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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, 2021
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

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)

1000 Louisiana Street, Suite 6600, Houston, TX 77002

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

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

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

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Large accelerated filer ◻ | Accelerated filer ◻ | Non-accelerated filer ⌧ | Smaller reporting company ☒ Emerging growth company ☐

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

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

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

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

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

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At August 5, 2021, 16,268,037 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, 2021 and 2020 | ​ | 5
​ | ​ | Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2021 and December 31, 2020 | ​ | 6
​ | ​ | Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) for the Three and Six Months Ended June 30, 2021 and the Year Ended December 31, 2020 | ​ | 7
​ | ​ | Condensed Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2021 and 2020 | ​ | 9
​ | ​ | Notes to Unaudited Condensed Consolidated Financial Statements | ​ | 10
ITEM 2. | ​ | Management’s Discussion and Analysis of Financial Condition and Results of Operations | ​ | 28
ITEM 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk | ​ | 41
ITEM 4. | ​ | Controls and Procedures | ​ | 42
​ | ​ | ​ | ​ | ​
PART II | ​ | OTHER INFORMATION | ​ | ​
ITEM 1. | ​ | Legal Proceedings | ​ | 43
ITEM 1A. | ​ | Risk Factors | ​ | 43
ITEM 2. | ​ | Unregistered Sales of Equity Securities and Use of Proceeds | ​ | 43
ITEM 3. | ​ | Defaults Upon Senior Securities | ​ | 43
ITEM 4. | ​ | Mine Safety Disclosures | ​ | 43
ITEM 5. | ​ | Other Information | ​ | 43
ITEM 6. | ​ | Exhibits | ​ | 44
Signatures | ​ | ​ | ​ | 45
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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, are forward looking statements and may concern, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. These forward-looking statements may be identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “objective,” “believe,” “predict,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in 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, 2020, 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 commodity 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;

| ● | impacts and potential risks related to actual or anticipated pandemics, such as the novel coronavirus (COVID-19) pandemic;

| ● | impacts of the ongoing COVID-19 pandemic on the health and safety of our employees;

| ● | our indebtedness, which may increase in the future;

| ● | higher levels of indebtedness 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;

| ● | drilling and operating risks, including accidents, equipment failures, fires, and leaks of toxic or hazardous materials which can result in injury, loss of life, pollution, property damage and suspension of operations;

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

| ● | 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;

| ● | our ability to secure adequate sour gas treating and/or sour gas take-away capacity in our Monument Draw area sufficient to handle production volumes;

| ● | 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;

| ● | the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars;

| ● | 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;

| ● | 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;

| ● | exploration and development risks;

| ● | the possibility that our industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental 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;

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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 Middle East, and armed conflict or acts of terrorism or sabotage;

| ● | 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 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,
​ | ​ | 2021 | ​ | 2020 | ​ | 2021 | ​ | 2020
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 51,935 | ​ | $ | 15,758 | ​ | $ | 93,205 | ​ | $ | 57,675
Natural gas | ​ | ​ | 5,317 | ​ | ​ | 836 | ​ | ​ | 14,404 | ​ | ​ | 1,190
Natural gas liquids | ​ | ​ | 6,851 | ​ | ​ | 1,437 | ​ | ​ | 11,760 | ​ | ​ | 6,190
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 64,103 | ​ | ​ | 18,031 | ​ | ​ | 119,369 | ​ | ​ | 65,055
Other | ​ | ​ | 263 | ​ | ​ | 463 | ​ | ​ | 515 | ​ | ​ | 838
Total operating revenues | ​ | ​ | 64,366 | ​ | ​ | 18,494 | ​ | ​ | 119,884 | ​ | ​ | 65,893
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,169 | ​ | ​ | 10,300 | ​ | ​ | 19,636 | ​ | ​ | 22,789
Workover and other | ​ | ​ | 767 | ​ | ​ | 539 | ​ | ​ | 1,327 | ​ | ​ | 1,862
Taxes other than income | ​ | ​ | 2,912 | ​ | ​ | 1,493 | ​ | ​ | 6,104 | ​ | ​ | 4,408
Gathering and other | ​ | ​ | 14,331 | ​ | ​ | 15,228 | ​ | ​ | 27,502 | ​ | ​ | 25,775
Restructuring | ​ | ​ | — | ​ | ​ | 2,162 | ​ | ​ | — | ​ | ​ | 2,580
General and administrative | ​ | ​ | 4,031 | ​ | ​ | 5,270 | ​ | ​ | 8,858 | ​ | ​ | 9,126
Depletion, depreciation and accretion | ​ | ​ | 11,249 | ​ | ​ | 14,382 | ​ | ​ | 21,844 | ​ | ​ | 32,412
Full cost ceiling impairment | ​ | ​ | — | ​ | ​ | 60,107 | ​ | ​ | — | ​ | ​ | 60,107
Total operating expenses | ​ | ​ | 43,459 | ​ | ​ | 109,481 | ​ | ​ | 85,271 | ​ | ​ | 159,059
Income (loss) from operations | ​ | ​ | 20,907 | ​ | ​ | (90,987) | ​ | ​ | 34,613 | ​ | ​ | (93,166)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | (53,089) | ​ | ​ | (34,761) | ​ | ​ | (98,800) | ​ | ​ | 83,538
Interest expense and other | ​ | ​ | (1,747) | ​ | ​ | (1,568) | ​ | ​ | (3,117) | ​ | ​ | (3,197)
Total other income (expenses) | ​ | ​ | (54,836) | ​ | ​ | (36,329) | ​ | ​ | (101,917) | ​ | ​ | 80,341
Income (loss) before income taxes | ​ | ​ | (33,929) | ​ | ​ | (127,316) | ​ | ​ | (67,304) | ​ | ​ | (12,825)
Income tax benefit (provision) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Net income (loss) | ​ | $ | (33,929) | ​ | $ | (127,316) | ​ | $ | (67,304) | ​ | $ | (12,825)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) per share of common stock: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | $ | (2.09) | ​ | $ | (7.86) | ​ | $ | (4.14) | ​ | $ | (0.79)
Diluted | ​ | $ | (2.09) | ​ | $ | (7.86) | ​ | $ | (4.14) | ​ | $ | (0.79)
Weighted average common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 16,268 | ​ | ​ | 16,204 | ​ | ​ | 16,250 | ​ | ​ | 16,204
Diluted | ​ | ​ | 16,268 | ​ | ​ | 16,204 | ​ | ​ | 16,250 | ​ | ​ | 16,204

​

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, 2021 | ​ | December 31, 2020
Current assets: | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 1,458 | ​ | $ | 4,295
Accounts receivable, net | ​ | ​ | 37,098 | ​ | ​ | 32,242
Assets from derivative contracts | ​ | ​ | 1,280 | ​ | ​ | 8,559
Prepaids and other | ​ | ​ | 2,475 | ​ | ​ | 2,740
Total current assets | ​ | ​ | 42,311 | ​ | ​ | 47,836
Oil and natural gas properties (full cost method): | ​ | ​ | ​ | ​ | ​ | ​
Evaluated | ​ | ​ | 544,418 | ​ | ​ | 509,274
Unevaluated | ​ | ​ | 75,822 | ​ | ​ | 75,494
Gross oil and natural gas properties | ​ | ​ | 620,240 | ​ | ​ | 584,768
Less - accumulated depletion | ​ | ​ | (316,519) | ​ | ​ | (295,163)
Net oil and natural gas properties | ​ | ​ | 303,721 | ​ | ​ | 289,605
Other operating property and equipment: | ​ | ​ | ​ | ​ | ​ | ​
Other operating property and equipment | ​ | ​ | 3,367 | ​ | ​ | 3,535
Less - accumulated depreciation | ​ | ​ | (1,206) | ​ | ​ | (1,149)
Net other operating property and equipment | ​ | ​ | 2,161 | ​ | ​ | 2,386
Other noncurrent assets: | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | ​ | 563 | ​ | ​ | 4,009
Operating lease right of use assets | ​ | ​ | 78 | ​ | ​ | 310
Other assets | ​ | ​ | 2,903 | ​ | ​ | 2,351
Total assets | ​ | $ | 351,737 | ​ | $ | 346,497
​ | ​ | ​ | ​ | ​ | ​ | ​
Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable and accrued liabilities | ​ | $ | 65,297 | ​ | $ | 58,928
Liabilities from derivative contracts | ​ | ​ | 71,443 | ​ | ​ | 22,125
Current portion of long-term debt | ​ | ​ | 2,209 | ​ | ​ | 1,720
Operating lease liabilities | ​ | ​ | 78 | ​ | ​ | 403
Total current liabilities | ​ | ​ | 139,027 | ​ | ​ | 83,176
Long-term debt | ​ | ​ | 163,000 | ​ | ​ | 158,489
Other noncurrent liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | ​ | 15,117 | ​ | ​ | 4,291
Asset retirement obligations | ​ | ​ | 10,945 | ​ | ​ | 10,583
Commitments and contingencies (Note 10) | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity: | ​ | ​ | ​ | ​ | ​ | ​
Common stock: 100,000,000 shares of $0.0001 par value authorized; | ​ | ​ | ​ | ​ | ​ | ​
16,268,037 and 16,203,979 shares issued and outstanding as of | ​ | ​ | ​ | ​ | ​ | ​
June 30, 2021 and December 31, 2020, respectively | ​ | ​ | 2 | ​ | ​ | 2
Additional paid-in capital | ​ | ​ | 331,117 | ​ | ​ | 330,123
Retained earnings (accumulated deficit) | ​ | ​ | (307,471) | ​ | ​ | (240,167)
Total stockholders' equity | ​ | ​ | 23,648 | ​ | ​ | 89,958
Total liabilities and stockholders' equity | ​ | $ | 351,737 | ​ | $ | 346,497

​

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, 2020 | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 330,123 | ​ | $ | (240,167) | ​ | $ | 89,958
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (33,375) | ​ | ​ | (33,375)
Long-term incentive plan vestings | ​ | 87 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reduction in shares to cover | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
individuals' tax withholding | ​ | (24) | ​ | ​ | — | ​ | ​ | (264) | ​ | ​ | — | ​ | ​ | (264)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 692 | ​ | ​ | — | ​ | ​ | 692
Balances at March 31, 2021 | ​ | 16,267 | ​ | ​ | 2 | ​ | ​ | 330,551 | ​ | ​ | (273,542) | ​ | ​ | 57,011
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (33,929) | ​ | ​ | (33,929)
Long-term incentive plan vestings | ​ | 1 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reduction in shares to cover | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
individuals' tax withholding | ​ | — | ​ | ​ | — | ​ | ​ | (5) | ​ | ​ | — | ​ | ​ | (5)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 571 | ​ | ​ | — | ​ | ​ | 571
Balances at June 30, 2021 | ​ | 16,268 | ​ | $ | 2 | ​ | $ | 331,117 | ​ | $ | (307,471) | ​ | $ | 23,648

​

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, 2019 | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 327,108 | ​ | $ | (10,460) | ​ | $ | 316,650
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 114,491 | ​ | ​ | 114,491
Equity issuance costs and other | ​ | — | ​ | ​ | — | ​ | ​ | (13) | ​ | ​ | — | ​ | ​ | (13)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 449 | ​ | ​ | — | ​ | ​ | 449
Balances at March 31, 2020 | ​ | 16,204 | ​ | ​ | 2 | ​ | ​ | 327,544 | ​ | ​ | 104,031 | ​ | ​ | 431,577
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (127,316) | ​ | ​ | (127,316)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 910 | ​ | ​ | — | ​ | ​ | 910
Balances at June 30, 2020 | ​ | 16,204 | ​ | ​ | 2 | ​ | ​ | 328,454 | ​ | ​ | (23,285) | ​ | ​ | 305,171
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (153,125) | ​ | ​ | (153,125)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 744 | ​ | ​ | — | ​ | ​ | 744
Balances at September 30, 2020 | ​ | 16,204 | ​ | ​ | 2 | ​ | ​ | 329,198 | ​ | ​ | (176,410) | ​ | ​ | 152,790
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (63,757) | ​ | ​ | (63,757)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 925 | ​ | ​ | — | ​ | ​ | 925
Balances at December 31, 2020 | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 330,123 | ​ | $ | (240,167) | ​ | $ | 89,958

​

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,
​ | 2021 | ​ | 2020
Cash flows from operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (67,304) | ​ | $ | (12,825)
Adjustments to reconcile net income (loss) to net cash | ​ | ​ | ​ | ​ | ​ | ​
provided by (used in) operating activities: | ​ | ​ | ​ | ​ | ​ | ​
Depletion, depreciation and accretion | ​ | ​ | 21,844 | ​ | ​ | 32,412
Full cost ceiling impairment | ​ | ​ | — | ​ | ​ | 60,107
Stock-based compensation, net | ​ | ​ | 1,079 | ​ | ​ | 1,173
Unrealized loss (gain) on derivative contracts | ​ | ​ | 70,869 | ​ | ​ | (45,157)
Reorganization items, net | ​ | ​ | — | ​ | ​ | (5,723)
Accrued settlements on derivative contracts | ​ | ​ | 6,972 | ​ | ​ | 349
Other income (expense) | ​ | ​ | (287) | ​ | ​ | 464
Change in assets and liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | (5,488) | ​ | ​ | 17,618
Prepaids and other | ​ | ​ | (441) | ​ | ​ | 3,468
Accounts payable and accrued liabilities | ​ | ​ | 1,856 | ​ | ​ | (8,782)
Net cash provided by (used in) operating activities | ​ | ​ | 29,100 | ​ | ​ | 43,104
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​
Oil and natural gas capital expenditures | ​ | ​ | (37,593) | ​ | ​ | (91,164)
Proceeds received from sale of oil and natural gas properties | ​ | ​ | 926 | ​ | ​ | 500
Funds held in escrow and other | ​ | ​ | (2) | ​ | ​ | 509
Net cash provided by (used in) investing activities | ​ | ​ | (36,669) | ​ | ​ | (90,155)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: | ​ | ​ | ​ | ​ | ​ | ​
Proceeds from borrowings | ​ | ​ | 82,000 | ​ | ​ | 81,209
Repayments of borrowings | ​ | ​ | (77,000) | ​ | ​ | (44,000)
Equity issuance costs and other | ​ | ​ | (268) | ​ | ​ | (32)
Net cash provided by (used in) financing activities | ​ | ​ | 4,732 | ​ | ​ | 37,177
​ | ​ | ​ | ​ | ​ | ​ | ​
Net increase (decrease) in cash and cash equivalents | ​ | ​ | (2,837) | ​ | ​ | (9,874)
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents at beginning of period | ​ | ​ | 4,295 | ​ | ​ | 10,275
Cash and cash equivalents at end of period | ​ | $ | 1,458 | ​ | $ | 401
​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow information: | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for reorganization items | ​ | $ | — | ​ | $ | 5,723
​ | ​ | ​ | ​ | ​ | ​ | ​
Disclosure of non-cash investing and financing activities: | ​ | ​ | ​ | ​ | ​ | ​
Asset retirement obligations | ​ | $ | 105 | ​ | $ | (90)

​

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 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. 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 (SEC) on March 8, 2021. Please refer to the notes in the Annual Report on Form 10-K for the year ended December 31, 2020 when reviewing interim financial results.

Risk and Uncertainties

The Company is continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on its business, including how it has and may continue to impact its operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of its business in a safe and secure manner. In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand. As a consequence, beginning in March 2020, the Company realized lower revenue as a result of commodity price declines, resulting in the Company temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally, the Company incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of the Company’s reserves.

​

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices to pre-pandemic levels. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. Furthermore, the health of the Company’s employees, contractors and vendors, and its ability to meet staffing needs in its operations and critical functions remain concerns and cannot be predicted, nor can the impact on the Company’s customers, vendors and contractors. Any material effect on these parties could adversely impact the Company. These and other factors could affect the Company’s operations, earnings and cash flows and could cause its results to not be comparable to those of the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results. For further information regarding the actual and potential impacts of COVID-19 on the Company, see “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Use of Estimates

The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States 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, and fair value estimates. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.

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, has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Cash and Cash Equivalents

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.

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. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of June 30, 2021 and December 31, 2020, allowances for doubtful accounts were less than $0.1 million and approximately $0.2 million, respectively.

Other Operating Property and Equipment

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

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

Concentrations of Credit Risk

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

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts from its oil and natural gas purchasers. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. Joint operating agreements govern the operations of an oil or natural gas well and, in most instances, provide for offsetting of amounts payable or receivable between the Company and its joint interest owners. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

The Company’s exposure to credit risk under its derivative contracts is diversified 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, 2021, the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Senior Credit Agreement.

Restructuring

During the three and six months ended June 30, 2020, the Company incurred approximately $2.2 million and $2.6 million in restructuring charges, respectively, related to the consolidation into one corporate office and reductions in its workforce due to efforts to improve efficiencies and go forward costs. In May 2020, in furtherance of the consolidation into one corporate office, the Company exercised a one-time early termination option under the lease agreement for the Company’s office space in Denver, Colorado. These costs were recorded in “Restructuring” on the unaudited condensed consolidated statements of operations. Refer to Note 2, “Leases,” for further details.

Change in Estimate

In late March 2020, due to changes in market conditions and decreased commodity prices, the Company determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to “General and administrative” on the unaudited condensed consolidated statement of operations for the three months ended March 31, 2020.

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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 generally accepted accounting principles to contracts, hedging arrangements, and other transactions that reference LIBOR. ASU 2020-04 will be in effect through December 31, 2022. The Company is currently evaluating ASU 2020-04 and the impact it may have on its operating results, financial position and disclosures.

​

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of their simplification initiative. ASU 2019-12 simplifies the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. The Company adopted ASU 2019-12 effective January 1, 2021. The adoption of ASU 2019-12 did not have a material impact on the Company’s operating results, financial position or disclosures.

​

​

2. LEASES

The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of an identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset.

The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the unaudited condensed consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date.

Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842, Leases (ASC 842) requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on an index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise.

The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company’s operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term.

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Variable lease payments associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other,” “Restructuring” or “General and administrative” in the unaudited condensed consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis.

The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value.

The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, an adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the unaudited condensed consolidated statements of operations.

The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases when incurred. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.

The Company leases equipment and office space under operating leases. The Company has no leases that meet the criteria for classification as a finance lease. The “Operating lease right of use assets” outstanding on the unaudited condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020 have an initial lease term of 5 years. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company’s leases for the six months ended June 30, 2021 and 2020 (in thousands, except years and discount rate):

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended | ​
​ | ​ | June 30, | ​
​ |  | 2021 | ​ |  | 2020 |
Lease cost | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating lease costs | ​ | $ | 235 | ​ | ​ | $ | 1,797 | ​
Short-term lease costs | ​ | ​ | 1,889 | ​ | ​ | ​ | 16,094 | ​
Variable lease costs | ​ | ​ | 229 | ​ | ​ | ​ | 682 | ​
Total lease costs | ​ | $ | 2,353 | ​ | ​ | $ | 18,573 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other information | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for amounts included in the measurement of lease liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating cash flows from operating leases | ​ | $ | 328 | ​ | ​ | $ | 1,790 | ​
Weighted-average remaining lease term - operating leases | ​ | ​ | 0.2 | years | ​ | ​ | 1.0 | years
Weighted-average discount rate - operating leases | ​ | ​ | 3.70 | % | ​ | ​ | 3.70 | %

As described in Note 1, “Financial Statement Presentation,” the Company exercised a one-time early termination option under the lease agreement for the Company’s office space in Denver, Colorado in May 2020 and paid a $1.3 million termination fee. The Company’s abandonment of its office lease in Denver resulted in a $0.5 million impairment to its operating lease right of use asset presented as “Restructuring” in the unaudited condensed consolidated statements of operations for the three months ended June 30, 2020.

Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of June 30, 2021, are presented in the table below (in thousands):

​ | ​ | ​ | ​
​ |  | June 30, 2021
Remaining period in 2021 | ​ | $ | 78
2022 | ​ | ​ | —
2023 | ​ | ​ | —
2024 | ​ | ​ | —
2025 | ​ | ​ | —
Thereafter | ​ | ​ | —
Total operating lease payments | ​ | ​ | 78
Less: discount to present value | ​ | ​ | —
Total operating lease liabilities | ​ | ​ | 78
Less: current operating lease liabilities | ​ | ​ | 78
Noncurrent operating lease liabilities | ​ | $ | —

​

​

3. OPERATING REVENUES

Revenue is measured based on consideration specified in a contract with a customer 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. 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 the commodity to the customer. 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 $33.9 million and $24.5 million as of June 30, 2021 and December 31, 2020, respectively, as “Accounts receivable” and “Other assets” on the unaudited condensed consolidated balance sheets.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Substantially all of the Company’s revenues are derived from single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations, for the periods indicated (in thousands):

​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | Six Months Ended
​ | ​ | June 30, | ​ | June 30,
​ |  | 2021 | ​ | 2020 | ​ | 2021 | ​ | 2020
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 51,935 | ​ | $ | 15,758 | ​ | $ | 93,205 | ​ | $ | 57,675
Natural gas | ​ | ​ | 5,317 | ​ | ​ | 836 | ​ | ​ | 14,404 | ​ | ​ | 1,190
Natural gas liquids | ​ | ​ | 6,851 | ​ | ​ | 1,437 | ​ | ​ | 11,760 | ​ | ​ | 6,190
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 64,103 | ​ | ​ | 18,031 | ​ | ​ | 119,369 | ​ | ​ | 65,055
Other | ​ | ​ | 263 | ​ | ​ | 463 | ​ | ​ | 515 | ​ | ​ | 838
Total operating revenues | ​ | $ | 64,366 | ​ | $ | 18,494 | ​ | $ | 119,884 | ​ | $ | 65,893

​

Oil Sales

The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price, averaged over the daily settlement prices for a production month, and adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, averaged over the daily settlement prices for a production month, and net of applicable market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received.

Settlement statements for the Company’s crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company’s crude oil contracts is typically due on or before the 20th day of the month following the delivery month.

Natural Gas and Natural Gas Liquids Sales

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

Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees

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incurred to gather, process or transport the commodities are presented separately as “Gathering and other " on the unaudited condensed consolidated statements of operations.

Settlement statements for the Company’s natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. The majority of the Company’s natural gas and natural gas liquids prices are based on daily average pricing for the month. Historically, differences between the Company’s estimates and the actual revenue received have not been material. Payment under the Company’s natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month.

​

4. DIVESTITURES

​

Northern West Quito Assets

On December 18, 2020, the Company sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total adjusted sales price of $25.9 million in cash. The effective date of the transaction was October 1, 2020. Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded. The Company used the net proceeds from the sale to repay amounts outstanding under the Company’s Senior Credit Agreement and for general corporate purposes.

5. 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, 2021, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2021 of the West Texas Intermediate (WTI) crude oil spot price of $49.72 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2021 of the Henry Hub natural gas price of $2.43 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2021 did not exceed the ceiling amount.

​

At June 30, 2020, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2020 of the WTI crude oil spot price of $47.37 per

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barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended June 30, 2020 of the Henry Hub natural gas price of $2.07 MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2020 exceeded the ceiling amount by $60.1 million which resulted in a ceiling test impairment charge of that amount for the quarter. The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020 to $47.37 per barrel at June 30, 2020. This average price decline was partially offset by favorable differentials and lower operating expenses.

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.

​

6. DEBT

As of June 30, 2021 and December 31, 2020, the Company’s debt consisted of the following (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2021 | ​ | December 31, 2020
Senior revolving credit facility | ​ | $ | 163,000 | ​ | $ | 158,000
Paycheck Protection Program loan | ​ | ​ | 2,209 | ​ | ​ | 2,209
Total debt | ​ | ​ | 165,209 | ​ | ​ | 160,209
Current portion of Paycheck Protection Program loan | ​ | ​ | 2,209 | ​ | ​ | 1,720
Total long-term debt | ​ | $ | 163,000 | ​ | $ | 158,489

​

Senior Revolving Credit Facility

On October 8, 2019, the Company entered into a senior secured revolving credit agreement, as amended, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $185.0 million. At June 30, 2021, the Company had $163.0 million indebtedness outstanding and approximately $1.9 million letters of credit outstanding under the Senior Credit Agreement, resulting in $20.1 million of borrowing capacity under the current borrowing base of $185.0 million. Pursuant to the Fourth Amendment to the Senior Credit Agreement, the borrowing base is subject to a reduction on September 1, 2021, which is discussed further below.

​

A portion of the Senior Credit Agreement, in the amount of $25.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. Redeterminations of the borrowing base occur semi-annually on May 1 and November 1, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 2.00% to 3.00% for ABR-based loans or at specified margins over LIBOR of 3.00% to 4.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement. These margins fluctuate based on the Company’s utilization of the facility.

The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement. The Company may be required to make mandatory prepayments of the

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outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations. Amounts outstanding under the Senior Credit Agreement are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00. As of June 30, 2021, after giving effect to the Third Amendment, discussed below, the Company was in compliance with the financial covenants under the Senior Credit Agreement.

On October 29, 2020, the Company entered into the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment). The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020. The Third Amendment also reduced the amount available for issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require the Company to enter into swap agreements representing not less than 65% of the Company’s reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of the Company’s uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

​

On May 10, 2021, the Company entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021. The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provides for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

Paycheck Protection Program Loan

On April 16, 2020, the Company entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as the Company makes a timely application of forgiveness to the SBA, the Company is not required to make any payments under the PPP Loan until the forgiveness amount is communicated to the Company by the SBA.

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The Company may elect, at its option, to prepay 20% or less of the borrowings outstanding under the PPP Loan without premium or penalty, and without notice. Prepayments of more than 20% of the outstanding borrowings require written advanced notice and payment of accrued interest. The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.

Under the terms of the CARES Act, the Company can apply for and be granted forgiveness for all or a portion of the PPP Loan. Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels. The Company believes it is eligible for, and is pursuing forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act; however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

7. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurement (ASC 820), 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. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes 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.

As required by ASC 820, 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 that were accounted for at fair value as of June 30, 2021 and December 31, 2020 (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | June 30, 2021
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ |  | 1,843 | ​ | $ | — | ​ |  | 1,843
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | ​ | 86,560 | ​ | $ | — | ​ | ​ | 86,560

​

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | December 31, 2020
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ | $ | 12,568 | ​ | $ | — | ​ | $ | 12,568
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | $ | 26,416 | ​ | $ | — | ​ | $ | 26,416

​

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, “Derivative and Hedging Activities,” for additional discussion of derivatives.

The Company’s derivative contracts are with 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 following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The 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 and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

8. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy, it generally hedges a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids 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’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, 2021, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Credit Agreement.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Company’s crude oil, natural gas and natural gas liquids derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls. 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. A costless collar consists 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. 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 Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020 (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Derivatives not designated as | ​ | ​ | ​ | Asset derivative contracts | ​ | ​ | ​ | Liability derivative contracts
hedging contracts under ASC 815 |  | Balance sheet location |  | June 30, 2021 |  | December 31, 2020 |  | Balance sheet location |  | June 30, 2021 |  | December 31, 2020
Commodity contracts | ​ | Current assets - assets from derivative contracts | ​ | $ | 1,280 | ​ | $ | 8,559 | ​ | Current liabilities - liabilities from derivative contracts | ​ | $ | (71,443) | ​ | $ | (22,125)
Commodity contracts | ​ | Other noncurrent assets - assets from derivative contracts | ​ | ​ | 563 | ​ | ​ | 4,009 | ​ | Other noncurrent liabilities - liabilities from derivative contracts | ​ | ​ | (15,117) | ​ | ​ | (4,291)
Total derivatives not designated as hedging contracts under ASC 815 | ​ | ​ | ​ | $ | 1,843 | ​ | $ | 12,568 | ​ | ​ | ​ | $ | (86,560) | ​ | $ | (26,416)

​

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):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Amount of gain or (loss) | ​ | Amount of gain or (loss)
​ | ​ | ​ | ​ | recognized in income on | ​ | recognized in income on
​ | ​ | ​ | ​ | derivative contracts for the | ​ | derivative contracts for the
Derivatives not designated | ​ | Location of gain or | ​ | Three Months Ended | ​ | Six Months Ended
as hedging contracts | ​ | (loss) recognized in income | ​ | June 30, | ​ | June 30,
under ASC 815 |  | on derivative contracts | ​ | 2021 | ​ | 2020 | ​ | 2021 | ​ | 2020
Commodity contracts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unrealized gain (loss) on commodity contracts | ​ | Other income (expenses) - net gain (loss) on derivative contracts | ​ | $ | (34,817) | ​ | $ | (67,221) | ​ | $ | (70,869) | ​ | $ | 45,157
Realized gain (loss) on commodity contracts | ​ | Other income (expenses) - net gain (loss) on derivative contracts | ​ | ​ | (18,272) | ​ | ​ | 32,460 | ​ | ​ | (27,931) | ​ | ​ | 38,381
Total net gain (loss) on derivative contracts | ​ | ​ | ​ | $ | (53,089) | ​ | $ | (34,761) | ​ | $ | (98,800) | ​ | $ | 83,538

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

During the six months ended June 30, 2020, the Company terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $16.3 million which were recorded in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.

At June 30, 2021, the Company had the following open crude oil and natural gas derivative contracts:

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | Volume in | ​ | Weighted
​ | ​ | ​ | ​ | ​ | ​ | Mmbtu's/ | ​ | Average
Period |  | Instrument |  | Commodity |  | Bbl's |  | Price
2021 | ​ | Fixed-Price Swap | ​ | Crude Oil | ​ | 1,457,000 | ​ | $ | 43.65
2021 | ​ | Fixed-Price Swap | ​ | Natural Gas | ​ | 2,168,512 | ​ | ​ | 2.72
2021 | ​ | Basis Swap | ​ | Crude Oil | ​ | 1,457,000 | ​ | ​ | (0.32)
2021 | ​ | Basis Swap | ​ | Natural Gas | ​ | 2,168,512 | ​ | ​ | (0.24)
2021 | ​ | WTI NYMEX Roll | ​ | Crude Oil | ​ | 1,209,000 | ​ | ​ | (0.41)
2022 | ​ | Fixed-Price Swap | ​ | Crude Oil | ​ | 2,368,434 | ​ | ​ | 48.81
2022 | ​ | Fixed-Price Swap | ​ | Natural Gas | ​ | 1,297,420 | ​ | ​ | 3.01
2022 | ​ | Producer Collar (Ceiling) | ​ | Natural Gas | ​ | 2,388,624 | ​ | ​ | 2.65
2022 | ​ | Producer Collar (Floor) | ​ | Natural Gas | ​ | 2,388,624 | ​ | ​ | 2.50
2022 | ​ | Basis Swap | ​ | Crude Oil | ​ | 2,368,434 | ​ | ​ | 0.47
2022 | ​ | Basis Swap | ​ | Natural Gas | ​ | 3,686,044 | ​ | ​ | (0.30)
2022 | ​ | WTI NYMEX Roll | ​ | Crude Oil | ​ | 2,399,434 | ​ | ​ | (0.03)

​

​

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, 2021 and December 31, 2020 (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Derivative Assets | ​ | Derivative Liabilities
Offsetting of Derivative Assets and Liabilities |  | June 30, 2021 |  | December 31, 2020 |  | June 30, 2021 |  | December 31, 2020
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gross Amounts Presented in the Consolidated Balance Sheet | ​ | $ | 1,843 | ​ | $ | 12,568 | ​ | $ | (86,560) | ​ | $ | (26,416)
Amounts Not Offset in the Consolidated Balance Sheet | ​ | ​ | (1,843) | ​ | ​ | (8,968) | ​ | ​ | 1,843 | ​ | ​ | 8,968
Net Amount | ​ | $ | — | ​ | $ | 3,600 | ​ | $ | (84,717) | ​ | $ | (17,448)

​

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

9. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (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.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

​

​ | ​ | ​ | ​
Liability for asset retirement obligations as of December 31, 2020 |  | $ | 10,583
Additions | ​ | ​ | 105
Accretion expense | ​ | ​ | 257
Liability for asset retirement obligations as of June 30, 2021 | ​ | $ | 10,945

​

​

10. COMMITMENTS AND CONTINGENCIES

Commitments

As of June 30, 2021, the Company has a minimum volume commitment with a third party for the treating of sour gas production through June 30, 2022. The future payments associated with the minimum volume commitment are approximately $4.9 million and $4.8 million for the remainder of 2021 and for 2022, respectively.

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, 2021, the Company had in place two long-term crude oil contracts and 12 long-term 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

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 our 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.

​

11. STOCKHOLDERS’ EQUITY

Warrants

On October 8, 2019, the Company entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which the Company issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants), on a pro rata basis to pre-emergence holders of the predecessor Company’s common stock pursuant to the Company’s plan of reorganization.

Each Warrant represents the right to purchase one share of common stock at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On October 8, 2019, the Company issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of common stock, with an initial exercise price of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of common stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of common stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75%, compounding monthly, as provided in the Warrant Agreement. As of June 30, 2021, the Company had 1.8 million Series A, 2.2 million Series B and 2.9 million Series C warrants outstanding with corresponding exercise prices of $43.78, $52.86 and $66.47 per share, respectively.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Warrants do not grant any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of the Company’s business.

Incentive Plans

On January 29, 2020, the Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the Plan) with an effective date of January 1, 2020 in which an aggregate of approximately 1.5 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. On June 8, 2021, Amendment No. 1 to the Plan to increase, by 0.3 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of approximately 1.8 million shares, became effective. As of June 30, 2021 and December 31, 2020, a maximum of 0.5 million and 0.2 million, respectively, of the Company’s common stock remained reserved for issuance under the Plan.

The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected not to apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited.

For the three and six months ended June 30, 2021, the Company recognized expense of $0.5 million and $1.1 million, respectively, related to stock-based-compensation. For the three and six months ended June 30, 2020, the Company recognized expense of $0.8 million and $1.2 million, respectively, related to stock-based compensation. Stock-based compensation expense is recorded as a component of "General and administrative" on the unaudited condensed consolidated statements of operations.

Stock Options

From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. Awards granted under the Plan typically vest over a four year period at a rate of one-fourth on the annual anniversary date of the grant and expire seven years from the date of grant.

No stock options were granted during the six months ended June 30, 2021. At June 30, 2021, the Company had $0.7 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.6 years.

During the six months ended June 30, 2020, the Company granted stock options under the Plan covering 0.5 million shares of common stock to employees of the Company. These stock options have exercise prices ranging from $18.91 to $37.83 with a weighted average exercise price of $28.32 per share. At June 30, 2020, the Company had $1.3 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 2.1 years.

Restricted Stock

From time to time, the Company grants shares of restricted stock units (RSUs) under the Plan to employees of the Company. Under the Plan, employee RSUs will vest and convert to shares typically over a four year period at a rate of one-fourth on the annual anniversary date of the grant or when the performance or market conditions described below occur.

During the six months ended June 30, 2021, the Company granted less than 0.1 million shares of RSUs which will vest over four years at a rate of one-fourth on the annual anniversary date of the grant. These RSUs were granted at a fair

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

value price of $8.00 per share. At June 30, 2021, the Company had $3.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of 2.3 years.

During the six months ended June 30, 2020, the Company granted 0.9 million shares of RSUs with the vesting conditions and fair values described below under the Plan to employees of the Company. At June 30, 2020, the Company had $5.6 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of 3.0 years.

| ● | 0.4 million RSUs granted will vest over four years at a rate one-fourth on the annual anniversary date of the grant. These RSUs were granted at a fair value prices ranging from $4.36 to $11.89 with a weighted average fair value price of $11.80 per share.

| ● | 0.2 million RSUs granted will vest in full only upon achievement of certain business combination goals, as defined in the award agreements. These RSUs were granted at a fair value of $11.89 per share. As of June 30, 2021, a business combination, as defined in the awards agreements, had not been consummated and was not considered probable. As such, no expense has been recognized for the RSUs with business combination vesting conditions.

| ● | 0.3 million RSUs granted will vest in full or in part or may terminate based on the Company’s total shareholder return relative to the total shareholder return of certain of its peer companies as defined in the award agreements over the performance period ending on February 20, 2024. These RSUs were granted at a fair value of $6.48 per share.

​

12. 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,
​ |  | 2021 | ​ | 2020 | ​ | 2021 | ​ | 2020
Basic: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (33,929) | ​ | $ | (127,316) | ​ | $ | (67,304) | ​ | $ | (12,825)
Weighted average basic number of common shares outstanding | ​ | ​ | 16,268 | ​ | ​ | 16,204 | ​ | ​ | 16,250 | ​ | ​ | 16,204
Basic net income (loss) per share of common stock | ​ | $ | (2.09) | ​ | $ | (7.86) | ​ | $ | (4.14) | ​ | $ | (0.79)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Diluted: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (33,929) | ​ | $ | (127,316) | ​ | $ | (67,304) | ​ | $ | (12,825)
Weighted average basic number of common shares outstanding | ​ | ​ | 16,268 | ​ | ​ | 16,204 | ​ | ​ | 16,250 | ​ | ​ | 16,204
Common stock equivalent shares representing shares issuable upon: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercise of Series A Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Exercise of Series B Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Exercise of Series C Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Exercise of stock options | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Vesting of restricted stock units | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive | ​ | ​ | Anti-dilutive
Weighted average diluted number of common shares outstanding | ​ | ​ | 16,268 | ​ | ​ | 16,204 | ​ | ​ | 16,250 | ​ | ​ | 16,204
Diluted net income (loss) per share of common stock | ​ | $ | (2.09) | ​ | $ | (7.86) | ​ | $ | (4.14) | ​ | $ | (0.79)

​

Common stock equivalents, including warrants, options and restricted stock units, totaling 7.7 million for the three and six months ended June 30, 2021 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Common stock equivalents, including warrants, options and restricted stock units, totaling 7.8 million and 7.6 million for the three and six months ended June 30, 2020, respectively, were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net losses.

​

​

13. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | June 30, 2021 |  | December 31, 2020
Accounts receivable, net: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 32,370 | ​ | $ | 22,781
Joint interest accounts | ​ | ​ | 4,539 | ​ | ​ | 8,543
Other | ​ | ​ | 189 | ​ | ​ | 918
​ | ​ | $ | 37,098 | ​ | $ | 32,242
Prepaids and other: | ​ | ​ | ​ | ​ | ​ | ​
Prepaids | ​ | $ | 500 | ​ | $ | 892
Funds in escrow | ​ | ​ | 1,773 | ​ | ​ | 1,740
Other | ​ | ​ | 202 | ​ | ​ | 108
​ | ​ | $ | 2,475 | ​ | $ | 2,740
Other assets: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 1,565 | ​ | $ | 1,720
Funds in escrow | ​ | ​ | 1,287 | ​ | ​ | 581
Other | ​ | ​ | 51 | ​ | ​ | 50
​ | ​ | $ | 2,903 | ​ | $ | 2,351
Accounts payable and accrued liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Trade payables | ​ | $ | 28,091 | ​ | $ | 22,740
Accrued oil and natural gas capital costs | ​ | ​ | 6,769 | ​ | ​ | 8,344
Revenues and royalties payable | ​ | ​ | 20,877 | ​ | ​ | 16,412
Accrued interest expense | ​ | ​ | 1,554 | ​ | ​ | 482
Accrued employee compensation | ​ | ​ | 2,082 | ​ | ​ | 3,223
Accrued lease operating expenses | ​ | ​ | 5,830 | ​ | ​ | 7,622
Other | ​ | ​ | 94 | ​ | ​ | 105
​ | ​ | $ | 65,297 | ​ | $ | 58,928

​

​

​

​

​

​

​

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

The following discussion is intended to assist in understanding our results of operations for the three and six months ended June 30, 2021 and 2020 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, 2020.

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. During 2017, we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas. As a result, 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 total operating revenues for the first six months of 2021 and 2020 were $119.9 million and $65.9 million, respectively. The increase in revenues in the most recent period is primarily attributable to an approximate $22.47 per Boe increase in average realized prices (excluding the effects of hedging arrangements). During the first six months of 2021, production averaged 14,956 Boe/d compared to average production of 16,527 Boe/d during the first six months of 2020. Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 600 Boe/d and 2,700 Boe/d in the first six months of 2021 and 2020, respectively. In February 2021, we temporarily shut-in production due to inclement weather. In May and June 2020, we temporarily shut-in production in response to historically low commodity prices. Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs. For the six months ended June 30, 2021, we drilled and cased 2.0 gross (2.0 net) operated wells, completed 6.0 gross (6.0 net) operated wells, and put online 6.0 gross (6.0 net) operated wells.

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, 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.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could result in impairment charges under our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. Using the crude oil price for July 2021 of $75.31 per barrel, and holding it constant for two months to create a trailing 12-month period of average prices that is more reflective of recent price trends, our ceiling test calculation would not have generated an impairment, holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Recent Developments

Risk and Uncertainties

We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of our business in a safe and secure manner. In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand. As a consequence, beginning in March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

​

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices to pre-pandemic levels. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. Furthermore, the health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions remain concerns and cannot be predicted, nor can the impact on our customers, vendors and contractors. Any material effect on these parties could adversely impact us. These and other factors could affect our operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years. The results presented in this Form 10-Q are not necessarily indicative of future operating results. For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020.

​

Senior Revolving Credit Facility

​

On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021. The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provides for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

​

Capital Resources and Liquidity

In March 2020, the World Health Organization declared the outbreak of COVID-19 a pandemic. In 2020, the COVID-19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically reduced demand for oil and natural gas at the same time that supply was maintained at high levels due to a price and market share war involving the OPEC/Saudi Arabia and Russia, all of which adversely impacted the prices we

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received for our production. As a consequence, beginning in March 2020, we realized lower revenue as a result of these commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

​

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand of oil and natural gas and increases in oil and natural gas prices to pre-pandemic levels. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. 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 U.S. or global financial system and markets and an economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus 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, adversely impacting our ability to comply with covenants in our Senior Credit Agreement or causing our lenders to further reduce the borrowing base under our Senior Credit 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, and borrowing capacity under, our Senior Credit Agreement.

​

We expect to spend approximately $40.0 million to $50.0 million on drilling, completion, support infrastructure and other capital costs during 2021. These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and, if needed, borrowings under our Senior Credit Agreement, which has a current borrowing base of $185.0 million and which is scheduled to be reduced to $175.0 million on September 1, 2021 pursuant to the Fourth Amendment to our Senior Credit Agreement, as discussed in greater detail above. Amounts borrowed under our Senior Credit Agreement will mature on October 8, 2024. At June 30, 2021, we had $163.0 million of indebtedness outstanding and approximately $1.9 million letters of credit outstanding under our Senior Credit Agreement, resulting in $20.1 million of borrowing capacity under the current $185.0 million borrowing base. The next redetermination is scheduled for the fall of 2021. If our borrowing base is further reduced upon a redetermination, our resulting liquidity could be insufficient to fund our business, operations and planned capital expenditures and the reduction could result in a borrowing base deficiency, which would require us to repay any amount outstanding in excess of the borrowing base.

As part of our ongoing efforts to manage our business and liquidity, we are in regular contact with our lenders regarding matters relating to the Senior Credit Agreement, and we closely monitor our compliance with the various covenants under our Senior Credit Agreement, which include certain financial covenants, such as maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00. As of June 30, 2021, after giving effect to the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment), we were in compliance with the financial covenants under the Senior Credit Agreement.

We have periodically, including as recently as October 2020, obtained waivers or amendments to the financial covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with them for a particular period of time. 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 Senior Credit Agreement. As a consequence, we endeavor to anticipate potential covenant compliance issues and work with the lenders under our Senior Credit Agreement to address any such issues ahead of time. For instance, depressed oil and natural gas prices during 2020 and

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our decision to temporarily shut-in a portion of our production in response to market conditions adversely impacted our cash flows, which, combined with cash requirements associated with capital-intensive oil and gas development projects undertaken in late 2019 and early 2020, led to challenges in our compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020. Thus, on July 31, 2020, we secured a waiver in which the lenders consented to waive maintenance of the Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020. In conjunction with the fall 2020 borrowing base redetermination process, and due to a decline in the value associated with our derivative contracts, we pursued additional relief from our lenders in regards to the Current Ratio. On October 29, 2020, in the Third Amendment, the lenders waived maintenance with the Current Ratio for the fiscal quarter ending September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

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Similarly, in prior years, we have also obtained waivers and amendments for other financial covenant violations. For instance, our strategic decision to transform into a pure-play, single basin company focused on the Delaware Basin in West Texas resulted in us divesting our producing properties located in other areas and acquiring primarily undeveloped acreage in the Delaware Basin. Our drilling activities once we acquired these assets required significant capital expenditure outlays to replenish production and related EBITDA from the divested producing properties. These and other factors adversely impacted our ability to comply with our debt covenants under the predecessor credit agreement by reducing our production, reserves and EBITDA on a current and a pro forma historical basis, while making us more susceptible to fluctuations in performance and compliance more challenging. In addition, we encountered certain operational difficulties that impacted our ability to comply at the time, including elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells and limited and expensive treatment and transportation options. Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.

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In short, historically, our lenders have provided us with the covenant relief we have sought to the extent it was necessary to manage through near-term business and operational challenges as we pursued our longer-term business objectives; however, there is no assurance that they will be amenable to providing any such relief in the future, should it become necessary. Further, there is some evidence that credit is becoming more challenging for oil and gas companies generally, and for us in particular, to secure. As noted previously, late last year, Bank of Montreal, the primary lender under our Senior Credit Agreement, announced that it was exiting its U.S. energy investment banking business, a service line that is generally complementary to commercial banking service offerings. Bank of Montreal’s election to exit that line of business may be an indication of sentiment overall with regards to the business and investment banking environment affecting the U.S. oil and gas industry in the near term.

More specifically as it regards us, in our recent redetermination, the lenders under our Senior Credit Agreement have reduced our borrowing base to $185.0 million effective on June 1, 2021 and $175.0 million effective on September 1, 2021, and we agreed to some other modifications of the terms and covenants contained in our Senior Credit Agreement at the request of our lenders in the Fourth Amendment, as discussed in greater detail above. While we anticipate that we will be able to operate our business and maintain adequate liquidity within the limitations imposed by our Senior Credit Agreement, as amended, the loss of additional liquidity may prevent us from accelerating our drilling plans in an effort to manage our liquidity more closely. Additionally, reduced access to bank borrowings limits our flexibility in responding to unforeseen adverse events as well as our ability to pursue opportunities that might prove beneficial in the future. As noted elsewhere herein and our other filings with the Securities and Exchange Commission, many factors, including many that are beyond our control, affect our business and operations and may adversely impact our cash flows, liquidity and our ability to comply with the covenants under our Senior Credit Agreement. Consequently, there is no assurance that our expectations with regard to our capital needs or compliance with the covenants in the Senior Credit Agreement will prove accurate. In the event we are unable to maintain compliance, the lenders under our Senior Credit Agreement may be unwilling to provide us with the covenant relief we need. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in securing alternative means of financing our business upon favorable terms or at all. If we are able to secure alternative financing, it may be more costly, provide less liquidity, or impose more restrictive covenants than our Senior Credit Agreement.

When commodity prices decline significantly, as they did in 2020, our ability to finance our capital budget and operations may be adversely impacted. We employ derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, however, the total volumes we typically hedge are less than our

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expected production, vary from period to period based on our view of current and future market conditions and generally extend up to only approximately 30 months. These limitations result in our liquidity being susceptible to commodity price declines in the near term and, in particular, if such prices decline for a sustained period of time. 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 under our hedges. Our Senior Credit Agreement contains minimum hedging requirements. Pursuant to the Third Amendment, we are required to hedge at least 65% of anticipated production from proved developed producing reserves through December 31, 2022. 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.

Our future capital resources and liquidity depend on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Cash is required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves, which is typical in the capital-intensive oil and natural gas industry. We strive to maintain financial flexibility while pursuing our drilling plans and may access capital markets, pursue joint ventures, sell assets and engage in other transactions as necessary to, among other things, maintain borrowing capacity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage. Our ability to complete such transactions and maintain or increase our borrowing base 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.

Cash Flow

During the six months ended June 30, 2021, operating cash flows and net borrowings under our Senior Credit Agreement funded our capital expenditures program. See “Results of Operations” for a review of the impact of prices and volumes on operating revenues.

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

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended
​ | ​ | June 30,
​ |  | 2021 | ​ | 2020
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows provided by (used in) operating activities | ​ | $ | 29,100 | ​ | $ | 43,104
Cash flows provided by (used in) investing activities | ​ | ​ | (36,669) | ​ | ​ | (90,155)
Cash flows provided by (used in) financing activities | ​ | ​ | 4,732 | ​ | ​ | 37,177
Net increase (decrease) in cash and cash equivalents | ​ | $ | (2,837) | ​ | $ | (9,874)

​

Operating Activities. Net cash flows provided by operating activities for the six months ended June 30, 2021 and 2020 were $29.1 million and $43.1 million, respectively.

Operating cash flows for the six months ended June 30, 2021 decreased from the six months ended June 30, 2020 due to realized losses from derivative contracts incurred in the six months ended June 30, 2021 as a result of increased commodity prices. In addition, realized gains from derivative contracts were higher in the six months ended June 30, 2020, as that period included the early termination of certain derivative contracts. During the six months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $16.3 million during the period. The decrease to current period operating cash flows was partially offset by our average realized price increase of approximately $22.47 per Boe which contributed to higher oil and natural gas revenues in 2021.

Operating cash flows for the six months ended June 30, 2020 increased from the six months ended June 30, 2019 due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in

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interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy. In addition, realized gains from derivative contracts were higher in the six months ended June 30, 2020, which included the early termination of certain derivative contracts. During the six months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $16.3 million during the period. These increases to operating cash flows in 2020 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes.

Investing Activities. Net cash flows used in investing activities for the six months ended June 30, 2021 and 2020 were approximately $36.7 million and $90.2 million, respectively.

During the six months ended June 30, 2021, we spent $37.6 million on oil and natural gas capital expenditures, of which $33.0 million related to drilling and completion costs and $3.1 million related to the development of our treating equipment and gathering support infrastructure. We received $0.9 million in proceeds from the sale of oil and natural gas properties.

During the six months ended June 30, 2020, we spent $91.2 million on oil and natural gas capital expenditures, of which $61.2 million related to drilling and completion costs and $29.0 million related to the development of our treating equipment and our gathering support infrastructure. We received $0.5 million in proceeds from the sale of oil and natural gas properties. In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.

Financing Activities. Net cash flows provided by financing activities for the six months ended June 30, 2021 and 2020 were approximately $4.7 million and $37.2 million, respectively.

During the six months ended June 30, 2021, net borrowings of $5.0 million under our Senior Credit Agreement were used to partially fund our drilling and completions program and the development of our treating equipment and gathering support facilities.

During the six months ended June 30, 2020, net borrowings of $35.0 million under our Senior Credit Agreement were used to fund our drilling and completions program and the development of our treating equipment and gathering support facilities. We also borrowed $2.2 million under the Paycheck Protection Plan Loan to fund payroll costs, rent and utilities.

Senior Revolving Credit Facility

On October 8, 2019, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders. The Senior Credit Agreement, as amended, provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $185.0 million. A portion of the Senior Credit Agreement, in the amount of $25.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. Redeterminations of the borrowing base occur semi-annually on May 1 and November 1, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 2.00% to 3.00% for ABR-based loans or at specified margins over LIBOR of 3.00% to 4.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement. These margins fluctuate based on our utilization of the facility.

We may elect, at our option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments that may be payable pursuant to the terms of the Senior Credit Agreement. We may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations. Amounts outstanding

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under the Senior Credit Agreement are guaranteed by our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of us and our subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00:1.00.

On October 29, 2020, we entered into the Third Amendment. The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020. The Third Amendment also reduced the amount available for the issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On May 10, 2021, we entered into the Fourth Amendment which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduces the borrowing base to $175.0 million effective September 1, 2021. The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provides for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

​

As of June 30, 2021, after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

Paycheck Protection Program Loan

On April 16, 2020, we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.

We may elect, at our option, to prepay 20% or less of the borrowings outstanding under the PPP Loan without premium or penalty, and without notice. Prepayments of more than 20% of the outstanding borrowings require written advanced notice and payment of accrued interest. The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control.

Under the terms of the CARES Act, we can apply for and be granted forgiveness for all or a portion of the PPP Loan. Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with

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the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels. We believe we are eligible for, and are pursuing, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act; however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

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, 2020.

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Results of Operations

​

Three Months Ended June 30, 2021 and 2020
​

We reported a net loss of $33.9 million and $127.3 million for the three months ended June 30, 2021 and 2020, respectively. The table included below sets forth financial information for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Three Months Ended | ​ | ​ | ​
​ | ​ | June 30, | ​ | ​ | ​
In thousands (except per unit and per Boe amounts) |  | 2021 | ​ | 2020 | ​ | Change
Net income (loss) | ​ | $ | (33,929) | ​ | $ | (127,316) | ​ | $ | 93,387
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | ​ | 51,935 | ​ | ​ | 15,758 | ​ | ​ | 36,177
Natural gas | ​ | ​ | 5,317 | ​ | ​ | 836 | ​ | ​ | 4,481
Natural gas liquids | ​ | ​ | 6,851 | ​ | ​ | 1,437 | ​ | ​ | 5,414
Other | ​ | ​ | 263 | ​ | ​ | 463 | ​ | ​ | (200)
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,169 | ​ | ​ | 10,300 | ​ | ​ | (131)
Workover and other | ​ | ​ | 767 | ​ | ​ | 539 | ​ | ​ | 228
Taxes other than income | ​ | ​ | 2,912 | ​ | ​ | 1,493 | ​ | ​ | 1,419
Gathering and other | ​ | ​ | 14,331 | ​ | ​ | 15,228 | ​ | ​ | (897)
Restructuring | ​ | ​ | — | ​ | ​ | 2,162 | ​ | ​ | (2,162)
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 3,546 | ​ | ​ | 4,484 | ​ | ​ | (938)
Stock-based compensation | ​ | ​ | 485 | ​ | ​ | 786 | ​ | ​ | (301)
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 11,015 | ​ | ​ | 14,005 | ​ | ​ | (2,990)
Depreciation – Other | ​ | ​ | 105 | ​ | ​ | 232 | ​ | ​ | (127)
Accretion expense | ​ | ​ | 129 | ​ | ​ | 145 | ​ | ​ | (16)
Full cost ceiling impairment | ​ | ​ | — | ​ | ​ | 60,107 | ​ | ​ | (60,107)
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | (53,089) | ​ | ​ | (34,761) | ​ | ​ | (18,328)
Interest expense and other | ​ | ​ | (1,747) | ​ | ​ | (1,568) | ​ | ​ | (179)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 805 | ​ | ​ | 775 | ​ | ​ | 30
Natural Gas - MMcf | ​ | ​ | 2,055 | ​ | ​ | 1,632 | ​ | ​ | 423
Natural gas liquids – MBbls | ​ | ​ | 270 | ​ | ​ | 251 | ​ | ​ | 19
Total MBoe(1) | ​ | ​ | 1,417 | ​ | ​ | 1,298 | ​ | ​ | 119
Average daily production – Boe/d(1) | ​ | ​ | 15,571 | ​ | ​ | 14,264 | ​ | ​ | 1,307
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 64.52 | ​ | $ | 20.33 | ​ | $ | 44.19
Natural gas price - Mcf | ​ | ​ | 2.59 | ​ | ​ | 0.51 | ​ | ​ | 2.08
Natural gas liquids price - Bbl | ​ | ​ | 25.37 | ​ | ​ | 5.73 | ​ | ​ | 19.64
Total per Boe(1) | ​ | ​ | 45.24 | ​ | ​ | 13.89 | ​ | ​ | 31.35
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 7.18 | ​ | $ | 7.94 | ​ | $ | (0.76)
Workover and other | ​ | ​ | 0.54 | ​ | ​ | 0.42 | ​ | ​ | 0.12
Taxes other than income | ​ | ​ | 2.06 | ​ | ​ | 1.15 | ​ | ​ | 0.91
Gathering and other | ​ | ​ | 10.11 | ​ | ​ | 11.73 | ​ | ​ | (1.62)
Restructuring | ​ | ​ | — | ​ | ​ | 1.67 | ​ | ​ | (1.67)
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.50 | ​ | ​ | 3.45 | ​ | ​ | (0.95)
Stock-based compensation | ​ | ​ | 0.34 | ​ | ​ | 0.61 | ​ | ​ | (0.27)
Depletion | ​ | ​ | 7.77 | ​ | ​ | 10.79 | ​ | ​ | (3.02)

(1) | Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.

(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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Oil, natural gas and natural gas liquids revenues were $64.1 million and $18.0 million for the three months ended June 30, 2021 and 2020, respectively. The increase in revenues in the most recent period is primarily attributable to an approximate $31.35 per Boe increase in our average realized prices (excluding the effects of hedging arrangements). 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. For the three months ended June 30, 2021 and 2020, production averaged 15,571 Boe/d and 14,264 Boe/d, respectively. Our average daily production increased in the three months ended June 30, 2021 when compared to the same period in the prior year due to new production brought online as a result of our 2021 capital program as well as production from wells brought back online that were shut-in during May and June 2020 when historically low commodity prices occurred, which was partially offset by third-party processing curtailments and facility upgrades and repairs in the current year period.

Lease operating expenses were $10.2 million and $10.3 million for the three months ended June 30, 2021 and 2020, respectively. On a per unit basis, lease operating expenses were $7.18 per Boe and $7.94 per Boe for the three months ended June 30, 2021 and 2020, respectively. The decrease in lease operating expenses in 2021 results from operational efficiencies decreasing our per unit costs.

Workover and other expenses were $0.8 million and $0.5 million for the three months ended June 30, 2021 and 2020, respectively. On a per unit basis, workover and other expenses were $0.54 per Boe and $0.42 per Boe for the three months ended June 30, 2021 and 2020, respectively. The increased workover and other expenses in 2021 relate to more significant workover projects undertaken in the current year.

Taxes other than income were $2.9 million and $1.5 million for the three months ended June 30, 2021 and 2020, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.06 per Boe and $1.15 per Boe for the three months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses were $14.3 million and $15.2 million for the three months ended June 30, 2021 and 2020, 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. Approximately $4.6 million and $2.3 million for the three months ended June 30, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $9.7 million and $9.5 million for the three months ended June 30, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The increase in treating equipment and gathering support facilities expenses in 2021 results from higher chemical costs to improve the quality of treated oil, which were partially offset by lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period. Also included are $3.4 million of rig stacking charges for the three months ended June 30, 2020.

Restructuring expense was approximately $2.2 million for the three months ended June 30, 2020. During the three months ended June 30, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs. In May 2020, in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.

General and administrative expense was $3.5 million and $4.5 million for the three months ended June 30, 2021 and 2020, respectively. The reduction in general and administrative expense in the current period is associated with a decrease in professional fees and information technology costs incurred when compared to the prior year. On a per unit basis, general and administrative expenses were $2.50 per Boe and $3.45 per Boe for the three months ended June 30, 2021 and 2020, respectively.

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

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period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $11.0 million and $14.0 million for the three months ended June 30, 2021 and 2020, respectively. On a per unit basis, depletion expense was $7.77 per Boe and $10.79 per Boe for the three months ended June 30, 2021 and 2020, respectively. The lower depletion rate in the 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. At June 30, 2020, we recorded a full cost ceiling impairment of $60.1 million. The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020 to $47.37 per barrel at June 30, 2020. This average price decline was partially offset by favorable differentials and lower operating expenses.
​

We enter into derivative commodity instruments to hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids 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. At June 30, 2021, we had a $1.8 million derivative asset, $1.3 million of which was classified as current, and we had a $86.6 million derivative liability, $71.4 million of which was classified as current. We recorded a net derivative loss of $53.1 million ($34.8 million net unrealized loss and $18.3 million net realized loss on settled and early terminated contracts) for the three months ended June 30, 2021. For the three months ended June 30, 2020, we recorded a net derivative loss of $34.8 million ($67.2 million net unrealized loss and $32.4 million net realized gain on settled and early terminated contracts). During the three months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received proceeds of approximately $16.4 million, which were included in the $32.4 million net realized gains for the period.

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Six Months Ended June 30, 2021 and 2020
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We reported a net loss of $67.3 million and $12.8 million for the six months ended June 30, 2021 and 2020, respectively. The table included below sets forth financial information for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Six Months Ended | ​ | ​ | ​
​ | ​ | June 30, | ​ | ​ | ​
In thousands (except per unit and per Boe amounts) | ​ | 2021 | ​ | 2020 | ​ | Change
Net income (loss) | ​ | $ | (67,304) | ​ | $ | (12,825) | ​ | $ | (54,479)
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | ​ | 93,205 | ​ | ​ | 57,675 | ​ | ​ | 35,530
Natural gas | ​ | ​ | 14,404 | ​ | ​ | 1,190 | ​ | ​ | 13,214
Natural gas liquids | ​ | ​ | 11,760 | ​ | ​ | 6,190 | ​ | ​ | 5,570
Other | ​ | ​ | 515 | ​ | ​ | 838 | ​ | ​ | (323)
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 19,636 | ​ | ​ | 22,789 | ​ | ​ | (3,153)
Workover and other | ​ | ​ | 1,327 | ​ | ​ | 1,862 | ​ | ​ | (535)
Taxes other than income | ​ | ​ | 6,104 | ​ | ​ | 4,408 | ​ | ​ | 1,696
Gathering and other | ​ | ​ | 27,502 | ​ | ​ | 25,775 | ​ | ​ | 1,727
Restructuring | ​ | ​ | — | ​ | ​ | 2,580 | ​ | ​ | (2,580)
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 7,779 | ​ | ​ | 7,953 | ​ | ​ | (174)
Stock-based compensation | ​ | ​ | 1,079 | ​ | ​ | 1,173 | ​ | ​ | (94)
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 21,356 | ​ | ​ | 31,605 | ​ | ​ | (10,249)
Depreciation – Other | ​ | ​ | 231 | ​ | ​ | 513 | ​ | ​ | (282)
Accretion expense | ​ | ​ | 257 | ​ | ​ | 294 | ​ | ​ | (37)
Full cost ceiling impairment | ​ | ​ | — | ​ | ​ | 60,107 | ​ | ​ | (60,107)
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | (98,800) | ​ | ​ | 83,538 | ​ | ​ | (182,338)
Interest expense and other | ​ | ​ | (3,117) | ​ | ​ | (3,197) | ​ | ​ | 80
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 1,524 | ​ | ​ | 1,712 | ​ | ​ | (188)
Natural Gas - MMcf | ​ | ​ | 4,188 | ​ | ​ | 4,171 | ​ | ​ | 17
Natural gas liquids – MBbls | ​ | ​ | 485 | ​ | ​ | 601 | ​ | ​ | (116)
Total MBoe(1) | ​ | ​ | 2,707 | ​ | ​ | 3,008 | ​ | ​ | (301)
Average daily production – Boe(1) | ​ | ​ | 14,956 | ​ | ​ | 16,527 | ​ | ​ | (1,571)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 61.16 | ​ | $ | 33.69 | ​ | $ | 27.47
Natural gas price - Mcf | ​ | ​ | 3.44 | ​ | ​ | 0.29 | ​ | ​ | 3.15
Natural gas liquids price - Bbl | ​ | ​ | 24.25 | ​ | ​ | 10.30 | ​ | ​ | 13.95
Total per Boe(1) | ​ | ​ | 44.10 | ​ | ​ | 21.63 | ​ | ​ | 22.47
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 7.25 | ​ | $ | 7.58 | ​ | $ | (0.33)
Workover and other | ​ | ​ | 0.49 | ​ | ​ | 0.62 | ​ | ​ | (0.13)
Taxes other than income | ​ | ​ | 2.25 | ​ | ​ | 1.47 | ​ | ​ | 0.78
Gathering and other | ​ | ​ | 10.16 | ​ | ​ | 8.57 | ​ | ​ | 1.59
Restructuring | ​ | ​ | — | ​ | ​ | 0.86 | ​ | ​ | (0.86)
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.87 | ​ | ​ | 2.64 | ​ | ​ | 0.23
Stock-based compensation | ​ | ​ | 0.40 | ​ | ​ | 0.39 | ​ | ​ | 0.01
Depletion | ​ | ​ | 7.89 | ​ | ​ | 10.51 | ​ | ​ | (2.62)

(1) | Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil. This ratio is based on energy equivalency, not price equivalency. The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.

(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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Oil, natural gas and natural gas liquids revenues were $119.4 million and $65.1 million for the six months ended June 30, 2021 and 2020, respectively. The increase in revenues in the most recent period is primarily attributable to an approximate $22.47 per Boe increase in our average realized prices (excluding the effects of hedging arrangements). 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. For the six months ended June 30, 2021 and 2020, production averaged 14,956 Boe/d and 16,527 Boe/d, respectively. Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 600 Boe/d and 2,700 Boe/d in the first six months of 2021 and 2020, respectively. In February 2021, we temporarily shut-in production due to inclement weather. In May and June 2020, we temporarily shut-in production in response to historically low commodity prices. Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

Lease operating expenses were $19.6 million and $22.8 million for the six months ended June 30, 2021 and 2020, respectively. On a per unit basis, lease operating expenses were $7.25 per Boe and $7.58 per Boe for the six months ended June 30, 2021 and 2020, respectively. The decrease in lease operating expenses in 2021 results from decreased salt water disposal costs due to lower production volumes and less produced water.

Workover and other expenses were $1.3 million and $1.9 million for the six months ended June 30, 2021 and 2020, respectively. On a per unit basis, workover and other expenses were $0.49 per Boe and $0.62 per Boe for the six months ended June 30, 2021 and 2020, respectively. The decreased workover and other expenses in 2021 relate to preventive operational measures previously undertaken to mitigate potential future failures in producing wells, continued improvements in well and completion designs, and cost reductions for materials and services. This decrease is partially offset by more significant workover projects undertaken in the second quarter of 2021.

Taxes other than income were $6.1 million and $4.4 million for the six months ended June 30, 2021 and 2020, respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.25 per Boe and $1.47 per Boe for the six months ended June 30, 2021 and 2020, respectively.

Gathering and other expenses were $27.5 million and $25.8 million for the six months ended June 30, 2021 and 2020, 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. Approximately $8.6 million and $5.2 million for the six months ended June 30, 2021 and 2020, respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Gathering and marketing fees increased in 2021 as we marketed higher quantities of sour gas production to third parties in the current year period. Approximately $18.9 million and $17.2 million for the six months ended June 30, 2021 and 2020, respectively, relate to operating expenses on our treating equipment and gathering support facilities. The increase in treating equipment and gathering support facilities expenses in 2021 results from higher electricity and buy back fuel costs incurred as a result of inclement weather in February 2021 and higher chemical costs to improve the quality of treated oil, which were partially offset by lower operating expenses associated with our treating equipment, as fewer sour gas production volumes were processed through our hydrogen sulfide treating plant in the current year period. Also included are $3.4 million of rig stacking charges for the six months ended June 30, 2020.

Restructuring expense was approximately $2.6 million for the six months ended June 30, 2020. During the six months ended June 30, 2020, we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and go forward costs. In May 2020, in furtherance of the consolidation into one corporate office, we exercised a one-time early termination option under the lease agreement for our office space in Denver, Colorado.

General and administrative expense was $7.8 million and $8.0 million for the six months ended June 30, 2021 and 2020, respectively. The reduction in general and administrative expense in the current year period is associated with a decrease in professional fees and information technology costs. These reductions were partial offset by an increase in payroll costs, as the 2020 period included a $1.6 million deduction to general and administrative expenses related to discretionary cash incentives. In late March 2020, due to changes in market conditions and decreased commodity prices,

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we determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $1.6 million reduction to general and administrative expense in the 2020 period. On a per unit basis, general and administrative expenses were $2.87 per Boe and $2.64 per Boe for the six months ended June 30, 2021 and 2020, respectively. The increase in general and administrative expenses on a per unit basis is attributed to the reduction in produced volumes between the periods.

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 $21.4 million and $31.6 million for the six months ended June 30, 2021 and 2020, respectively. On a per unit basis, depletion expense was $7.89 per Boe and $10.51 per Boe for the six months ended June 30, 2021 and 2020, respectively. The lower depletion rate in 2021 is attributable to the change in our depletable base as a result of full cost ceiling test impairments incurred in 2020.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. At June 30, 2020, we recorded a full cost ceiling impairment of $60.1 million. The ceiling test impairment was primarily driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation, from $55.96 per barrel at March 31, 2020 to $47.37 per barrel at June 30, 2020. This average price decline was partially offset by favorable differentials and lower operating expenses.

​

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids 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. At June 30, 2021, we had a $1.8 million derivative asset, $1.3 million of which was classified as current, and we had a $86.6 million derivative liability, $71.4 million of which was classified as current. We recorded a net derivative loss of $98.8 million ($70.9 million net unrealized loss and $27.9 million net realized loss on settled and early terminated contracts) for the six months ended June 30, 2021. For the six months ended June 30, 2020, we recorded a net derivative gain of $83.5 million ($45.2 million net unrealized gain and $38.3 million net realized gain on settled and early terminated contracts). During the six months ended June 30, 2020, we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $16.3 million, which were included in the $38.3 million net realized gains for the period.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, “Financial Statement Presentation.”

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, natural gas, and natural gas liquids prices decline significantly, 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, natural gas and natural gas liquids 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, generally our objective is to hedge approximately 65% to 85% of our anticipated production for up to the next 30 months, when derivative contracts are available upon terms and prices acceptable to us and in a manner

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consistent with at least the minimum requirements that may be in effect from time to time under our Senior Credit Agreement. Our hedge policies and objectives may change significantly as our operational profile and contractual obligations changes. 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, 2021, we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 8, “Derivative and Hedging Activities,” for more details.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are 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 and cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 7, “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 LIBOR and ABR 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, 2021, the principal amount of our debt was $165.2 million, of which approximately 1.3% bears interest at a weighted average fixed interest rate of 1.0% per year. The remaining 98.7% of our total debt at June 30, 2021 bears interest at floating and variable interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At June 30, 2021, the weighted average interest rate on our variable rate debt was 4.04% per year. If the balance of our variable interest rate at June 30, 2021 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.7 million per year.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief 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, 2021. On the basis of this review, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC 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 Chief 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 three months ended June 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 10, “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, 2020.

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

The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Total Number of Shares Purchased(1) | ​ | Average Price Paid Per Share | ​ | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | ​ | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 2021 | 185 | ​ | $ | 11.93 | ​ | — | ​ | —
May 2021 | — | ​ | ​ | — | ​ | — | ​ | —
June 2021 | 185 | ​ | ​ | 12.70 | ​ | — | ​ | —

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(1) | All of the shares were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock units. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock.

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

The Company has extended R. Kevin Andrews’s, Chief Financial Officer, employment agreement to January 28, 2022 to align his agreement term with the terms of the Chief Executive Officer and Chief Operating Officer.

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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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3.1 |  | Amended and Restated Certificate of Incorporation of Battalion Oil Corporation (formerly Halcón Resources 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).
10.1 | ​ | Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, by and among Battalion Oil Corporation (formerly Halcón Resources Corporation), as borrower, Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 8, 2019).
10.1.1 | ​ | First Amendment to the Senior Secured Revolving Credit Agreement, dated as of November 21, 2019, by and among Battalion Oil Corporation (formerly Halcón Resources Corporation), as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 27, 2019).
10.1.2 | ​ | Second Amendment to the Senior Secured Revolving Credit Agreement and Limited Consent, dated as of April 30, 2020, by and among Battalion Oil Corporation, as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 6, 2020).
10.1.3 | ​ | Third Amendment to the Senior Secured Revolving Credit Agreement and Limited Waiver, dated as of October 29, 2020, by and among Battalion Oil Corporation, as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 2, 2020).
10.1.4 | ​ | Fourth Amendment to the Senior Secured Revolving Credit Agreement dated as of May 10, 2021, by and among Battalion Oil Corporation, as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1.4 of our Quarterly Report on Form 10-Q filed May 17, 2021).
10.8† | ​ | Employment Agreement between R. Kevin Andrews and Battalion Oil Corporation effective as of August 17, 2020 (Incorporated by reference to Exhibit 10.12 of our Quarterly Report on Form 10-Q filed November 9, 2020).
10.8.1*† | ​ | First Amendment to Employment Agreement between R. Kevin Andrews and Battalion Oil Corporation effective as of August 7, 2021.
31.1* | ​ | Sarbanes-Oxley Section 302 certification of Principal Executive Officer
31.2* | ​ | Sarbanes-Oxley Section 302 certification of 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 9, 2021 | By: | /s/ RICHARD H. LITTLE
​ | ​ | Name: | Richard H. Little
​ | ​ | Title: | Chief Executive Officer
​ | ​ | ​
​ | ​ | ​
August 9, 2021 | By: | /s/ R. KEVIN ANDREWS
​ | ​ | Name: | R. Kevin Andrews
​ | ​ | Title: | Executive Vice President, Chief Financial Officer and Treasurer

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