be added to the Liquidation Preference. The Series A-3 Preferred Stock Dividend Payment Date will commence on March 31, 2024, and the Conversion Price equaled $6.83, which may be adjusted from time to time.

On May 13, 2024, the Company sold, in a private placement, an aggregate of 20,000 shares of Series A-4 Redeemable Convertible Preferred Stock (the “Series A-4 Preferred Stock”) to the Investors. The Company received $19.5 million in proceeds, net of $0.5 million in original issue discount. The issuance of Series A-4 Preferred Stock was approved by the Company’s board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the Series A-4 Preferred Stock. Holders of Series A-4 Preferred Stock will have no voting rights with respect to the shares of Series A-4 Preferred Stock. The Series A-4 Preferred Stock will receive annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed PIK accrual rate of 16.0% annually at the option of the Company. Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends. PIK dividends will be cumulative, compound and accrue quarterly in arrears and will be added to the Liquidation Preference. The Series A-4 Preferred Stock Dividend Payment Date will commence on June 30, 2024, and the Conversion Price equaled $6.42, which may be adjusted from time to time.

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

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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, 2024, the Company paid-in-kind dividends on the preferred stock of $7.9 million and $13.0 million, respectively. For the three and six months ended June 30, 2023, the Company PIK dividends on the preferred stock of $1.0 million. As of June 30, 2024, the carrying value of the preferred stock, inclusive of PIK dividends, is approximately $159.5 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.

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 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 prior to 120 days following the closing date, 100% of the Liquidation Preference at such time;

| ● | at any time on or after 120 days following the closing date but prior to the 180 days following the closing date, 102% of the Liquidation Preference at such time;

| ● | at any time on or after 180 days following the closing date but on or prior to the first anniversary of the closing date, 105% of the Liquidation Preference at such time;

| ● | 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 on or prior to 150 days following the issuance date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or

| ● | at any time after the one hundred fiftieth (150 th) 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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

|  | 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.

10. 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,
​ |  | 2024 | ​ | 2023 | ​ | 2024 | ​ | 2023
Basic: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (105) | ​ | $ | (4,748) | ​ | $ | (31,307) | ​ | $ | 18,063
Less: Preferred stock dividend | ​ | ​ | (8,586) | ​ | ​ | (997) | ​ | ​ | (14,218) | ​ | ​ | (2,489)
Less: Undistributed earnings allocable to preferred stockholders | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (1,301)
Net (loss) income available to common stockholders | ​ | $ | (8,691) | ​ | $ | (5,745) | ​ | $ | (45,525) | ​ | $ | 14,273
Weighted average basic number of common shares outstanding basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,425
Basic net (loss) income per share of common stock | ​ | $ | (0.53) | ​ | $ | (0.35) | ​ | $ | (2.77) | ​ | $ | 0.87
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net (loss) income available to common stockholders basic | ​ | $ | (8,691) | ​ | $ | (5,745) | ​ | $ | (45,525) | ​ | $ | 14,273
Reallocation of undistributed earnings | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 7
Net (loss) income available to common stockholders diluted | ​ | $ | (8,691) | ​ | $ | (5,745) | ​ | $ | (45,525) | ​ | $ | 14,280
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average basic number of common shares outstanding basic | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,425
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 | ​ | ​ | 95
Weighted average diluted number of common shares outstanding diluted | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,457 | ​ | ​ | 16,520
Diluted net (loss) income per share of common stock | ​ | $ | (0.53) | ​ | $ | (0.35) | ​ | $ | (2.77) | ​ | $ | 0.86

​

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 9, “Redeemable Convertible Preferred Stock”.

For the three and six months ended June 30, 2024, common stock equivalents, including options and restricted stock units (“RSUs”), totaling 0.3 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, 2023, common stock equivalents, including options and RSUs, totaling 0.6 million and 0.5 million, respectively, 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)

11. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | June 30, 2024 |  | December 31, 2023
Accounts receivable, net: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 21,243 | ​ | $ | 19,802
Joint interest accounts | ​ | ​ | 2,095 | ​ | ​ | 2,138
Other | ​ | ​ | 1,556 | ​ | ​ | 1,081
​ | ​ | $ | 24,894 | ​ | $ | 23,021
Prepaids and other: | ​ | ​ | ​ | ​ | ​ | ​
Prepaids | ​ | $ | 396 | ​ | $ | 490
Funds in escrow | ​ | ​ | 347 | ​ | ​ | 345
Other | ​ | ​ | 78 | ​ | ​ | 72
​ | ​ | $ | 821 | ​ | $ | 907
Other assets (Non-current): | ​ | ​ | ​ | ​ | ​ | ​
Investment in unconsolidated affiliate | ​ | $ | 1,093 | ​ | $ | 1,283
Contract asset | ​ | ​ | 18,498 | ​ | ​ | 15,062
Funds in escrow | ​ | ​ | 565 | ​ | ​ | 552
Other | ​ | ​ | 760 | ​ | ​ | 759
​ | ​ | $ | 20,916 | ​ | $ | 17,656
Accounts payable and accrued liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Trade payables | ​ | $ | 34,522 | ​ | $ | 24,915
Accrued oil and natural gas capital costs | ​ | ​ | 6,694 | ​ | ​ | 15,337
Revenues and royalties payable | ​ | ​ | 26,345 | ​ | ​ | 18,986
Accrued employee compensation | ​ | ​ | 1,052 | ​ | ​ | 520
Accrued lease operating expenses | ​ | ​ | 7,512 | ​ | ​ | 6,418
Other | ​ | ​ | 331 | ​ | ​ | 349
​ | ​ | $ | 76,456 | ​ | $ | 66,525

​

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 nor does the Company have the obligation to absorb losses or the right to receive benefits that could potentially be significant, 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 8, “Commitments and Contingencies”.

Contract Asset. The Company has advanced a total of $18.5 million in contributions on behalf of its joint venture partner in WAT to fund a workover operation on the Acid Gas Injection (“AGI”) well, of which $3.4 million were advanced during the six months ended June 30, 2024. Pursuant to the terms of the agreement governing the joint venture, the Company has multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lessor of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance, none of which would

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

occur until the expiration of the current tolling agreement between the parties. The Company assesses the fair value of the contract asset on a quarterly basis for possible impairment.

12. MERGER AGREEMENT

Agreement and Plan of Merger

On December 14, 2023, the Company entered into an Agreement and Plan of Merger, as amended (the “Merger Agreement”) with Fury Resources, Inc., a Delaware corporation (“Parent”) and San Jacinto Merger Sub, Inc. (“Merger Sub”), a Delaware corporation and a direct, wholly owned subsidiary of Parent. The Merger Agreement provides, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into the Company (the “Merger”), with the Company surviving as a wholly owned subsidiary of Parent. Subject to the terms and conditions set forth in the Merger Agreement, each of the Company’s issued and outstanding shares of Common Stock, par value $0.0001 per share (“Common Stock”) shall be converted into the right to receive $9.80 in cash, without interest, which represents a total transaction value of approximately $450.0 million, and such shares shall otherwise cease to be outstanding, shall automatically be canceled and retired and cease to exist; and each outstanding share of redeemable convertible preferred stock will be contributed to Parent in exchange for new preferred shares of Parent , or sold to Parent for cash, in each case at a valuation based on the conversion or redemption value of such preferred stock.

On January 24, 2024, Parent and the Company agreed to cause an amount equal to $10.0 million to be distributed from the escrow account to the Company and such is recorded as a deposit liability in “Other” long-term liabilities on the condensed consolidated balance sheet and will be included in the net proceeds of the Merger should it be completed.

On April 24, 2024, pursuant to an amendment to the Merger Agreement dated April 16, 2024, Parent paid to the Company $0.1 million to be used by the Company to pay the Company’s costs and expenses associated with printing and mailing the definitive Proxy Statement for the Merger to the Company’s stockholders.

The obligations of the Company, Parent and Merger Sub to consummate the Merger are subject to the satisfaction or waiver of certain customary closing conditions, including, among other things: (a) the absence of any law or order of any Governmental Authority having jurisdiction over a party to the Merger Agreement prohibiting or making illegal the consummation of the Merger, and (b) the adoption of the Merger Agreement by a majority vote of the issued and outstanding shares of Company Common Stock.

​

​

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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 six months ended June 30, 2024 and 2023 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, 2023. 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

Merger with Fury Resources. On December 14, 2023, we entered into an Agreement and Plan of Merger, as amended (the “Merger Agreement”) with Fury Resources, Inc., a Delaware corporation (“Parent”) and San Jacinto Merger Sub, Inc. (“Merger Sub”), a Delaware corporation and a direct, wholly owned subsidiary of Parent.

The Merger Agreement provides, that upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into us (the “Merger”), with us surviving as a wholly owned subsidiary of Parent. Subject to the terms and conditions set forth in the Merger Agreement, at the effective time of the Merger, each of our issued and outstanding shares of Common Stock, par value $0.0001 per share (“Common Stock”) shall be converted into the right to receive $9.80 in cash, without interest, which represents a total transaction value of approximately $450.0 million (the “Merger Consideration”), and such shares shall otherwise cease to be outstanding, shall automatically be canceled and retired and cease to exist; and each outstanding share of redeemable convertible

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preferred stock will be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at valuation based on the conversion or redemption value of such preferred stock.

If the Merger is consummated, our shares of Common Stock will no longer trade on the NYSE American and will be deregistered under the Securities Exchange Act of 1934, as amended. As a result, we will become a private company.

On January 24, 2024, Parent and we agreed to cause an amount equal to $10.0 million to be distributed from the escrow account to the Company.

On April 24, 2024, pursuant to an amendment to the Merger Agreement dated April 16, 2024, Parent paid to us $0.1 million to be used by us to pay our costs and expenses associated with printing and mailing the definitive Proxy Statement for the Merger to our stockholders.

On May 3, 2024, Parent provided Equity Financing Subscription Agreements evidencing agreements by the financing sources party thereto to provide an aggregate amount of equity financing to Parent equal to $160.0 million. Of such $160.0 million equity financing commitments, $10.0 million has been drawn by Parent and was used to fund the initial $10.0 million deposit into escrow at the time the Merger Agreement was signed, and such deposit was released to the Company on January 24, 2024. With respect to the remaining $150.0 million of equity financing commitments, under the terms of the applicable Equity Financing Subscription Agreements, the obligation of the relevant financing sources to fund their portion of the equity financing is conditioned upon the satisfaction of certain conditions, including Parent entering into Equity Financing Subscription Agreements evidencing an aggregate amount of equity financing equal to $200.0 million and the other parties to such Equity Financing Subscription Agreements providing the related equity funding in escrow concurrently with or prior to the closing of the transactions contemplated by the Merger Agreement.

The obligations of us, Parent and Merger Sub to consummate the Merger are subject to the satisfaction or waiver of certain customary closing conditions, including, among other things: (a) the absence of any law or order of any Governmental Authority having jurisdiction over a party to the Merger Agreement prohibiting or making illegal the consummation of the Merger, and (b) the adoption of the Merger Agreement by a majority vote of the issued and outstanding shares of Company Common Stock.

We have incurred approximately $3.6 million as of August 8, 2024, and will continue to incur significant costs and expenses, including fees for professional services and other transaction costs, in connection with the Merger.

Preferred Stock Equity Issuance. On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares of Series A-3 Convertible Preferred Stock (the “Series A-3 Preferred Stock”) under a commitment letter received during the third quarter of 2023 to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing stockholders (the “Investors”). We received $19.5 million in proceeds, net of $0.5 million in original issue discount.

On May 13, 2024, we sold, in a private placement, an aggregate of 20,000 shares of Series A-4 Redeemable Convertible Preferred Stock (the “Series A-4 Preferred Stock”) (together with the Series A-3 Preferred Stock, the “preferred stock”) to the Investors. We received $19.5 million in proceeds, net of $0.5 million in original issue discount.

The issuances of preferred stock were approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock.

On May 14, 2024, proceeds from the sale of the Series A-4 Preferred Stock were used to make a $17.3 million prepayment of outstanding borrowings under the Amended Term Loan Agreement to cure noncompliance of the Total Net Leverage Ratio as of March 31, 2024.

Holders of the preferred stock have no voting rights with respect to the shares of preferred stock. The preferred stock is entitled to annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued at a fixed rate of 16.0% annually (“PIK accrual”) at our option. Currently, our Amended Term Loan Agreement prohibits the payment of

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cash dividends. Paid-in-kind (“PIK”) dividends are cumulative, compound and accrue quarterly in arrears and are added to the Liquidation Preference (defined below) of the preferred stock.

Shares of preferred stock are convertible, subject to conversion ratios and prices stipulated in the certificate of designation of the preferred stock, at any time by the holders of the preferred stock and by Battalion after meeting certain other agreement requirements. Battalion also has the right to redeem the preferred stock in cash at an amount equal to between 100-120% of the Liquidation Preference ($1,000 per share, or $138.0 million, increased for any PIK accruals) determined according to the redemption date. Additionally, in the event of a change of control, holders of the preferred stock have the right to receive, (i) at any time on or prior to 150 days following the closing date, and at the election of the Company, a cash payment equal to the Liquidation Preference or equity consideration equal to the 107.5% of the Liquidation Preference, or (ii) at any time after 150 days following the closing date, a cash payment equal to between 100-120% of the Liquidation Preference determined by the redemption date or conversion into common stock. 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. For additional information, see Note 9, “Redeemable Convertible Preferred Stock” to the unaudited condensed consolidated financial statements.

H 2 S Treating Joint Venture. In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “AGI Facility”) in Winkler County, Texas. The joint venture, operating as Wink Amine Treater, LLC (“WAT”) (previously Brazos Amine Treater, LLC (“BAT”)), has also entered into a Gas Treating Agreement (“GTA”) with us for natural gas production from our Monument Draw area. In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land, we retained a 5% equity interest in WAT, an unconsolidated subsidiary. Caracara provided the initial capital for the construction of the AGI Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H2S and CO2. We initially expected the AGI Facility to be mechanically complete in early April 2023 and to be in service in the second quarter of 2023. However, during commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection. To correct this issue, a positive displacement pump was ordered and installed. The AGI Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure. We commenced workover operations to remediate this issue.

During the third quarter of 2023, additional complications were encountered with the workover operation at the AGI Facility causing higher than expected costs. To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million to date as of June 30, 2024 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believe that we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance, none of which would occur until the expiration of the current tolling agreement between the parties.

The Acid Gas Injection (“AGI”) well and facility have been operational since March 9, 2024 and continued to process gas in the second quarter of 2024. Additional projects have been completed causing interruption in the daily rates, however, the facility has processed over 2.1 Bcf effectively since operational through the second quarter of 2024. The delays during the second quarter of 2024 have resulted in higher than expected gathering and treating costs. It is possible that the existing remedial facility work by WAT could extend past the second quarter of 2024 and any delays in commissioning or shut downs of the plant past the second quarter of 2024 will result in higher processing fees than currently forecast until such time the facility becomes fully operational.

Under the GTA, we will pay a treating rate that varies based on volumes delivered to the Facility for a term that will last 20 years from the in-service date of the Facility and have a minimum volume commitment of 20 MMcf per day, with certain rollover rights and start-up flexibility, for an initial term of five years from the in service date of the Facility, which can be extended up to seven years under certain conditions. Once in service, the GTA has a tiered-rate structure which is expected to drive a greater than 50 percent reduction in treating fees. Our current estimates of facility in-service

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dates and future treating fee reductions are subject to various operational and other risk factors, some of which are beyond our control, which could impact the timing and extent of these estimates.

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 a net loss of $45.5 million for the six months ended June 30, 2024 and had a negative working capital of $69.1 million as of June 30, 2024. As of June 30, 2024, we had $54.4 million of cash and cash equivalents, no additional borrowing capacity under the Amended Term Loan Agreement (as defined in Note 4, “Debt” to the unaudited condensed consolidated financial statements) and a total of $52.5 million in debt repayments due through June 2025, including $27.5 million due during the remainder of 2024.

​

Our Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule. We are required to make scheduled payments in the aggregate amount of $62.5 million from the fiscal quarter ending September 30, 2024 through the fiscal quarter ending September 30, 2025 with $12.5 million due at the end of the third quarter of 2024, $15.0 million due at the end of each of the fourth quarter of 2024 and the first quarter of 2025, and $10.0 million due at the end of each of the second and third quarters of 2025. We will be required to make a final payment of $97.7 million at maturity on November 24, 2025.

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In November 2022, we were required to seek an amendment to our Term Loan Agreement (as defined in Note 4, “Debt” to the unaudited condensed consolidated financial statements) to alleviate Current Ratio covenant compliance requirements through the first quarter of 2023 as a result of reduced commodity prices, higher interest rates, and the high capital costs experienced in our 2022 drilling program, which are by nature difficult to predict and subject to factors outside our control. In the first quarter of 2023, commodity prices, cost conditions and interest rates continued to deteriorate, which further constrained our liquidity. As a result, we projected near-term future covenant breaches (specifically the Current Ratio) beginning with the first quarter of 2023, coupled with inadequate liquidity resources available to fully fund all of our upcoming obligations, including debt repayments and interest, capital expenditures and operating costs. In the absence of additional liquidity from other sources with agreeable economic terms, we obtained $95.6 million of preferred equity funding during 2023 and an additional $19.5 million during the quarter ended March 31, 2024 from our three largest existing stockholders.

At March 31, 2024, we were not in compliance with the Total Net Leverage Ratio covenant under our Amended Term Loan Agreement. On May 13, 2024, we issued 20,000 additional shares of preferred equity and received net proceeds of $19.5 million, net of original issue discount and issuance costs. On May 14, 2024, the proceeds were used to make an optional prepayment of outstanding borrowings in the amount of $17.3 million under the Amended Term Loan Agreement. Such prepayment cured the noncompliance of the Total Net Leverage Ratio as of March 31, 2024.

We continue to execute on a plan to reduce operating and capital costs to improve cash flow, including the issuance of preferred stock totaling $134.6 million as of June 30, 2024. 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 continue our operations, satisfy our debt payment requirements and meet our debt covenant requirements for the next 12 months from the issuance of these condensed consolidated financial statements. In response to these events and conditions, we have continued to execute on a plan to reduce operating and capital costs to improve cash flow. We have also obtained a support letter from our three largest current investors to purchase up to $30 million of additional preferred equity securities over the next 12 months. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, cost reduction measures, and the commitment of the investors to purchase up to $30 million in additional preferred equity if needed, it is probable that we will have sufficient liquidity to fund our operations, meet our debt requirements and maintain compliance with our future debt covenants as described in Note 4, “Debt,” for the next 12 months from the issuance of these condensed consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include entering into other financing arrangements (e.g. the refinancing of our Amended Term Loan), a sale of a portion of our non-core

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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.

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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.

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Debt Obligations. On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into the Term Loan Agreement with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.

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On November 14, 2022, we paid approximately $2.4 million and entered into a further Amended Credit Agreement (the “Amended Term Loan Agreement”) with our lenders which modified certain provisions of its original Term Loan Agreement including, but not limited to, our Current Ratio financial covenant, interest rate benchmark, and prepayment premiums, all as further described below.

On March 28, 2024, we entered into the Third Amendment to the Amended Term Loan Agreement (the “Third Amendment”) with our lenders. The Third Amendment, amended the Amended Term Loan Agreement to, among other things, (a) amend the approved plan of development (“APOD”) for certain properties, (b) remove the Proved Developed Producing (“PDP”) Production Test and APOD Economic Test (each defined in the Term Loan Agreement), (c) require the Borrower to receive cash proceeds from equity issuances and/or cash contributions in an aggregate amount of not less than $38.0 million during the period from Amendment Effective Date through March 31, 2024 (the “Specified Additional Equity Capital”), which such Specified Additional Equity Capital shall be excluded from the calculation of Consolidated Cash Balance (as defined in the Term Loan Agreement) through December 31, 2024, and (d) make amendments to certain other affirmative covenants in connection with the foregoing.

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As of June 30, 2024, we had $160.2 million of indebtedness outstanding and $0.3 million of letters of credit outstanding under the Amended Term Loan Agreement. We currently, as of August 8, 2024, have $160.2 million in borrowings outstanding and $4.7 million available for the issuance of letters of credit. The maturity date of the Amended Term Loan Agreement is November 24, 2025. Borrowings under the Amended Term Loan Agreement bear a variable interest rate based on the Secured Overnight Financing Rate (“SOFR”) plus 0.15% plus a fixed applicable margin of 7.5%. The weighted average interest rate on our borrowings for the quarter ended June 30, 2024 was approximately 12.95%.

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Our Amended Term Loan Agreement contains a mandatory repayment schedule with $12.5 million due at the end of the third quarter in 2024 and in the aggregate, $50.0 million due from the fourth quarter ending December 31, 2024 through the fiscal quarter ending September 30, 2025 as well as a $97.7 million payment due upon maturity. Amounts outstanding under the 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 all of the equity interests of the Borrower held by us. As part of the Amended Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries.

We may elect, at our option, to prepay any borrowing outstanding under the Amended Term Loan Agreement subject to the following prepayment premiums:

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​ | ​ | ​ | ​
Period (after applicable borrowing date(1)) | ​ | ​ | Premium
Months 0-12 | ​ | ​ | Make-whole amount equal to 12 months of interest plus 2.00%
Months 13-24 | ​ | ​ | 2.00%
Months 25-36 | ​ | ​ | 1.00%
Months 37-48 | ​ | ​ | 0.00%

(1) | Applicable borrowing dates are November 2021 for the original $200.0 million borrowed and April and November 2022 for the $20.0 million and $15.0 million in delayed draw borrowings, respectively.

We may be required to make mandatory prepayments of the loans under the Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, or with cash on hand in excess of certain maximum levels beginning in 2023. For each fiscal quarter after January 1, 2023, we are required to make mandatory prepayments when our Consolidated Cash Balance, as defined in the Amended Term Loan Agreement, exceeds $20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance. As of June 30, 2024, the Consolidated Cash Balance, as defined in the Amended Term Loan Agreement and excluding the Specified Additional Equity Capital, did not exceed $20.0 million; therefore, no mandatory prepayment was necessary.

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The Amended Term Loan Agreement also contains certain financial covenants (as defined), including the maintenance of the following ratios:

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| ● | Asset Coverage Ratio of not less than 1.80 to 1.00 as of June 30, 2024 and each fiscal quarter thereafter

| ● | Total Net Leverage Ratio of not greater than 2.50 to 1.00 as of June 30, 2024, and each fiscal quarter thereafter, and

| ● | Current Ratio of not less than 1.00 to 1.00, determined as of the last day of any fiscal quarter period, as of June 30, 2024 and for each fiscal quarter thereafter.

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At March 31, 2024, subject to the cure provision discussed below, we were not in compliance with the Total Net Leverage Ratio covenant but were in compliance with the remaining financial covenants under the Amended Term Loan Agreement. Under the Amended Term Loan Agreement, we have a right to cure noncompliance with the Total Net Leverage Ratio covenant within 15 days of delivery of financial statements by making an optional prepayment in an amount not greater than the amount required for purposes of complying with the Total Net Leverage Ratio and such prepayment shall not be subject to the applicable prepayment premium. Once such prepayment is made, the Total Net Leverage Ratio shall be recalculated giving effect to the reduction in the outstanding amount of borrowings as if such prepayment had occurred on the last day of the quarter. Accordingly, on May 14, 2024, we made a prepayment of outstanding borrowings under the Amended Term Loan Agreement in the amount of $17.3 million resulting in total borrowings outstanding of $172.7 million. Upon giving effect to such prepayment for the calculation of the Total Net Leverage Ratio at March 31, 2024, we were in compliance with such financial covenant.

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As of June 30, 2024, we were in compliance with the financial covenants under the Amended Term Loan Agreement.

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The Amended Term Loan Agreement contains an APOD for our Monument Draw acreage through the drilling and completion of certain wells.

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The 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.

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 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, as evidenced most recently by the Third Amendment in March 2024 and the amendment of our Term Loan Agreement in November 2022 which reduced the Current Ratio covenant as of September 30, 2022 through March 31, 2023, 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 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 Amended Term Loan Agreement.

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Cash Flow

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

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended
​ | ​ | June 30,
​ |  | 2024 | ​ | 2023
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows provided by (used in) operating activities | ​ | $ | 33,741 | ​ | $ | 8,649
Cash flows used in investing activities | ​ | ​ | (45,706) | ​ | ​ | (31,739)
Cash flows provided by financing activities | ​ | ​ | 8,867 | ​ | ​ | 8,878
Net decrease in cash, cash equivalents and restricted cash | ​ | $ | (3,098) | ​ | $ | (14,212)

Operating Activities. Net cash flows provided by operating activities for the six months ended June 30, 2024 were $33.7 million compared to net cash flows used in operating activities of $8.7 million for the six months ended June 30, 2023. Items impacting operating cash flows were (i) lower total operating revenues resulting from an approximate $0.96 per Boe decrease in average realized prices (excluding the impact of hedging arrangements) and lower production volumes for the six months ended June 30, 2024 compared to the six months ended June 30, 2023, partially offset by the impact of settled derivative contracts period over period, (ii) increased operating costs per Boe and increased interest costs in 2023 and (iii) changes in working capital.

Investing Activities. Net cash flows used in investing activities for the six months ended June 30, 2024 and 2023 were approximately $45.7 million and $31.7 million, respectively, primarily for drilling and completion activities.

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 (1) operated rig in the Delaware Basin, drilled and cased four (4) gross (3.73 net), and completed and put online two (2) 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.

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During the six months ended June 30, 2023, we spent $32.6 million on oil and natural gas capital expenditures, of which $28.1 million related to drilling and completion costs and $3.8 million related to the development of our treating equipment and gathering support infrastructure. In the first six months of 2023, we ran one operated rig in the Delaware Basin and completed and put online one operated well.

Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2024 and 2023 were $8.9 million. 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 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 the $10.0 million distributed from the Merger escrow account to the Company. During the six months ended June 30, 2023, we received $24.4 million from our preferred stock equity issuance and repaid $15.0 million under our Amended Term Loan Agreement.

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 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, 2023.

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Results of Operations

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

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | June 30, | ​ | June 30,
In thousands (except per unit and per Boe amounts) |  | 2024 | ​ | 2023 | ​ | 2024 | ​ | 2023
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | ​ | 45,699 | ​ | ​ | 46,168 | ​ | $ | 88,128 | ​ | $ | 100,383
Natural gas | ​ | ​ | (2,119) | ​ | ​ | 2,060 | ​ | ​ | (72) | ​ | ​ | 4,960
Natural gas liquids | ​ | ​ | 5,503 | ​ | ​ | 5,657 | ​ | ​ | 10,559 | ​ | ​ | 12,815
Other | ​ | ​ | 21 | ​ | ​ | 387 | ​ | ​ | 359 | ​ | ​ | 1,256
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 11,005 | ​ | ​ | 11,365 | ​ | ​ | 22,591 | ​ | ​ | 23,056
Workover and other | ​ | ​ | 951 | ​ | ​ | 2,634 | ​ | ​ | 1,839 | ​ | ​ | 3,969
Taxes other than income | ​ | ​ | 3,349 | ​ | ​ | 3,180 | ​ | ​ | 6,340 | ​ | ​ | 6,370
Gathering and other | ​ | ​ | 12,126 | ​ | ​ | 16,828 | ​ | ​ | 29,412 | ​ | ​ | 33,345
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 3,304 | ​ | ​ | 6,015 | ​ | ​ | 7,276 | ​ | ​ | 10,925
Stock-based compensation | ​ | ​ | 36 | ​ | ​ | (772) | ​ | ​ | 135 | ​ | ​ | (545)
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 12,809 | ​ | ​ | 14,361 | ​ | ​ | 25,438 | ​ | ​ | 30,168
Depreciation – Other | ​ | ​ | 161 | ​ | ​ | 166 | ​ | ​ | 323 | ​ | ​ | 321
Accretion expense | ​ | ​ | 243 | ​ | ​ | 186 | ​ | ​ | 477 | ​ | ​ | 372
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | 1,223 | ​ | ​ | 4,473 | ​ | ​ | (22,964) | ​ | ​ | 23,946
Interest expense and other | ​ | ​ | (6,448) | ​ | ​ | (9,531) | ​ | ​ | (13,487) | ​ | ​ | (17,316)
Net income (loss) | ​ | $ | (105) | ​ | $ | (4,748) | ​ | $ | (31,307) | ​ | $ | 18,063
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 577 | ​ | ​ | 636 | ​ | ​ | 1,143 | ​ | ​ | 1,366
Natural Gas - MMcf | ​ | ​ | 1,929 | ​ | ​ | 2,155 | ​ | ​ | 4,109 | ​ | ​ | 4,562
Natural gas liquids – MBbls | ​ | ​ | 271 | ​ | ​ | 302 | ​ | ​ | 524 | ​ | ​ | 629
Total MBoe(1) | ​ | ​ | 1,170 | ​ | ​ | 1,297 | ​ | ​ | 2,352 | ​ | ​ | 2,755
Average daily production – Boe(1) | ​ | ​ | 12,857 | ​ | ​ | 14,253 | ​ | ​ | 12,923 | ​ | ​ | 15,221
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 79.20 | ​ | $ | 72.59 | ​ | $ | 77.10 | ​ | $ | 73.49
Natural gas price - Mcf | ​ | ​ | (1.10) | ​ | ​ | 0.96 | ​ | ​ | (0.02) | ​ | ​ | 1.09
Natural gas liquids price - Bbl | ​ | ​ | 20.31 | ​ | ​ | 18.73 | ​ | ​ | 20.15 | ​ | ​ | 20.37
Total per Boe(1) | ​ | ​ | 41.95 | ​ | ​ | 41.55 | ​ | ​ | 41.93 | ​ | ​ | 42.89
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 9.41 | ​ | $ | 8.76 | ​ | $ | 9.61 | ​ | $ | 8.37
Workover and other | ​ | ​ | 0.81 | ​ | ​ | 2.03 | ​ | ​ | 0.78 | ​ | ​ | 1.44
Taxes other than income | ​ | ​ | 2.86 | ​ | ​ | 2.45 | ​ | ​ | 2.70 | ​ | ​ | 2.31
Gathering and other | ​ | ​ | 10.36 | ​ | ​ | 12.97 | ​ | ​ | 12.51 | ​ | ​ | 12.10
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.82 | ​ | ​ | 4.64 | ​ | ​ | 3.09 | ​ | ​ | 3.97
Stock-based compensation | ​ | ​ | 0.03 | ​ | ​ | (0.60) | ​ | ​ | 0.06 | ​ | ​ | (0.20)
Depletion | ​ | ​ | 10.95 | ​ | ​ | 11.07 | ​ | ​ | 10.82 | ​ | ​ | 10.95

(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 $ 49.1 million and $53.9 million for the three months ended June 30, 2024 and 2023. The decrease in revenues is primarily attributable to our lower production volumes in 2024 compared to 2023 partially offset by an increase in average realized prices. Average realized prices (excluding the effects of hedging arrangements) increased approximately $0.40 per Boe for three months ended June 30, 2024 when compared with the same period in 2023.

Oil, natural gas and NGLs revenues were $98.6 million and $118.2 million for the six months ended June 30, 2024 and 2023, respectively. The decrease in revenues is primarily attributable to a decrease in our average realized prices and lower production volumes in 2024 compared to 2023. Average realized prices (excluding the effects of hedging arrangements) decreased approximately $0.96 per Boe for the six months ended June 30, 2024 when compared with the same period in 2023. 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.

Production averaged 12,857 Boe/d and 14,253 Boe/d for the three months ended June 30, 2024 and 2023, respectively, and 12,923 Boe/d and 15,221 for the six months ended June 30, 2024 and 2023, respectively. Production was lower in the second quarter and year to date period 2024 compared with the same period in 2023 due largely to the timing of capital expenditures spent to bring new wells online and natural production declines on our existing producing wells. Over the twelve months preceding June 30, 2024, we put online 4 gross (3.93 net) operated wells while in the twelve months preceding June 30, 2023, we put online 7 gross (6.5 net) operated wells. Also impacting 2024 production volumes was curtailment in Monument Draw due to downstream throughput limitations causing increased downtime and shut-in production.

Lease Operating Expenses. Lease operating expenses were $11.0 million and $11.4 million for the three months ended June 30, 2024 and 2023, respectively, and $22.6 million and $23.1 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, lease operating expenses were $9.41 per Boe and $8.76 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $9.61 per Boe and $8.37 per Boe for the six months ended June 30, 2024 and 2023, respectively. The increase in lease operating expenses on a per unit basis in the second quarter and first six months of 2024 is primarily a result of an inflationary market increase in maintenance, power, and chemical costs combined with lower production.

Workover and Other Expenses. Workover and other expenses were $1.0 million and $2.6 million for the three months ended June 30, 2024 and 2023, respectively and $1.8 million and $4.0 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, workover and other expenses were $0.81 per Boe and $2.03 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $0.78 per Boe and $1.44 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreased workover and other expenses in 2024 relate to more significant workover projects undertaken in the prior year.

Taxes Other than Income. Taxes other than income were $3.3 million and $3.2 million for the three months ended June 30, 2024 and 2023, respectively, and $6.3 million and $6.4 million for the six months ended June 30, 2024 and 2023, 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 $2.86 per Boe and $2.45 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $2.70 per Boe and $2.31 per Boe for the six months ended June 30, 2024 and 2023, respectively.

Gathering and Other Expenses. Gathering and other expenses were $12.1 million and $16.8 million for the three months ended June 30, 2024 and 2023, respectively, and $29.4 million and $33.3 million for the six months ended June 30, 2024 and 2023, 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 $10.36 per Boe and $12.97 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $12.51 per Boe and $12.10 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decrease in gathering and other expenses per Boe for the three months

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ended June 30, 2024 is primarily related to the increase in volumes treated at the AGI facility compared to the same period in 2023. The increase in gathering and other expenses per Boe for the six months ended June 30, 2024 is primarily related to an increased percentage of total production requiring H 2 S treatment, as well as inflationary impacts on costs associated with our own hydrogen sulfide treating plant, partially offset by increased volumes treated at the AGI facility, compared to the same period in 2023.

General and Administrative Expense. General and administrative expense was $3.3 million and $6.0 million for the three months ended June 30, 2024 and 2023, respectively, and $7.3 million and $11.0 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, general and administrative expenses were $2.82 per Boe and $4.64 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $3.09 per Boe and $3.97 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreases in general and administrative expense for the three and six months ended June 30, 2024 compared with the prior year periods is primarily associated with a decrease in payroll and benefits in connection with the headcount reduction in 2023 partially offset by an increase in legal fees associated with the merger.

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 $12.8 million and $14.4 million for the three months ended June 30, 2024 and 2023, respectively, and $25.4 million and $30.2 million for the six months ended June 30, 2024 and 2023, respectively. On a per unit basis, depletion expense was $10.95 per Boe and $11.07 per Boe for the three months ended June 30, 2024 and 2023, respectively, and $10.82 per Boe and $10.95 per Boe for the six months ended June 30, 2024 and 2023, respectively. The decreases in our depletion rate per Boe is primarily due to a period over period decrease in future development costs associated with proved reserves relative to the associated period over period decrease in proved reserves.

Net (loss) gain 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, 2024, we recorded a net derivative gain of $1.2 million ($4.4 million net gain on unsettled contracts and $3.2 million net realized loss on settled contracts). For the three months ended June 30, 2023, we recorded a net derivative gain of $4.5 million ($2.4 million net gain on unsettled contracts and $2.1 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 loss on unsettled contracts and $7.6 million net realized loss on settled contracts). For the six months ended June 30, 2023, we recorded a net derivative gain of $23.9 million ($23.3 million net gain on unsettled contracts and $0.6 million net realized gain on settled contracts). At June 30, 2024, we had a $10.5 million derivative asset ($5.9 million current) and a $45.2 million derivative liability ($25.6 million current).

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Interest Expense and Other. Interest expense and other was $6.5 million and $9.5 million for the three months ended June 30, 2024 and 2023, respectively, and $13.5 million and $17.3 million for the six months ended June 30, 2024 and 2023, respectively. Interest expense and other primarily decreased in the current year periods compared to the same periods in the prior year due to a lower average debt balance resulting from repayment of borrowings associated with our Amended Term Loan Agreement. 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 2024, our interest rate will be approximately 12.98% on outstanding borrowings.

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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 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. As of June 30, 2024, 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 6, “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 5, “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, 2024, the principal amount of our term loan debt was $160.2 million, of which substantially all 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, 2024, the weighted average interest rate on our variable rate debt was 12.98% per year. If the balance of our variable interest rate debt at June 30, 2024 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $2.6 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, 2024. 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,

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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, 2024 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 8, “Commitments and Contingencies,” which is incorporated herein by reference.

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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, 2023.

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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.

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2.1 | ​ | Agreement and Plan of Merger, dated as of December 14, 2023, by and among the Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed December 18, 2023).
2.1.1 | ​ | First Amendment to Agreement and Plan of Merger, dated as of January 24, 2024, by and among Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed January 24, 2024).
2.1.2 | ​ | Second Amendment to Agreement and Plan of Merger, dated as of February 6, 2024, by and among Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed February 6, 2024).
2.1.3 | ​ | Third Amendment to Agreement and Plan of Merger, dated as of February 16, 2024, by and among Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed February 16, 2024).
2.1.4 | ​ | Fourth Amendment to Agreement and Plan of Merger, dated April 16, 2024, by and among Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed April 17, 2024).
2.1.5 | ​ | Fifth Amendment to Agreement and Plan of Merger, dated June 10, 2024, by and among Battalion Oil Corporation, Fury Resources, Inc. and San Jacinto Merger Sub, Inc. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed June 11, 2024).
3.1 |  | Amended and Restated Certificate of Incorporation of Battalion Oil Corporation dated October 8, 2019, as amended by the Certificate of Amendment, dated January 21, 2020 (Incorporated by reference to Exhibit 3.1 of our Annual Report on Form 10-K filed March 25, 2020).
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).
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
​ | ​ | ​
​ | ​ | ​
August 14, 2024 | ​ | By: | /s/ MATTHEW B. STEELE
​ | ​ | ​ | ​
​ | ​ | Name: | Matthew B. Steele
​ | ​ | Title: | Chief Executive Officer
​ | ​ | ​ | (Principal Executive Officer and Principal Financial Officer)
​ | ​ | ​

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