10-Q 1 batl-20200930x10q.htm 10-Q

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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 September 30, 2020
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 Corporation

(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 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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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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At November 6, 2020, 16,203,967 shares of the Registrant’s Common Stock were outstanding.

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TABLE OF CONTENTS

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PART I | ​ | FINANCIAL INFORMATION | ​ | ​
ITEM 1. | ​ | Condensed Consolidated Financial Statements (Unaudited) | ​ | 5
​ | ​ | Condensed Consolidated Statements of Operations (Unaudited) for the Three Months and Nine Months Ended September 30, 2020 and 2019 | ​ | 5
​ | ​ | Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2020 and December 31, 2019 | ​ | 6
​ | ​ | Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) for the Three and Nine Months Ended September 30, 2020 and the Year Ended December 31, 2019 | ​ | 7
​ | ​ | Condensed Consolidated Statement of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2020 and 2019 | ​ | 9
ITEM 2. | ​ | Management’s Discussion and Analysis of Financial Condition and Results of Operations | ​ | 39
ITEM 3. | ​ | Quantitative and Qualitative Disclosures about Market Risk | ​ | 56
ITEM 4. | ​ | Controls and Procedures | ​ | 56
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PART II | ​ | OTHER INFORMATION | ​ | ​
ITEM 1. | ​ | Legal Proceedings | ​ | 57
ITEM 1A. | ​ | Risk Factors | ​ | 57
ITEM 2. | ​ | Unregistered Sales of Equity Securities and Use of Proceeds | ​ | 58
ITEM 3. | ​ | Defaults Upon Senior Securities | ​ | 58
ITEM 4. | ​ | Mine Safety Disclosures | ​ | 58
ITEM 5. | ​ | Other Information | ​ | 58
ITEM 6. | ​ | Exhibits | ​ | 59
Signatures | ​ | ​ | ​ | 60
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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, concerning, 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, are forward-looking statements. These forward-looking statements are 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 these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2019, 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, including, but not limited to, the following factors:

| ● | volatility in commodity prices for oil, natural gas and natural gas liquids;

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

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

| ● | 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;

| ● | we have historically had substantial indebtedness and we may incur more debt 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;

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| ● | 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 the 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;

| ● | 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

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Item 1. Condensed Consolidated Financial Statements (Unaudited)

BATTALION OIL CORPORATION

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Three Months | ​ | ​ | Three Months | ​ | Nine Months | ​ | ​ | Nine Months
​ | ​ | Ended | ​ | ​ | Ended | ​ | Ended | ​ | ​ | Ended
​ | ​ | September 30, 2020 | ​ | ​ | September 30, 2019 | ​ | September 30, 2020 | ​ | ​ | September 30, 2019
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 33,638 | ​ | ​ | $ | 46,275 | ​ | $ | 91,313 | ​ | ​ | $ | 145,024
Natural gas | ​ | ​ | 1,912 | ​ | ​ | ​ | 301 | ​ | ​ | 3,102 | ​ | ​ | ​ | 107
Natural gas liquids | ​ | ​ | 3,896 | ​ | ​ | ​ | 3,987 | ​ | ​ | 10,086 | ​ | ​ | ​ | 13,229
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 39,446 | ​ | ​ | ​ | 50,563 | ​ | ​ | 104,501 | ​ | ​ | ​ | 158,360
Other | ​ | ​ | 384 | ​ | ​ | ​ | 246 | ​ | ​ | 1,222 | ​ | ​ | ​ | 743
Total operating revenues | ​ | ​ | 39,830 | ​ | ​ | ​ | 50,809 | ​ | ​ | 105,723 | ​ | ​ | ​ | 159,103
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,091 | ​ | ​ | ​ | 11,958 | ​ | ​ | 32,880 | ​ | ​ | ​ | 39,617
Workover and other | ​ | ​ | 905 | ​ | ​ | ​ | 1,566 | ​ | ​ | 2,767 | ​ | ​ | ​ | 5,580
Taxes other than income | ​ | ​ | 2,722 | ​ | ​ | ​ | 3,012 | ​ | ​ | 7,130 | ​ | ​ | ​ | 9,213
Gathering and other | ​ | ​ | 13,500 | ​ | ​ | ​ | 10,147 | ​ | ​ | 39,275 | ​ | ​ | ​ | 36,057
Restructuring | ​ | ​ | — | ​ | ​ | ​ | 3,223 | ​ | ​ | 2,580 | ​ | ​ | ​ | 15,148
General and administrative | ​ | ​ | 4,111 | ​ | ​ | ​ | 19,423 | ​ | ​ | 13,237 | ​ | ​ | ​ | 36,550
Depletion, depreciation and accretion | ​ | ​ | 15,755 | ​ | ​ | ​ | 20,512 | ​ | ​ | 48,167 | ​ | ​ | ​ | 90,912
Full cost ceiling impairment | ​ | ​ | 128,336 | ​ | ​ | ​ | 45,568 | ​ | ​ | 188,443 | ​ | ​ | ​ | 985,190
(Gain) loss on sale of Water Assets | ​ | ​ | — | ​ | ​ | ​ | (164) | ​ | ​ | — | ​ | ​ | ​ | 3,618
Total operating expenses | ​ | ​ | 175,420 | ​ | ​ | ​ | 115,245 | ​ | ​ | 334,479 | ​ | ​ | ​ | 1,221,885
Income (loss) from operations | ​ | ​ | (135,590) | ​ | ​ | ​ | (64,436) | ​ | ​ | (228,756) | ​ | ​ | ​ | (1,062,782)
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Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | (15,843) | ​ | ​ | ​ | 13,457 | ​ | ​ | 67,695 | ​ | ​ | ​ | (34,332)
Interest expense and other | ​ | ​ | (1,692) | ​ | ​ | ​ | (10,547) | ​ | ​ | (4,889) | ​ | ​ | ​ | (37,606)
Reorganization items, net | ​ | ​ | — | ​ | ​ | ​ | (1,758) | ​ | ​ | — | ​ | ​ | ​ | (1,758)
Total other income (expenses) | ​ | ​ | (17,535) | ​ | ​ | ​ | 1,152 | ​ | ​ | 62,806 | ​ | ​ | ​ | (73,696)
Income (loss) before income taxes | ​ | ​ | (153,125) | ​ | ​ | ​ | (63,284) | ​ | ​ | (165,950) | ​ | ​ | ​ | (1,136,478)
Income tax benefit (provision) | ​ | ​ | — | ​ | ​ | ​ | — | ​ | ​ | — | ​ | ​ | ​ | 95,791
Net income (loss) | ​ | $ | (153,125) | ​ | ​ | $ | (63,284) | ​ | $ | (165,950) | ​ | ​ | $ | (1,040,687)
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Net income (loss) per share of common stock: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | $ | (9.45) | ​ | ​ | $ | (0.40) | ​ | $ | (10.24) | ​ | ​ | $ | (6.55)
Diluted | ​ | $ | (9.45) | ​ | ​ | $ | (0.40) | ​ | $ | (10.24) | ​ | ​ | $ | (6.55)
Weighted average common shares outstanding: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Basic | ​ | ​ | 16,204 | ​ | ​ | ​ | 159,143 | ​ | ​ | 16,204 | ​ | ​ | ​ | 158,916
Diluted | ​ | ​ | 16,204 | ​ | ​ | ​ | 159,143 | ​ | ​ | 16,204 | ​ | ​ | ​ | 158,916

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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)

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​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ | ​ | September 30, 2020 | ​ | December 31, 2019
Current assets: | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 1,827 | ​ | $ | 5,701
Accounts receivable, net | ​ | ​ | 26,053 | ​ | ​ | 48,504
Assets from derivative contracts | ​ | ​ | 18,996 | ​ | ​ | 4,995
Restricted cash | ​ | ​ | — | ​ | ​ | 4,574
Prepaids and other | ​ | ​ | 2,326 | ​ | ​ | 7,379
Total current assets | ​ | ​ | 49,202 | ​ | ​ | 71,153
Oil and natural gas properties (full cost method): | ​ | ​ | ​ | ​ | ​ | ​
Evaluated | ​ | ​ | 520,453 | ​ | ​ | 420,609
Unevaluated | ​ | ​ | 80,540 | ​ | ​ | 105,009
Gross oil and natural gas properties | ​ | ​ | 600,993 | ​ | ​ | 525,618
Less - accumulated depletion | ​ | ​ | (254,849) | ​ | ​ | (19,474)
Net oil and natural gas properties | ​ | ​ | 346,144 | ​ | ​ | 506,144
Other operating property and equipment: | ​ | ​ | ​ | ​ | ​ | ​
Other operating property and equipment | ​ | ​ | 3,490 | ​ | ​ | 3,655
Less - accumulated depreciation | ​ | ​ | (1,020) | ​ | ​ | (378)
Net other operating property and equipment | ​ | ​ | 2,470 | ​ | ​ | 3,277
Other noncurrent assets: | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | ​ | 9,675 | ​ | ​ | 224
Operating lease right of use assets | ​ | ​ | 424 | ​ | ​ | 3,165
Other assets | ​ | ​ | 5,178 | ​ | ​ | 703
Total assets | ​ | $ | 413,093 | ​ | $ | 584,666
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Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable and accrued liabilities | ​ | $ | 56,130 | ​ | $ | 97,333
Liabilities from derivative contracts | ​ | ​ | 9,055 | ​ | ​ | 8,069
Current portion of long-term debt | ​ | ​ | 1,401 | ​ | ​ | —
Operating lease liabilities | ​ | ​ | 657 | ​ | ​ | 923
Asset retirement obligations | ​ | ​ | — | ​ | ​ | 109
Total current liabilities | ​ | ​ | 67,243 | ​ | ​ | 106,434
Long-term debt, net | ​ | ​ | 178,808 | ​ | ​ | 144,000
Other noncurrent liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | ​ | 3,292 | ​ | ​ | 4,854
Asset retirement obligations | ​ | ​ | 10,960 | ​ | ​ | 10,481
Operating lease liabilities | ​ | ​ | — | ​ | ​ | 2,247
Commitments and contingencies (Note 12) | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity: | ​ | ​ | ​ | ​ | ​ | ​
Common stock: 100,000,000 shares of $0.0001 par value authorized; | ​ | ​ | ​ | ​ | ​ | ​
16,203,967 and 16,203,940 shares issued and outstanding as of | ​ | ​ | ​ | ​ | ​ | ​
September 30, 2020 and December 31, 2019, respectively | ​ | ​ | 2 | ​ | ​ | 2
Additional paid-in capital | ​ | ​ | 329,198 | ​ | ​ | 327,108
Retained earnings (accumulated deficit) | ​ | ​ | (176,410) | ​ | ​ | (10,460)
Total stockholders' equity | ​ | ​ | 152,790 | ​ | ​ | 316,650
Total liabilities and stockholders' equity | ​ | $ | 413,093 | ​ | $ | 584,666

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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)

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Retained | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Additional | ​ | Earnings | ​ | ​ | ​
​ | ​ | Common Stock | ​ | Paid-In | ​ | (Accumulated | ​ | Stockholders'
​ |  | Shares |  | Amount |  | Capital |  | Deficit) |  | Equity
Balances at December 31, 2019 (Successor) | ​ | 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 (Successor) | ​ | 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 (Successor) | ​ | 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 (Successor) | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 329,198 | ​ | $ | (176,410) | ​ | $ | 152,790

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

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BATTALION OIL CORPORATION

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Unaudited)

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(In thousands)

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Retained | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | Additional | ​ | Earnings | ​ | ​ | ​
​ | ​ | Common Stock | ​ | Paid-In | ​ | (Accumulated | ​ | Stockholders'
​ |  | Shares |  | Amount |  | Capital |  | Deficit) |  | Equity
Balances at December 31, 2018 (Predecessor) | ​ | 160,613 | ​ | $ | 16 | ​ | $ | 1,095,367 | ​ | $ | 101,661 | ​ | $ | 1,197,044
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (336,559) | ​ | ​ | (336,559)
Long-term incentive plan grants | ​ | 4,153 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Long-term incentive plan forfeitures | ​ | (193) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reduction in shares to cover individuals' tax withholding | ​ | (253) | ​ | ​ | — | ​ | ​ | (406) | ​ | ​ | — | ​ | ​ | (406)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | (6,416) | ​ | ​ | — | ​ | ​ | (6,416)
Balances at March 31, 2019 (Predecessor) | ​ | 164,320 | ​ | ​ | 16 | ​ | ​ | 1,088,545 | ​ | ​ | (234,898) | ​ | ​ | 853,663
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (640,844) | ​ | ​ | (640,844)
Long-term incentive plan grants | ​ | 11 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Long-term incentive plan forfeitures | ​ | (166) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reduction in shares to cover individuals' tax withholding | ​ | (42) | ​ | ​ | — | ​ | ​ | (20) | ​ | ​ | — | ​ | ​ | (20)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | 1,358 | ​ | ​ | — | ​ | ​ | 1,358
Balances at June 30, 2019 (Predecessor) | ​ | 164,123 | ​ | ​ | 16 | ​ | ​ | 1,089,883 | ​ | ​ | (875,742) | ​ | ​ | 214,157
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (63,284) | ​ | ​ | (63,284)
Long-term incentive plan forfeitures | ​ | (1,742) | ​ | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | —
Reduction in shares to cover individuals' tax withholding | ​ | (164) | ​ | ​ | — | ​ | ​ | (14) | ​ | ​ | — | ​ | ​ | (14)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | (2,428) | ​ | ​ | — | ​ | ​ | (2,428)
Balances at September 30, 2019 (Predecessor) | ​ | 162,217 | ​ | ​ | 16 | ​ | ​ | 1,087,441 | ​ | ​ | (939,026) | ​ | ​ | 148,431
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (115,366) | ​ | ​ | (115,366)
Reduction in shares to cover individuals' tax withholding | ​ | (715) | ​ | ​ | — | ​ | ​ | (54) | ​ | ​ | — | ​ | ​ | (54)
Stock-based compensation | ​ | — | ​ | ​ | — | ​ | ​ | (2,534) | ​ | ​ | — | ​ | ​ | (2,534)
Balances at October 1, 2019 (Predecessor) | ​ | 161,502 | ​ | ​ | 16 | ​ | ​ | 1,084,853 | ​ | ​ | (1,054,392) | ​ | ​ | 30,477
Cancellation of Predecessor equity | ​ | (161,502) | ​ | ​ | (16) | ​ | ​ | (1,084,853) | ​ | ​ | 1,054,392 | ​ | ​ | (30,477)
Balances at October 1, 2019 (Predecessor) | ​ | — | ​ | $ | — | ​ | $ | — | ​ | $ | — | ​ | $ | —
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Issuance of Successor common stock | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 322,294 | ​ | $ | — | ​ | $ | 322,296
Issuance of Successor warrants | ​ | — | ​ | ​ | — | ​ | ​ | 7,336 | ​ | ​ | — | ​ | ​ | 7,336
Equity issuance costs | ​ | — | ​ | ​ | — | ​ | ​ | (2,503) | ​ | ​ | — | ​ | ​ | (2,503)
Balances at October 1, 2019 (Successor) | ​ | 16,204 | ​ | ​ | 2 | ​ | ​ | 327,127 | ​ | ​ | — | ​ | ​ | 327,129
Net income (loss) | ​ | — | ​ | ​ | — | ​ | ​ | — | ​ | ​ | (10,460) | ​ | ​ | (10,460)
Equity issuance costs | ​ | — | ​ | ​ | — | ​ | ​ | (19) | ​ | ​ | — | ​ | ​ | (19)
Balances at December 31, 2019 (Successor) | ​ | 16,204 | ​ | $ | 2 | ​ | $ | 327,108 | ​ | $ | (10,460) | ​ | $ | 316,650

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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)

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | Successor | ​ | ​ | Predecessor
​ | Nine Months | ​ | ​ | Nine Months
​ | Ended | ​ | ​ | Ended
​ | September 30, 2020 |  |  | September 30, 2019
Cash flows from operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (165,950) | ​ | ​ | $ | (1,040,687)
Adjustments to reconcile net income (loss) to net cash | ​ | ​ | ​ | ​ | ​ | ​ | ​
provided by (used in) operating activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion, depreciation and accretion | ​ | ​ | 48,167 | ​ | ​ | ​ | 90,912
Full cost ceiling impairment | ​ | ​ | 188,443 | ​ | ​ | ​ | 985,190
(Gain) loss on sale of Water Assets | ​ | ​ | — | ​ | ​ | ​ | 3,618
Deferred income tax provision (benefit) | ​ | ​ | — | ​ | ​ | ​ | (95,791)
Stock-based compensation, net | ​ | ​ | 1,793 | ​ | ​ | ​ | (8,035)
Unrealized loss (gain) on derivative contracts | ​ | ​ | (24,029) | ​ | ​ | ​ | 45,834
Amortization and write-off of deferred loan costs | ​ | ​ | — | ​ | ​ | ​ | 1,859
Amortization of discount and premium | ​ | ​ | — | ​ | ​ | ​ | 134
Reorganization items, net | ​ | ​ | (6,440) | ​ | ​ | ​ | (283)
Accrued settlements on derivative contracts | ​ | ​ | 474 | ​ | ​ | ​ | 168
Other income (expense) | ​ | ​ | 280 | ​ | ​ | ​ | 367
Change in assets and liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts receivable | ​ | ​ | 16,270 | ​ | ​ | ​ | 3,781
Prepaids and other | ​ | ​ | 5,053 | ​ | ​ | ​ | (9,854)
Accounts payable and accrued liabilities | ​ | ​ | (16,183) | ​ | ​ | ​ | (10,446)
Net cash provided by (used in) operating activities | ​ | ​ | 47,878 | ​ | ​ | ​ | (33,233)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from investing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil and natural gas capital expenditures | ​ | ​ | (96,483) | ​ | ​ | ​ | (167,235)
Proceeds received from sale of oil and natural gas properties | ​ | ​ | 3,500 | ​ | ​ | ​ | 1,247
Acquisition of oil and natural gas properties | ​ | ​ | — | ​ | ​ | ​ | (2,809)
Other operating property and equipment capital expenditures | ​ | ​ | (28) | ​ | ​ | ​ | (85,613)
Funds held in escrow and other | ​ | ​ | 508 | ​ | ​ | ​ | (7)
Net cash provided by (used in) investing activities | ​ | ​ | (92,503) | ​ | ​ | ​ | (254,417)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows from financing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Proceeds from borrowings | ​ | ​ | 119,209 | ​ | ​ | ​ | 315,234
Repayments of borrowings | ​ | ​ | (83,000) | ​ | ​ | ​ | (57,000)
Equity issuance costs and other | ​ | ​ | (32) | ​ | ​ | ​ | (441)
Net cash provided by (used in) financing activities | ​ | ​ | 36,177 | ​ | ​ | ​ | 257,793
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net increase (decrease) in cash, cash equivalents and restricted cash | ​ | ​ | (8,448) | ​ | ​ | ​ | (29,857)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash, cash equivalents and restricted cash at beginning of period | ​ | ​ | 10,275 | ​ | ​ | ​ | 46,866
Cash, cash equivalents and restricted cash at end of period | ​ | $ | 1,827 | ​ | ​ | $ | 17,009
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Supplemental cash flow information: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for reorganization items | ​ | $ | 6,440 | ​ | ​ | $ | 2,041
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Disclosure of non-cash investing and financing activities: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Asset retirement obligations | ​ | $ | (70) | ​ | ​ | $ | 2,932

​

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

​

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION

Basis of Presentation and Principles of Consolidation

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

Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. 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 25, 2020. Please refer to the notes in the 2019 Annual Report on Form 10-K 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 reducing capital expenditures, temporarily shutting-in producing wells, and implementing various measures to ensure the continued operation of its business in a safe and secure manner. COVID-19 and governmental actions to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war between 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 agreed in April to reduce production, downward pressure on prices has continued and could continue for the foreseeable future, particularly given concerns over the impacts of the current economic downturn on demand. The Company is unable to predict the effect that these events will have on its business and financial condition due to numerous uncertainties, including the severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on its business, demand for oil and natural gas, and oil and natural gas prices. The health of the Company’s employees, contractors and vendors, and its ability to meet staffing needs in its operations and critical functions 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. For example, the Company realized lower revenue as a result of commodity price declines, which began in March 2020. In response to low commodity prices, the Company temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues in the current year. Additionally, as discussed further in Note 7, “Oil and Natural Gas Properties,” 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. 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 this Quarterly Report on Form 10-Q.

​

Emergence From Voluntary Reorganization Under Chapter 11

​

On August 7, 2019 (the Petition Date), the Company and its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Company’s chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective (the Effective Date) and the Company emerged from chapter 11 bankruptcy. See Note 2, “Reorganization,” for further details on the Company’s chapter 11 bankruptcy and the Plan.

Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. The Company elected to apply fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate.

Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result of the adoption of fresh-start accounting, the Company’s unaudited condensed consolidated financial statements subsequent to October 1, 2019 are not comparable to its consolidated financial statements prior to, and including, October 1, 2019. See Note 3, “Fresh-start Accounting,” for further details on the impact of fresh-start accounting on the Company’s unaudited condensed consolidated financial statements.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019.

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, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets, liabilities and warrants recorded as a result of the adoption of fresh-start accounting. 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, Cash Equivalents and Restricted Cash

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

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ |  | September 30, 2020 | ​ | December 31, 2019
​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 1,827 | ​ | $ | 5,701
Restricted cash | ​ | ​ | — | ​ | ​ | 4,574
Total cash, cash equivalents and restricted cash | ​ | $ | 1,827 | ​ | $ | 10,275

​
Restricted cash consisted of funds related to payments prescribed under the Plan that were held in an interest-bearing escrow account.

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 September 30, 2020 (Successor) and December 31, 2019 (Successor), allowances for doubtful accounts were approximately $0.2 million and $0.1 million, respectively.

Other Operating Property and Equipment

Other operating property and equipment was recorded at fair value as a result of fresh-start accounting on October 1, 2019 and 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, the lesser of lease term or 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.

The Company reviews its other operating property and equipment for impairment in accordance with 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.

Restructuring

During the three and nine months ended September 30, 2020 (Successor), the Company incurred none and approximately $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 (Successor), in furtherance of the consolidation into one corporate office, the Company exercised a one-time early termination option

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

under the lease agreement for the Company’s office space in Denver, Colorado. Refer to Note 4, “Leases,” for further details.

During the nine months ended September 30, 2019 (Predecessor), several senior executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the period, the Company made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. Consequently, for the three and nine months ended September 30, 2019 (Predecessor), the Company incurred $3.2 million and approximately $15.1 million in restructuring charges.

These costs were recorded in “Restructuring” on the unaudited condensed consolidated statements of operations.

Concentrations of Credit Risk

As of September 30, 2020 (Successor), 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 September 30, 2020 (Successor), the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Senior Credit Agreement.

Change in Estimate

In late March 2020 (Successor), due to changes in market conditions and decreased commodity prices, the Company determined 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 nine months ended September 30, 2020 (Successor).

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Recently Issued Accounting Pronouncements

In March 2020, the 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 is currently evaluating the effects of ASU 2019-12, but does not believe that it will have a material impact on its operating results, financial position or disclosures.

​

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (ASU 2016-13), which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. ASU 2016-13 will replace the previously required incurred loss approach with an expected loss model for instruments measured at amortized cost. The Company adopted ASU 2016-13 effective January 1, 2020 using the modified retrospective approach as of the adoption date. Based the Company’s assessment of its applicable financial assets, which are receivables from joint interest owners and oil and natural gas purchasers with various potential remedies ensuring collection from those parties, as well as assets from derivative contracts outstanding with major financial institutions, the adoption of ASU 2016-13 did not have a material impact on the Company’s operating results or financial position.

​

2. REORGANIZATION

On August 2, 2019, the Company entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of the Company’s 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, the Company filed voluntary petitions for relief under chapter 11 of the Bankruptcy Court to effect an accelerated prepackaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement. The Company continued to operate its businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the United States Bankruptcy Code and orders of the Bankruptcy Court. On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Company emerged from chapter 11 bankruptcy.

Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, the Unsecured Senior Noteholders and other claim and interest holders received the following treatment in full and final satisfaction of their claims and interests:

| ● | borrowings outstanding under the Predecessor Credit Agreement, plus unpaid interest and fees, were repaid in full, in cash, including by a refinancing (refer to Note 8, “Debt” for further details regarding the credit agreement);

| ● | the Unsecured Senior Noteholders received their pro rata share of 91% of the common stock of reorganized Battalion (New Common Shares), subject to dilution, issued pursuant to the Plan and participated in the Senior Noteholder Rights Offering (defined below);

| ● | the Company’s general unsecured claims were unimpaired and paid in full in the ordinary course; and

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

| ● | all of the Predecessor Company’s outstanding shares of common stock were cancelled and the existing common stockholders received their pro rata share of 9% of the New Common Shares issued pursuant to the Plan, subject to dilution, together with Warrants (defined below) to purchase common stock of reorganized Battalion and participated in the Existing Equity Interests Rights Offering (defined below and, collectively, the Existing Equity Total Consideration); provided, however, that registered holders of existing common stock with 2,000 shares or fewer of common stock received cash in an amount equal to the inherent value of such holder’s pro rata share of the Existing Equity Total Consideration (the Existing Equity Cash Out).

Each of the foregoing percentages of equity in the reorganized Company were as of October 8, 2019 and are subject to dilution by New Common Shares issued in connection with (i) a management incentive plan, (ii) the Warrants (defined below), (iii) the Equity Rights Offerings (defined below), and (iv) the Backstop Commitment Premium (defined below).

As a component of the Restructuring Support Agreement (i) certain Unsecured Senior Noteholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $150.2 million (the Senior Noteholder Rights Offering) and (ii) certain existing common stockholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $5.8 million (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on an assumed total enterprise value of $425.0 million. Certain of the Unsecured Senior Noteholders backstopped the Senior Noteholder Rights Offering and received as consideration (the Backstop Commitment Premium) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering, subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants. If the backstop agreement had been terminated, the Company would have been obligated to make a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering. The proceeds of the Equity Rights Offerings were used by the Company to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay reasonable and documented restructuring expenses, and (iii) fund Plan distributions.

Under the Restructuring Support Agreement, the existing common stockholders (subject to the Existing Equity Cash Out) were issued a series of warrants exercisable for cash for a three year period subsequent to the effective date of the Plan (Warrants). The Warrants were issued with strike prices based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders. The Warrants cumulatively represented 30% of the New Common Shares issued pursuant to the Plan.

​

Registration Rights Agreement

On the Effective Date, the Company and the other signatories thereto (the Demand Stockholders), entered into a registration rights agreement (the Registration Rights Agreement), pursuant to which, subject to certain conditions and limitations, the Company agreed to file with the SEC a registration statement concerning the resale of the registrable shares of New Common Shares of the Company held by Demand Stockholders (the Registrable Securities), as soon as reasonably practicable but in no event later than the later to occur of (i) ninety (90) days after the Effective Date and (ii) a date specified by a written notice to the Company by Demand Stockholders holding at least a majority of the Registerable Securities, and thereafter to use its commercially reasonable best efforts to cause the registration statement to be declared effective by the SEC as soon as reasonably practicable. In addition, from time to time, the Demand Stockholders may request that additional Registrable Securities be registered for resale by the Company. Subject to certain limitations, the Demand Stockholders also have the right to request that the Company facilitate the resale of Registrable Securities pursuant to firm commitment underwritten public offerings.

The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to suspensions of the Company’s registration obligations and indemnification.

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

3. FRESH-START ACCOUNTING

Upon the Company’s emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company’s assets immediately prior to the date of confirmation was less than the total of the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 2, “Reorganization,” for the terms of the Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as “Successor” or “Successor Company.” However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor Companies lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor Companies.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company’s total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after the reorganization.

Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company’s long-term debt, stockholders’ equity and working capital. The estimated Enterprise Value of $441.6 million at the Effective Date was in the Bankruptcy Court approved range of $425.0 million and $475.0 million. The Enterprise Value was derived from an independent valuation using an asset based methodology of estimated proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of October 1, 2019.

The Company elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate.

The Company’s principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $71.51 per barrel of oil, $3.37 per million British thermal units (MMBtu) of natural gas and $29.50 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company’s unproved acreage from a market participant perspective. See further discussion below in the “Fresh-start accounting adjustments” for the specific assumptions used in the valuation of the Company’s various other assets.

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value were reasonable and appropriate, different assumptions and estimates would materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

judgment. The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of October 1, 2019 (in thousands):

​ | ​ | ​ | ​
​ |  | October 1, 2019
​ | ​ | ​ | ​
Enterprise Value | ​ | $ | 441,583
Plus: Cash | ​ | ​ | 15,546
Less: Fair value of debt | ​ | ​ | (130,000)
Less: Fair value of warrants | ​ | ​ | (7,336)
Fair value of Successor common stock | ​ | $ | 319,793

​

The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of October 1, 2019 (in thousands):

​

​ | ​ | ​ | ​
​ |  | October 1, 2019
​ | ​ | ​ | ​
Enterprise Value | ​ | $ | 441,583
Plus: Cash | ​ | ​ | 15,546
Plus: Current liabilities | ​ | ​ | 122,134
Plus: Lease liabilities | ​ | ​ | 3,395
Plus: Noncurrent asset retirement obligation | ​ | ​ | 10,153
Plus: Other noncurrent liabilities | ​ | ​ | 1,625
Reorganization Value of Successor assets | ​ | $ | 594,436

​

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s unaudited condensed consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets, liabilities, and warrants. Amounts included in the table below are rounded to thousands.

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | As of October 1, 2019
​ |  | Predecessor Company |  | Reorganization Adjustments |  | Fresh-Start Adjustments |  | Successor Company
Current assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash and cash equivalents | ​ | $ | 17,009 | ​ | $ | (1,463) | (1)​ | $ | — | ​ | $ | 15,546
Accounts receivable, net | ​ | ​ | 37,826 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 37,826
Assets from derivative contracts | ​ | ​ | 15,310 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 15,310
Restricted cash | ​ | ​ | — | ​ | ​ | 13,839 | (2)​ | ​ | — | ​ | ​ | 13,839
Prepaids and other | ​ | ​ | 14,642 | ​ | ​ | 7,110 | (3)​ | ​ | (11,462) | (11)​ | ​ | 10,290
Total current assets | ​ | ​ | 84,787 | ​ | ​ | 19,486 | ​ | ​ | (11,462) | ​ | ​ | 92,811
Oil and natural gas properties (full cost method): | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Evaluated | ​ | ​ | 2,155,288 | ​ | ​ | — | ​ | ​ | (1,774,924) | (12)(13)​ | ​ | 380,364
Unevaluated | ​ | ​ | 438,365 | ​ | ​ | — | ​ | ​ | (329,411) | (13)​ | ​ | 108,954
Gross oil and natural gas properties | ​ | ​ | 2,593,653 | ​ | ​ | — | ​ | ​ | (2,104,335) | ​ | ​ | 489,318
Less - accumulated depletion | ​ | ​ | (1,709,719) | ​ | ​ | — | ​ | ​ | 1,709,719 | (13)​ | ​ | —
Net oil and natural gas properties | ​ | ​ | 883,934 | ​ | ​ | — | ​ | ​ | (394,616) | ​ | ​ | 489,318
Other operating property and equipment: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other operating property and equipment | ​ | ​ | 203,373 | ​ | ​ | — | ​ | ​ | (199,718) | (12)(14)​ | ​ | 3,655
Less - accumulated depreciation | ​ | ​ | (14,416) | ​ | ​ | — | ​ | ​ | 14,416 | (14)​ | ​ | —
Net other operating property and equipment | ​ | ​ | 188,957 | ​ | ​ | — | ​ | ​ | (185,302) | ​ | ​ | 3,655
Other noncurrent assets: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | ​ | 4,120 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 4,120
Operating lease right of use assets | ​ | ​ | 3,694 | ​ | ​ | — | ​ | ​ | (300) | (15)​ | ​ | 3,394
Funds in escrow and other | ​ | ​ | 1,138 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,138
Total assets | ​ | $ | 1,166,630 | ​ | $ | 19,486 | ​ | $ | (591,680) | ​ | $ | 594,436
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Current liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Accounts payable and accrued liabilities | ​ | $ | 112,578 | ​ | $ | 2,727 | (4)​ | $ | — | ​ | $ | 115,305
Liabilities from derivative contracts | ​ | ​ | 6,829 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 6,829
Current portion of long-term debt, net | ​ | ​ | 258,234 | ​ | ​ | (258,234) | (5)​ | ​ | — | ​ | ​ | —
Operating lease liabilities | ​ | ​ | 1,337 | ​ | ​ | — | ​ | ​ | (424) | (15)​ | ​ | 913
Total current liabilities | ​ | ​ | 378,978 | ​ | ​ | (255,507) | ​ | ​ | (424) | ​ | ​ | 123,047
Long-term debt, net | ​ | ​ | — | ​ | ​ | 130,000 | (6)​ | ​ | — | ​ | ​ | 130,000
Liabilities subject to compromise | ​ | ​ | 625,005 | ​ | ​ | (625,005) | (7)​ | ​ | — | ​ | ​ | —
Other noncurrent liabilities: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | ​ | 1,625 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 1,625
Asset retirement obligations | ​ | ​ | 10,153 | ​ | ​ | — | ​ | ​ | — | ​ | ​ | 10,153
Operating lease liabilities | ​ | ​ | 2,438 | ​ | ​ | — | ​ | ​ | 44 | (15)​ | ​ | 2,482
Commitments and contingencies | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Stockholders' equity: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Common Stock (Predecessor) | ​ | ​ | 16 | ​ | ​ | (16) | (8)​ | ​ | — | ​ | ​ | —
Common Stock (Successor) | ​ | ​ | — | ​ | ​ | 2 | (9)​ | ​ | — | ​ | ​ | 2
Additional paid-in capital (Predecessor) | ​ | ​ | 1,087,441 | ​ | ​ | (1,087,441) | (8)​ | ​ | — | ​ | ​ | —
Additional paid-in capital (Successor) | ​ | ​ | — | ​ | ​ | 327,127 | (9)​ | ​ | — | ​ | ​ | 327,127
Retained earnings (accumulated deficit) | ​ | ​ | (939,026) | ​ | ​ | 1,530,326 | (10)​ | ​ | (591,300) | (16)​ | ​ | —
Total stockholders' equity | ​ | ​ | 148,431 | ​ | ​ | 769,998 | ​ | ​ | (591,300) | ​ | ​ | 327,129
Total liabilities and stockholders' equity | ​ | $ | 1,166,630 | ​ | $ | 19,486 | ​ | $ | (591,680) | ​ | $ | 594,436

​

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Reorganization adjustments

| 1) | The table below details cash payments as of October 1, 2019, pursuant to the terms of the Plan described in Note 2, “Reorganization,” (in thousands):

​

​ | ​ | ​ | ​
Sources: |  | ​ | ​
Proceeds from Senior Noteholder Rights Offering | ​ | $ | 150,150
Proceeds from Senior Credit Agreement | ​ | ​ | 130,000
Proceeds from Existing Equity Interests Rights Offering | ​ | ​ | 5,779
Total Sources | ​ | $ | 285,929
​ | ​ | ​ | ​
Uses: | ​ | ​ | ​
Payment of Predecessor Credit Agreement principal, accrued interest, and fees | ​ | $ | (226,580)
Payment of debtor-in-possession junior secured term credit facility principal and accrued interest | ​ | ​ | (35,174)
Funding of professional fee escrow and cash collateral account | ​ | ​ | (13,839)
Payment of debt issuance costs on Senior Credit Agreement | ​ | ​ | (8,764)
Payment of professional fees and other | ​ | ​ | (3,035)
Total Uses | ​ | $ | (287,392)
​ | ​ | ​ | ​
Total Sources and Uses | ​ | $ | (1,463)

​

| 2) | Reflects the funding of an escrow account for professional fees associated with the chapter 11 bankruptcy and an account to cash collateralize the Predecessor Company’s outstanding letters of credit.

| 3) | Represents $10.2 million in debt issuance costs related to the Senior Credit Agreement, partially offset by the release of $3.1 million in fees paid to the Company’s restructuring advisors prior to the emergence from chapter 11 bankruptcy.

| 4) | Represents $7.7 million in fees to be paid to the Company’s restructuring advisors subsequent to the Company’s emergence from chapter 11 bankruptcy, partially offset by payments of i) accrued interest and fees on the Predecessor Credit Agreement and the debtor-in-possession junior secured term credit facility of $3.5 million and ii) professional fees associated with the chapter 11 bankruptcy of $1.5 million.

| 5) | On the Emergence Date, in accordance with the Plan, the Company repaid the principal outstanding on the Predecessor Credit Agreement of $223.2 million and the debtor-in-possession junior secured term credit facility of $35.0 million using proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

| 6) | Reflects the initial borrowing on the Senior Credit Agreement.

| 7) | Liabilities subject to compromise were as follows (in thousands):

​ | ​ | ​ | ​
6.75% senior notes due 2025 |  | $ | 625,005
Liabilities subject to compromise | ​ | ​ | 625,005
Discount on shares issued per the Senior Noteholder Subscription Rights Offering | ​ | ​ | (67,840)
Issuance of common stock to Class 4 claimholders | ​ | ​ | (75,388)
Gain on settlement of liabilities subject to compromise | ​ | $ | 481,777

​

| 8) | Reflects the cancellation of Predecessor common stock and additional paid-in capital.

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​

| 9) | The following table reconciles reorganization adjustments made to Successor common stock and additional paid-in capital (in thousands):

​ | ​ | ​ | ​
Par value of 16,203,940 shares of new common stock issued to holders of senior note claims and existing equity interest claims (valued at $19.74 per share) |  | $ | 2
Fair value of warrants issued to holder of the Existing Equity Interests (1) | ​ | ​ | 7,336
Additional paid-in-capital (Successor) | ​ | ​ | 322,294
Equity issuance costs associated with Equity Rights Offering | ​ | ​ | (2,503)
Total change in Successor common stock and additional paid-in capital | ​ | $ | 327,129

| (1) | The fair value of the warrants was estimated using a Binomial Lattice model with the following assumptions: implied stock price of the Successor Company of $19.74; initial strike price per share of $40.17, $48.28, and $60.45, for Series A, B, and C warrants, respectively, increased each month at an annualized rate of 6.75%; expected volatility of 45%; and risk free interest rate using the USD Yield Curve at each time-step in the lattice.

| 10) | The table below reflects the cumulative effect of the adjustments discussed above (in thousands):

​

​ | ​ | ​ | ​
Gain on settlement of liabilities subject to compromise |  | $ | 481,777
Success fees incurred upon emergence | ​ | ​ | (8,376)
Fair value of equity issued to Predecessor common stockholders | ​ | ​ | (7,449)
Fair value of warrants issued to Predecessor common stockholders | ​ | ​ | (7,336)
Issuance of common stock to backstop commitment parties | ​ | ​ | (13,079)
Other | ​ | ​ | (2,668)
Cancellation of Predecessor equity | ​ | ​ | 1,087,457
Net impact to retained earnings (accumulated deficit) | ​ | $ | 1,530,326

​

Fresh-start accounting adjustments

| 11) | Adjustment reflects the write-off of debt issuance costs associated with the Senior Credit Agreement of $10.2 million and the write-off of prepaid expenses related to $1.2 million of premiums for the Predecessor Company’s directors’ and officers’ insurance policy.

​

| 12) | Includes the reclassification of treating equipment and gathering support facilities from “Other operating property and equipment” to “Oil and natural gas properties, evaluated.” The Successor Company’s policy of accounting for its treating equipment and gathering support facilities identifies these assets as part of the Company’s full cost pool due to their supporting nature to the Company’s oil and natural gas operations.

​

| 13) | Reflects the adjustment to fair value of the Company’s oil and natural gas properties and unproved acreage, as well as the elimination of accumulated depletion.

​

In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $71.51 per barrel of oil, $3.37 per MMBtu of natural gas and $29.50 per barrel of natural gas liquids. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

​

In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company’s unproved acreage from a market participant perspective.

​

| 14) | Reflects the adjustment to fair value of the Company’s other operating property and equipment, as well as the elimination of accumulated depreciation.

​

For purposes of estimating the fair value of its other operating property and equipment, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.

​

| 15) | Upon adoption of fresh start accounting, the Company’s lease obligations were recalculated using the incremental borrowing rate applicable to the Company upon emergence from chapter 11 bankruptcy and commensurate with its new capital structure. The incremental borrowing rate used decreased from 4.83% in the Predecessor period to 3.70% in the Successor period. Additionally represents the removal of right-of-use assets and lease liabilities associated with the Company’s compressors, as the remaining contract term of the compressor leases were less than one year as of the Effective Date. See Note 4, “Leases,” for details associated with the Company’s short-term lease costs.

​

| 16) | Reflects the cumulative effect of the fresh-start accounting adjustments discussed above.

​

Reorganization Items

Reorganization items represent (i) expenses or income incurred subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments and are recorded in “Reorganization items, net” in the Company’s consolidated statements of operations. The following table summarizes the net reorganization items (in thousands):

​ | ​ | ​ | ​
​ | ​ | Predecessor
​ | ​ | Nine Months
​ | ​ | Ended
​ | ​ | September 30, 2019
Accrued interest | ​ | $ | 20,274
Write-off debt discount/premium and debt issuance costs | ​ | ​ | (10,953)
Reorganization professional fees and other | ​ | ​ | (11,079)
Gain (loss) on reorganization items | ​ | $ | (1,758)

​

​

​

​

4. 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

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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.

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 as an

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

expense on a straight-line basis over the lease term. 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 leases outstanding as of September 30, 2020 and December 31, 2019 (Successor) have initial lease terms ranging from 2 to 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 nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) (in thousands, except years and discount rate):

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | ​ | Predecessor | ​
​ | ​ | Nine Months | ​ | ​ | ​ | Nine Months | ​
​ | ​ | Ended | ​ | ​ | ​ | Ended | ​
​ |  | September 30, 2020 | ​ |  |  | September 30, 2019 |
Lease cost | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating lease costs | ​ | $ | 1,869 | ​ | ​ | ​ | $ | 1,932 | ​
Short-term lease costs | ​ | ​ | 16,372 | ​ | ​ | ​ | ​ | 12,262 | ​
Variable lease costs | ​ | ​ | 798 | ​ | ​ | ​ | ​ | 1,210 | ​
Total lease costs | ​ | $ | 19,039 | ​ | ​ | ​ | $ | 15,404 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Other information | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash paid for amounts included in the measurement of lease liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating cash flows from operating leases | ​ | $ | 2,093 | ​ | ​ | ​ | $ | 1,936 | ​
Right-of-use assets obtained in exchange for new operating lease liabilities | ​ | ​ | — | ​ | ​ | ​ | ​ | 5,462 | ​
Weighted-average remaining lease term - operating leases | ​ | ​ | 0.7 | years | ​ | ​ | ​ | 3.7 | years
Weighted-average discount rate - operating leases | ​ | ​ | 3.70 | % | ​ | ​ | ​ | 4.83 | %

Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approach used to record the right of use asset at fair value as of October 1, 2019.

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 (Successor) and paid a $1.3 million termination fee. The early termination option was deemed probable in May 2020 (Successor) and was recognized in the Company’s operating lease right of use asset and operating lease liability during the three months ended June 30, 2020 (Successor). This reduced the Company’s operating lease liability to $0.5 million, representing the remaining lease cost to be incurred from June 2020 through March 2021. 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 nine months ended September 30, 2020 (Successor).

Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of September 30, 2020 and December 31, 2019 (Successor), are presented in the table below (in thousands):

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Operating Leases | ​ | Successor
​ |  | September 30, 2020 |  | ​ |  | December 31, 2019
Remaining period in 2020 | ​ | $ | 211 | ​ | ​ | ​ | $ | 1,022
2021 | ​ | ​ | 453 | ​ | ​ | ​ | ​ | 876
2022 | ​ | ​ | — | ​ | ​ | ​ | ​ | 574
2023 | ​ | ​ | — | ​ | ​ | ​ | ​ | 585
2024 | ​ | ​ | — | ​ | ​ | ​ | ​ | 345
Thereafter | ​ | ​ | — | ​ | ​ | ​ | ​ | —
Total operating lease payments | ​ | ​ | 664 | ​ | ​ | ​ | ​ | 3,402
Less: discount to present value | ​ | ​ | 7 | ​ | ​ | ​ | ​ | 232
Total operating lease liabilities | ​ | ​ | 657 | ​ | ​ | ​ | ​ | 3,170
Less: current operating lease liabilities | ​ | ​ | 657 | ​ | ​ | ​ | ​ | 923
Noncurrent operating lease liabilities | ​ | $ | — | ​ | ​ | ​ | $ | 2,247

​

​

5. 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 $20.4 million and $36.4 million as of September 30, 2020 and December 31, 2019 (Successor), respectively, as “Accounts receivable” and “Other assets” on the unaudited condensed consolidated balance sheets.

Substantially all of the Company’s revenues are derived from its 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):

​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Three Months | ​ | ​ | Three Months | ​ | Nine Months | ​ | ​ | Nine Months
​ | ​ | Ended | ​ | ​ | Ended | ​ | Ended | ​ | ​ | Ended
​ |  | September 30, 2020 | ​ | ​ | September 30, 2019 |  | September 30, 2020 |  |  | September 30, 2019
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids sales: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | $ | 33,638 | ​ | ​ | $ | 46,275 | ​ | $ | 91,313 | ​ | ​ | $ | 145,024
Natural gas | ​ | ​ | 1,912 | ​ | ​ | ​ | 301 | ​ | ​ | 3,102 | ​ | ​ | ​ | 107
Natural gas liquids | ​ | ​ | 3,896 | ​ | ​ | ​ | 3,987 | ​ | ​ | 10,086 | ​ | ​ | ​ | 13,229
Total oil, natural gas and natural gas liquids sales | ​ | ​ | 39,446 | ​ | ​ | ​ | 50,563 | ​ | ​ | 104,501 | ​ | ​ | ​ | 158,360
Other | ​ | ​ | 384 | ​ | ​ | ​ | 246 | ​ | ​ | 1,222 | ​ | ​ | ​ | 743
Total operating revenues | ​ | $ | 39,830 | ​ | ​ | $ | 50,809 | ​ | $ | 105,723 | ​ | ​ | $ | 159,103

​

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

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 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 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.

​

6. DIVESTITURES

Water Infrastructure Assets

On December 20, 2018 (Predecessor), the Company sold its water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for a total adjusted purchase price of $210.9 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018 (Predecessor).

Upon closing, the Company dedicated all of the produced water from its oil and natural gas wells within its Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There were no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water to the Company.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

During the nine months ended September 30, 2019 (Predecessor), as a result of customary post-closing adjustments, the Company recorded a reduction of approximately $3.6 million on the gain on sale of the Water Assets on the unaudited condensed consolidated statements of operations in “(Gain) loss on sale of Water Assets.”

7. 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.

With the adoption of fresh-start accounting, the Company recorded its oil and natural gas properties at fair value as of the Emergence Date. The Company’s evaluated and unevaluated properties were assigned fair values of $380.4 million and $109.0 million, respectively.

The Successor Company’s policy of accounting for its treating equipment and gathering support facilities identifies these assets as part of the Company’s full cost pool due to their supporting nature to the Company’s oil and natural gas operations. The Company’s treating equipment and gathering support facilities were included in “Oil and natural gas properties, evaluated” on the unaudited condensed consolidated balance sheet as of the Emergence Date. Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approaches used.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. 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 September 30, 2020 (Successor), 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 September 30, 2020 of the West Texas Intermediate (WTI) crude oil spot price of $43.63 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 September 30, 2020 of the Henry Hub natural gas price of $1.97 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 September 30, 2020 (Successor) exceeded the ceiling amount by $128.3 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 $47.37 per barrel at June 30, 2020 (Successor) to $43.63 per barrel at September 30, 2020 (Successor). The ceiling test impairment also reflects the transfer of $23.6 million of unevaluated property costs to the full cost pool due to the Company’s intent to focus available capital on Monument Draw. At June 30, 2020 (Successor), the Company 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 (Successor) to $47.37 per barrel at June 30, 2020 (Successor). This average price decline was partially offset by favorable differentials and lower operating expenses.
​

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At September 30, 2019 (Predecessor), 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 September 30, 2019 of the WTI crude oil spot price of $57.69 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 September 30, 2019 of the Henry Hub natural gas price of $2.87 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 September 30, 2019 (Predecessor) exceeded the ceiling amount by $45.6 million which resulted in a ceiling test impairment charge of that amount for the quarter. The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-month 12-month average price for crude oil was $61.45 per barrel. At June 30, 2019 (Predecessor), the Company recorded a full cost ceiling impairment of $664.4 million. The ceiling test impairment at June 30, 2019 (Predecessor) was primarily driven by the Company’s continued focus on Monument Draw. Accordingly, the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019 (Predecessor), the majority of which is associated with the Company’s Hackberry Draw area. At March 31, 2019 (Predecessor), the Company recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and the Company’s intent to expend capital only on its most economic areas. As such, the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019 (Predecessor).

The impairments were recorded in “Full cost ceiling test impairment” on the unaudited condensed consolidated statements of operations.

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.

​

8. DEBT

As of September 30, 2020 and December 31, 2019 (Successor), the Company’s debt consisted of the following (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ | ​ | September 30, 2020 | ​ | December 31, 2019
Senior revolving credit facility | ​ | $ | 178,000 | ​ | $ | 144,000
Paycheck Protection Program loan(1) | ​ | ​ | 2,209 | ​ | ​ | -
​ | ​ | $ | 180,209 | ​ | $ | 144,000

(1) | As of September 30, 2020 (Successor), $1.4 million of the Company’s Paycheck Protection Program loan was classified as “Current portion of long-term debt” on the unaudited condensed consolidated balance sheet.

​

Senior Revolving Credit Facility

On the Effective Date, 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, which refinanced the Predecessor Company’s Amended and Restated Senior Secured Revolving Credit Agreement (the Predecessor Credit Agreement). The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $190.0 million. At September 30, 2020 (Successor), under the then-effective borrowing base of $195.0 million, the Company had $178.0 million

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indebtedness outstanding and approximately $4.7 million letters of credit outstanding under the Senior Credit Agreement, resulting in $12.3 million of borrowing capacity.

​

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 will 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 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% 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 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 attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. 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 September 30, 2020 (Successor), 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 (Successor), 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, sets the borrowing base to $190 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (defined below). The Third Amendment also reduces the amount available for issuance of letters of credit to $25.0 million and amends 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 provides for new covenants that, among other things, require the Company to enter into required swap agreements representing not less than 65% of the Company’s reasonably anticipated projected production from the 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 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 July 31, 2020 (Successor), the Company entered into the Limited Waiver to Senior Secured Revolving Credit Agreement (the Waiver) in which the lenders consented to waive maintenance of a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 as of the fiscal quarter ended June 30, 2020.

​

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On April 30, 2020 (Successor), the Company entered into the Second Amendment to the Senior Credit Agreement (Second Amendment) which among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then reduced by $5.0 million monthly starting September 1, 2020 until November 1, 2020, so that the borrowing base was scheduled to be $185.0 million on November 1, 2020, provided the borrowing base redetermination scheduled for November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii) provided that should the Company’s Consolidated Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any borrowings under the Senior Credit Agreement and thereafter, to the extent of any uncollateralized letters of credit exposure, shall be cash collateralized in accordance with the Senior Credit Agreement and (iv) allowed for a replacement benchmark rate to the London Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR). The Second Amendment also added provisions related to a loan incurred by the Company under the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act). The Company used, and the Second Amendment required the Company to use, the loan proceeds for CARES Forgivable Uses under the CARES Act. Additionally, the Second Amendment waived, for the fiscal quarter ended June 30, 2020, that the Company comply with the requirement under the Senior Credit Agreement that the Company unwind certain swap agreements for which settlement payments were calculated in such fiscal quarter to exceed 100% of actual production.

On November 21, 2019 (Successor), the Company entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), 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. 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. The Company is required to pay principal and interest installments of $0.1 million monthly beginning November 16, 2020. The maturity date of the PPP Loan is April 16, 2022.

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 eight week period after loan origination and the maintenance or achievement of certain employee levels. The Company believes it is eligible for, and is currently 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.

9. 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

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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 September 30, 2020 and December 31, 2019 (Successor) (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ | ​ | September 30, 2020
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ |  | 28,671 | ​ | $ | — | ​ |  | 28,671
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | ​ | 12,347 | ​ | $ | — | ​ | ​ | 12,347

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ | ​ | December 31, 2019
​ |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Assets from derivative contracts | ​ | $ | — | ​ | $ | 5,219 | ​ | $ | — | ​ | $ | 5,219
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Liabilities from derivative contracts | ​ | $ | — | ​ | $ | 12,923 | ​ | $ | — | ​ | $ | 12,923

​

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (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 10, “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.

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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, restricted cash, accounts receivable, noncurrent 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.

On the Effective Date, the Company emerged from chapter 11 bankruptcy and adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company’s assets, liabilities and warrants were recorded at their fair values as of the fresh-start reporting date, October 1, 2019. See Note 3, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company.

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 11, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

10. 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 September 30, 2020 (Successor), the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Credit Agreement.

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

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and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019 (Successor) (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | Successor | ​ | ​ | ​ | Successor
Derivatives not designated as | ​ | ​ | ​ | Asset derivative contracts | ​ | ​ | ​ | Liability derivative contracts
hedging contracts under ASC 815 |  | Balance sheet location |  | September 30, 2020 |  | December 31, 2019 |  | Balance sheet location |  | September 30, 2020 |  | December 31, 2019
Commodity contracts | ​ | Current assets - assets from derivative contracts | ​ | $ | 18,996 | ​ | $ | 4,995 | ​ | Current liabilities - liabilities from derivative contracts | ​ | $ | (9,055) | ​ | $ | (8,069)
Commodity contracts | ​ | Other noncurrent assets - assets from derivative contracts | ​ | ​ | 9,675 | ​ | ​ | 224 | ​ | Other noncurrent liabilities - liabilities from derivative contracts | ​ | ​ | (3,292) | ​ | ​ | (4,854)
Total derivatives not designated as hedging contracts under ASC 815 | ​ | ​ | ​ | $ | 28,671 | ​ | $ | 5,219 | ​ | ​ | ​ | $ | (12,347) | ​ | $ | (12,923)

​

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) recognized in income on derivative contracts for the | ​ | Amount of gain or (loss) recognized in income on derivative contracts for the
​ | ​ | ​ | ​ | Successor | ​ | ​ | Predecessor | ​ | Successor | ​ | ​ | Predecessor
Derivatives not designated | ​ | Location of gain or | ​ | Three Months | ​ | ​ | Three Months | ​ | Nine Months | ​ | ​ | Nine Months
as hedging contracts | ​ | (loss) recognized in income | ​ | Ended | ​ | ​ | Ended | ​ | Ended | ​ | ​ | Ended
under ASC 815 |  | on derivative contracts |  | September 30, 2020 |  |  | September 30, 2019 |  | September 30, 2020 |  |  | September 30, 2019
Commodity contracts: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Unrealized gain (loss) on commodity contracts | ​ | Other income (expenses) - net gain (loss) on derivative contracts | ​ | $ | (21,128) | ​ | ​ | $ | 11,571 | ​ | $ | 24,029 | ​ | ​ | $ | (45,834)
Realized gain (loss) on commodity contracts | ​ | Other income (expenses) - net gain (loss) on derivative contracts | ​ | ​ | 5,285 | ​ | ​ | ​ | 1,886 | ​ | ​ | 43,666 | ​ | ​ | ​ | 11,502
Total net gain (loss) on derivative contracts | ​ | ​ | ​ | $ | (15,843) | ​ | ​ | $ | 13,457 | ​ | $ | 67,695 | ​ | ​ | $ | (34,332)

​

During the three and nine months ended September 30, 2020 (Successor), the Company terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $6.6 million and $22.9 million, respectively, which were recorded in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.

​

At September 30, 2020 (Successor), 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
2020 | ​ | Fixed-Price Swap | ​ | Natural Gas | ​ | 736,000 | ​ | $ | 2.56
2020 | ​ | Call | ​ | Crude Oil | ​ | 726,800 | ​ | ​ | 70.00
2020 | ​ | Put | ​ | Crude Oil | ​ | 368,000 | ​ | ​ | 42.10
2020 | ​ | Producer Collar (Ceiling) | ​ | Crude Oil | ​ | 414,000 | ​ | ​ | 49.02
2020 | ​ | Producer Collar (Floor) | ​ | Crude Oil | ​ | 414,000 | ​ | ​ | 42.10
2020 | ​ | Basis Swap | ​ | Crude Oil | ​ | 782,000 | ​ | ​ | 0.26
2020 | ​ | WTI NYMEX Roll | ​ | Crude Oil | ​ | 518,500 | ​ | ​ | 0.17
2021 | ​ | Fixed-Price Swap | ​ | Natural Gas | ​ | 2,190,000 | ​ | ​ | 2.47
2021 | ​ | Fixed-Price Swap | ​ | Crude Oil | ​ | 2,554,000 | ​ | ​ | 45.98
2021 | ​ | Basis Swap | ​ | Crude Oil | ​ | 2,554,000 | ​ | ​ | (0.11)
2021 | ​ | WTI NYMEX Roll | ​ | Crude Oil | ​ | 2,554,000 | ​ | ​ | (0.29)
2022 | ​ | Fixed-Price Swap | ​ | Crude Oil | ​ | 724,000 | ​ | ​ | 51.50
2022 | ​ | Basis Swap | ​ | Crude Oil | ​ | 724,000 | ​ | ​ | 0.88
2022 | ​ | WTI NYMEX Roll | ​ | Crude Oil | ​ | 1,276,000 | ​ | ​ | 0.00

​

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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 September 30, 2020 and December 31, 2019 (Successor) (in thousands):

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | Successor
​ | ​ | Derivative Assets | ​ | Derivative Liabilities
Offsetting of Derivative Assets and Liabilities |  | September 30, 2020 |  | December 31, 2019 |  | September 30, 2020 |  | December 31, 2019
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Gross Amounts Presented in the Consolidated Balance Sheet | ​ | $ | 28,671 | ​ | $ | 5,219 | ​ | $ | (12,347) | ​ | $ | (12,923)
Amounts Not Offset in the Consolidated Balance Sheet | ​ | ​ | (6,928) | ​ | ​ | (4,557) | ​ | ​ | 6,928 | ​ | ​ | 4,557
Net Amount | ​ | $ | 21,743 | ​ | $ | 662 | ​ | $ | (5,419) | ​ | $ | (8,366)

​

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.

11. 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.

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

​

​ | ​ | ​ | ​
Liability for asset retirement obligations as of December 31, 2019 (Successor) |  | $ | 10,590
Liabilities settled and divested | ​ | ​ | (259)
Additions | ​ | ​ | 137
Accretion expense | ​ | ​ | 440
Revisions in estimated cash flows | ​ | ​ | 52
Liability for asset retirement obligations as of September 30, 2020 (Successor) | ​ | $ | 10,960

​

​

12. COMMITMENTS AND CONTINGENCIES

Commitments

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 September 30, 2020 (Successor), the Company had in place three long-term crude oil contracts and 14 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.

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NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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.

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13. STOCKHOLDERS’ EQUITY

Common Stock

On October 8, 2019, upon emergence from chapter 11 bankruptcy, by operation of the Plan and the confirmation order, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 16.2 million shares of new common stock. Refer to Note 2, “Reorganization,” for further details.

On October 8, 2019, upon emergence from chapter 11 bankruptcy, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the total number of shares of all classes of capital stock that the Successor Company has the authority to issue is 101,000,000 of which 100,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share, (ii) a classified board structure until the 2021 Annual Meeting of Stockholders, and (iii) a restriction on the Successor Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code. In addition, the amended and restated certificate of incorporation stipulates provisions for the right of removal of directors, specifically that prior to the 2021 Annual Meeting, any Group II Director (as defined in the certificate of incorporation) may be removed with or without cause by 85% of the shares then entitled to vote at an election of directors (which voting threshold has been increased solely with respect to such class of directors from a majority of shares then entitled to vote at an election of directors). Beginning at the 2021 Annual Meeting, any director of either class may be removed with or without cause by a majority of shares entitled to vote.

Warrants

On October 8, 2019, upon emergence from chapter 11 bankruptcy, by operation of the Plan and the confirmation order, all existing warrants of the Predecessor Company were cancelled and the Successor Company entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which the Successor Company issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of the Company’s Existing Equity Interests pursuant to the Plan.

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 the Effective Date, 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 September 30, 2020 (Successor), 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 $42.10, $50.73 and $63.67, respectively.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of the Company’s business. Refer to Note 2 “Reorganization” for further details.

On September 9, 2016, the Predecessor Company issued 4.7 million warrants. The warrants could be exercised to purchase 4.7 million shares of the Predecessor Company's common stock at an exercise price of $14.04 per share. The holders were entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. Upon emergence from chapter 11 bankruptcy, all of these outstanding warrants were cancelled. Refer to Note 2, “Reorganization,” for further details.

Incentive Plans

On September 9, 2016, the Predecessor Company’s board of directors adopted the 2016 Long-Term Incentive Plan (the 2016 Plan). Immediately prior to emergence from chapter 11 bankruptcy, the 2016 Plan was cancelled and all outstanding stock-based compensation awards granted thereunder were either vested or cancelled.

On January 29, 2020, the Successor Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the 2020 Plan). An aggregate of approximately 1.5 million shares of the Successor Company’s common stock were available for grant pursuant to awards under the 2020 Plan. As of September 30, 2020 (Successor), a maximum of 0.2 million shares of the Successor Company’s common stock remained reserved for issuance under the 2020 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 nine months ended September 30, 2020 (Successor), the Company recognized expense of $0.6 million and $1.8 million, respectively, related to stock-based compensation. For the three and nine months ended September 30, 2019 (Predecessor), the Company recognized a credit of $2.3 million and $8.0 million, respectively, related to stock-based compensation. During the nine months ended September 30, 2019 (Predecessor), several senior executives departed the Company. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three and nine months ended September 30, 2019 (Predecessor), the Company recognized an incremental reduction to stock-based compensation expense of $1.1 million and $9.5 million, respectively, associated with these modifications. 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 2020 Plan covering shares of common stock to employees of the Successor Company and granted stock options under the 2016 Plan covering shares of common stock to employees of the Predecessor 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 2020 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. Awards granted under the 2016 Plan typically vested over a three year period at a rate of one-third on the annual anniversary date of the grant and expired ten years from the grant date.

During the nine months ended September 30, 2020 (Successor), the Company granted stock options under the 2020 Plan covering 0.6 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 exercise price of $28.32 per share. At September 30, 2020

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

(Successor), the Company had $1.2 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 2.0 years.

No stock options were granted during the nine months ended September 30, 2019 (Predecessor). At September 30, 2019 (Predecessor), the Company had $0.2 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 0.8 years. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding stock options under the 2016 Plan were cancelled. Refer to Note 2, “Reorganization,” for further details.

Restricted Stock

From time to time, the Company grants shares of restricted stock units (RSUs) under the 2020 Plan to employees of the Successor Company and granted shares of restricted stock under the 2016 Plan to employees and non-employee directors of the Predecessor Company. Under the 2020 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. Under the 2016 Plan, employee shares typically vested over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vested six months from the date of grant.

During the nine months ended September 30, 2020 (Successor), the Company granted 1.0 million shares of RSUs with the vesting conditions and fair values described below under the 2020 Plan to employees of the Company. At September 30, 2020 (Successor), the Company had $4.9 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted-average period of 2.7 years.

| ● | 0.4 million RSUs granted will vest over four years at a rate one-fourth on the annual anniversary of date of the grant. These RSUs were granted at fair value prices ranging from $4.36 to $11.89 with a weighted average fair value price of $11.55 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 values ranging from $7.88 to $11.89 with a weighted average fair value price of $11.32 per share. As of September 30, 2020 (Successor), 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.

| ● | 0.4 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 values ranging from $4.05 to $6.48 with a weighted average fair value of $6.13 per share.

During the nine months ended September 30, 2019 (Predecessor), the Company granted 4.2 million shares of restricted stock under the 2016 Plan to employees of the Company. These restricted shares were granted at prices ranging from $1.29 to $1.40 with a weighted average price of $1.29 per share. At September 30, 2019 (Predecessor), the Company had $2.7 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 1.3 years. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock granted under the 2016 Plan was vested. Refer to Note 2, "Reorganization," for further details.

​

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

14. EARNINGS PER SHARE

On October 8, 2019, upon emergence from chapter 11 bankruptcy, the Predecessor Company’s equity was cancelled and new equity was issued. Refer to Note 2, “Reorganization,” for further details.

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Three Months | ​ | ​ | Three Months | ​ | Nine Months | ​ | ​ | Nine Months
​ | ​ | Ended | ​ | ​ | Ended | ​ | Ended | ​ | ​ | Ended
​ |  | September 30, 2020 |  |  | September 30, 2019 |  | September 30, 2020 |  |  | September 30, 2019
Basic: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | $ | (153,125) | ​ | ​ | $ | (63,284) | ​ | $ | (165,950) | ​ | ​ | $ | (1,040,687)
Weighted average basic number of common shares outstanding | ​ | ​ | 16,204 | ​ | ​ | ​ | 159,143 | ​ | ​ | 16,204 | ​ | ​ | ​ | 158,916
Basic net income (loss) per share of common stock | ​ | $ | (9.45) | ​ | ​ | $ | (0.40) | ​ | $ | (10.24) | ​ | ​ | $ | (6.55)
Diluted: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net income (loss) | ​ | ​ | (153,125) | ​ | ​ | ​ | (63,284) | ​ | ​ | (165,950) | ​ | ​ | ​ | (1,040,687)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Weighted average basic number of common shares outstanding | ​ | ​ | 16,204 | ​ | ​ | ​ | 159,143 | ​ | ​ | 16,204 | ​ | ​ | ​ | 158,916
Common stock equivalent shares representing shares issuable upon: | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Exercise of Predecessor stock options | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive
Exercise of Predecessor warrants | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive
Vesting of Predecessor restricted shares | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive | ​ | ​ | — | ​ | ​ | ​ | Anti-dilutive
Exercise of Successor Series A Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | — | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | —
Exercise of Successor Series B Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | — | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | —
Exercise of Successor Series C Warrants | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | — | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | —
Exercise of Successor stock options | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | — | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | —
Vesting of Successor restricted stock units | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | — | ​ | ​ | Anti-dilutive | ​ | ​ | ​ | —
Weighted average diluted number of common shares outstanding | ​ | ​ | 16,204 | ​ | ​ | ​ | 159,143 | ​ | ​ | 16,204 | ​ | ​ | ​ | 158,916
Diluted net income (loss) per share of common stock | ​ | $ | (9.45) | ​ | ​ | $ | (0.40) | ​ | $ | (10.24) | ​ | ​ | $ | (6.55)

​

Common stock equivalents, including warrants, options and restricted stock units, totaling 7.8 million and 7.6 million shares for the three and nine months ended September 30, 2020 (Successor), 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.

Common stock equivalents, including stock options, restricted shares and warrants, totaling 11.8 million and 14.1 million shares for the three and nine months ended September 30, 2019 (Predecessor), 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.

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BATTALION OIL CORPORATION

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

15. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

​

​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor
​ |  | September 30, 2020 |  | December 31, 2019
Accounts receivable, net: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 18,605 | ​ | $ | 36,367
Joint interest accounts | ​ | ​ | 7,037 | ​ | ​ | 10,145
Other | ​ | ​ | 411 | ​ | ​ | 1,992
​ | ​ | $ | 26,053 | ​ | $ | 48,504
Prepaids and other: | ​ | ​ | ​ | ​ | ​ | ​
Prepaids | ​ | $ | 552 | ​ | $ | 2,093
Income tax receivable | ​ | ​ | — | ​ | ​ | 1,250
Funds in escrow | ​ | ​ | 1,740 | ​ | ​ | 4,000
Other | ​ | ​ | 34 | ​ | ​ | 36
​ | ​ | $ | 2,326 | ​ | $ | 7,379
Other assets: | ​ | ​ | ​ | ​ | ​ | ​
Oil, natural gas and natural gas liquids revenues | ​ | $ | 1,796 | ​ | $ | —
Joint interest accounts | ​ | ​ | 2,676 | ​ | ​ | —
Funds in escrow | ​ | ​ | 581 | ​ | ​ | 580
Other | ​ | ​ | 125 | ​ | ​ | 123
​ | ​ | $ | 5,178 | ​ | $ | 703
Accounts payable and accrued liabilities: | ​ | ​ | ​ | ​ | ​ | ​
Trade payables | ​ | $ | 27,725 | ​ | $ | 36,038
Accrued oil and natural gas capital costs | ​ | ​ | 3,658 | ​ | ​ | 22,781
Revenues and royalties payable | ​ | ​ | 16,294 | ​ | ​ | 25,457
Accrued interest expense | ​ | ​ | 584 | ​ | ​ | 604
Accrued employee compensation | ​ | ​ | — | ​ | ​ | 2,947
Accrued lease operating expenses | ​ | ​ | 7,768 | ​ | ​ | 9,230
Other | ​ | ​ | 101 | ​ | ​ | 276
​ | ​ | $ | 56,130 | ​ | $ | 97,333

​

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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 nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) 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, 2019 (Successor).

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019.

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 (Predecessor), 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.

During the first nine months of 2020 (Successor), production averaged 16,712 Boe/d compared to average production of 17,209 Boe/d during the first nine months of 2019 (Predecessor). Our average daily oil and natural gas production decreased in the first nine months of 2020 (Successor) when compared to the same period in the prior year primarily due to our temporary shut-in of a portion of producing wells across all our operating areas in May and June 2020 as a consequence of low oil prices. Estimated downtime associated with these temporary shut-ins was approximately 1,800 Boe/d for the first nine months of 2020 (Successor). The production decline caused by temporary shut-ins in the current year period was partially offset by new wells put online since the prior year. For the nine months ended September 30, 2020 (Successor), we drilled and cased 4.0 gross (4.0 net) operated wells, completed 5.0 gross (4.3 net) operated wells, and put online 7.0 gross (6.3 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 and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Oil and natural gas prices are inherently volatile and sustained lower commodity prices could have a material impact upon 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 October 2020 of $42.37 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 amount related to the net book value of our oil and natural gas properties would have been reduced and would have generated an additional impairment of $77.5 million, 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

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cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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 reducing capital expenditures, temporarily shutting-in producing wells, and implementing various measures to ensure the continued operation of our business in a safe and secure manner. COVID-19 and governmental actions to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war between 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 agreed in April to reduce production, downward pressure on prices has continued and could continue for the foreseeable future, particularly given concerns over the impacts of the current economic downturn on demand. We are unable to predict the effect that these events will have on our business and financial condition due to numerous uncertainties, including the severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on our business, demand for oil and natural gas, and oil and natural gas prices. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions 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 the Company’s operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years. For example, we realized lower revenue as a result of commodity price declines, which began in March 2020. In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020, which further contributed to lower revenues in the current year. Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of our reserves. 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 this Quarterly Report on Form 10-Q.

​

Acid Gas Injection Well Permits

​

During the nine months ended September 30, 2020 (Successor), we received permits from the Texas Railroad Commission and the Texas Commission on Environmental Quality to construct and operate an acid gas injection well (AGI) by converting an existing producing gas well. AGI can provide a more cost effective alternative to sour gas treating. We are currently evaluating options for development of an AGI facility, including, but not limited to, divestiture of the assets with an associated third party treating arrangement for our sour gas production.

​

Successor Senior Revolving Credit Facility

On October 29, 2020 (Successor), we entered into the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment). The Third Amendment, among other things, sets the borrowing base to $190 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (defined below). The Third Amendment also reduces the amount available for the issuance of letters of credit to $25.0 million and amends 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 provides for new covenants that, among other things, require us to enter into required swap agreements representing not less than 65% of our reasonably anticipated projected production from the 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 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

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Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and also suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

​

On July 31, 2020 (Successor), we entered into the Limited Waiver to Senior Secured Revolving Credit Agreement (the Waiver) in which, the lenders consented to waive maintenance of a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 as of the fiscal quarter ended June 30, 2020. Our failure to comply with the Current Ratio for the three months ended June 30, 2020 (Successor) was primarily the result of our decision to shut in certain production due to low oil prices coupled with capital spending required to maintain certain of our oil and gas leasehold interests.

​

On April 30, 2020 (Successor), we entered into the Second Amendment to the Senior Credit Agreement (Second Amendment) which among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then reduced by $5.0 million monthly starting September 1, 2020 until November 1, 2020, so that the borrowing base was scheduled to be $185.0 million on November 1, 2020, provided the borrowing base redetermination scheduled for November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any borrowings under the Senior Credit Agreement and thereafter, to the extent of any uncollateralized letters of credit exposure, shall be cash collateralized in accordance with the Senior Credit Agreement and (iv) allowed for a replacement benchmark rate to the London Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR). The Second Amendment also added provisions related to a loan incurred by us under the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act). We used, and the Second Amendment required us to use, the loan proceeds for CARES Forgivable Uses under the CARES Act. Additionally, the Second Amendment waived, for the fiscal quarter ended June 30, 2020, that we comply with the requirement under the Senior Credit Agreement that we unwind certain swap agreements for which settlement payments were calculated in such fiscal quarter to exceed 100% of actual production.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), 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. 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. We are required to pay principal and interest installments of $0.1 million monthly beginning November 16, 2020. The maturity date of the PPP Loan is April 16, 2022.

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 the terms of the CARES Act during the eight week period after loan origination and the maintenance or achievement of certain employee levels. We believe we are eligible for, and are currently 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.

Listing of our Common Stock on NYSE American

Our Predecessor common stock was previously listed on the New York Stock Exchange (NYSE) under the symbol “HK.” As a result of our failure to satisfy the continued listing requirements of the NYSE, on July 22, 2019, our

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Predecessor common stock was delisted from the NYSE. Effective February 20, 2020, we commenced trading on the NYSE American exchange under the symbol “BATL.”

Capital Resources and Liquidity

In March 2020 (Successor), the World Health Organization declared the outbreak of COVID-19 a pandemic. The COVID-19 outbreak and associated government restrictions significantly impacted economic activity and markets and dramatically reduced current and anticipated 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 received for our production during the nine months ended September 30, 2020 (Successor). We realized lower revenue as a result of these commodity price declines, which began in March 2020 (Successor). In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020 (Successor), which further contributed to lower revenues in the current year. Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of our reserves.

​

Continued 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 a severe 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 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.

​

Our 2020 drilling and completion budget, originally approved by our board in December 2019, contemplated running one operated rig in the Delaware Basin during the year. That budget contemplated spending approximately $123 million to $138 million in capital expenditures, including drilling, completions, support infrastructure and other capital costs, to drill seven to ten gross operated wells and to put online 12 to 14 gross operated wells during the year. We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve acreage, and meet our contractual obligations. Accordingly, in March 2020, as a result of changes in market conditions and commodity prices, we scaled back our capital operations and spending. The rate of our expenditures has declined as we have progressed through the year and we expect our anticipated full year 2020 capital expenditures will be approximately $80 million to $84 million, subject to our continuing evaluation of market conditions and the risks and uncertainties affecting our business detailed elsewhere in this report.

​

Our near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations, and borrowings under our Senior Credit Agreement, which has a current borrowing base of $190.0 million. Amounts borrowed under the Senior Credit Agreement will mature on October 8, 2024. At September 30, 2020 (Successor), under the then-effective borrowing base of $195.0 million, we had $178.0 million of indebtedness outstanding and approximately $4.7 million letters of credit outstanding under the Senior Credit Agreement, resulting in $12.3 million of borrowing capacity. Under the Third Amendment, our borrowing base was recently affirmed at $190.0 million; however, we currently expect availability under our Senior Credit Agreement to be limited through at least the second quarter of 2021. The next redetermination is scheduled for the spring of 2021. If our borrowing base is reduced upon a redetermination, our resulting liquidity could be insufficient to fund our business and operations 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 these and other matters relating to the Senior Credit Agreement and, in parallel, are exploring alternative means to maintain our access to sufficient capital to fund our business, including refinancings, asset sales, and additional means to reduce our capital requirements. While we believe that alternatives to maintain compliance or to

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replace our Senior Credit Agreement are available to us should they become necessary, there can be no assurance in this regard.

​

The Senior Credit Agreement 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. We have recently, and in the past, obtained amendments to the covenants under our revolving credit agreements in circumstances where we anticipated that it might be challenging for us to comply with the financial covenants 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.

The current depression in oil and natural gas prices and our decision to temporarily shut-in a portion of our production in response to those 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 compliance with the Current Ratio under the Senior Credit Agreement for the fiscal quarter ended June 30, 2020. Thus, on July 31, 2020 (Successor), we entered into the 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 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. Pursuant to the Third Amendment, on October 29, 2020, the lenders waived maintenance of the Current Ratio for the fiscal quarters ending September 30, 2020 and suspends testing of the Current Ratio until the fiscal quarter ending December 31, 2021. As of September 30, 2020 (Successor), after giving effect to the Third Amendment, we were in compliance with the financial covenants under the Senior Credit Agreement.

In prior years, we have also obtained waivers and amendments for optional 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, 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.

​

While we have largely been successful in obtaining modifications of our covenants as needed, there can be no assurance that we will be successful in the future. In the event we are not successful, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowing under our Senior Credit Agreement.

When commodity prices decline significantly, as they have recently, our ability to finance our capital budget and operations may be adversely impacted. We use 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 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. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our 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

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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 nine months ended September 30, 2020 (Successor), operating cash flows supplemented with borrowings under our revolving credit agreement were used to fund our drilling and completion programs. See “Results of Operations” for a review of the impact of prices and volumes on operating revenues.

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

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Nine Months | ​ | ​ | Nine Months
​ | ​ | Ended | ​ | ​ | Ended
​ |  | September 30, 2020 |  |  | September 30, 2019
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flows provided by (used in) operating activities | ​ | $ | 47,878 | ​ | ​ | $ | (33,233)
Cash flows provided by (used in) investing activities | ​ | ​ | (92,503) | ​ | ​ | ​ | (254,417)
Cash flows provided by (used in) financing activities | ​ | ​ | 36,177 | ​ | ​ | ​ | 257,793
Net increase (decrease) in cash, cash equivalents and restricted cash | ​ | $ | (8,448) | ​ | ​ | $ | (29,857)

​

Operating Activities. Net cash flows provided by operating activities for the nine months ended September 30, 2020 (Successor) and net cash flows used in operating activities for the nine months ended September 30, 2019 (Predecessor) were $47.9 million and $33.2 million, respectively.

Operating cash flows for the nine months ended September 30, 2020 (Successor) increased from the comparable prior year period due to decreases in our operating expenses associated with our focus on efficiencies and cost savings and a decrease in interest expense associated with lower outstanding debt due to our chapter 11 bankruptcy. In addition, realized gains from derivative contracts were higher in the nine months ended September 30, 2020, which included the early termination of certain derivative contracts. During the nine months ended September 30, 2020 (Successor), we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 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 than the comparable prior year period.

Operating cash flows for the nine months ended September 30, 2019 (Predecessor) decreased from the comparable prior year period due to increases in our operating expenses, primarily severances paid to executives, reorganization costs, and third party water hauling and disposal costs.

Investing Activities. Net cash flows used in investing activities for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) were approximately $92.5 million and $254.4 million, respectively.

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During the nine months ended September 30, 2020 (Successor), we spent $96.5 million on oil and natural gas capital expenditures, of which $62.9 million related to drilling and completion costs and $32.1 million related to the development of our treating equipment and gathering support infrastructure. We received $3.5 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.

During the nine months ended September 30, 2019 (Predecessor), we spent $167.2 million on oil and natural gas capital expenditures, of which $158.6 million related to drilling and completion costs. We also spent approximately $85.6 million on capital expenditures related to the development of our natural gas treating equipment and our gathering support infrastructure.

Financing Activities. Net cash flows provided by financing activities for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor) were $36.2 million and $257.8 million, respectively.

During the nine months ended September 30, 2020 (Successor), net borrowings of $34.0 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 PPP Loan to fund payroll costs, rent and utilities.

During the nine months ended September 30, 2019 (Predecessor), net borrowings of $35.0 million under our debtor-in-possession junior secured term credit facility (DIP Facility) and $223.2 million under our Predecessor Credit Agreement were used to fund our drilling and completions program, as well as the development of our treating infrastructure and our gathering support infrastructure.

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 $190.0 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 will 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 1.50% to 2.50% for ABR-based loans or at specified margins over LIBOR of 2.50% to 3.50% 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 which 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 attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. Amounts outstanding 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.

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On October 29, 2020 (Successor),we entered into the Third Amendment. The Third Amendment, among other things, sets the borrowing base to $190 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment. The Third Amendment also reduces the amount available for the issuance of letters of credit to $25.0 million and amends 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 provides for new covenants that, among other things, require us to enter into required swap agreements representing not less than 65% of our reasonably anticipated projected production from the 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 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 July 31, 2020 (Successor), we entered into the Waiver which waived 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.

​

On April 30, 2020 (Successor), we entered into the Second Amendment to the Senior Credit Agreement (Second Amendment) which among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then reduced by $5.0 million monthly starting September 1, 2020 until November 1, 2020, so that the borrowing base was scheduled to be $185.0 million on November 1, 2020, provided the borrowing base redetermination scheduled for November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any borrowings under the Senior Credit Agreement and thereafter, to the extent of any uncollateralized letters of credit exposure, shall be cash collateralized in accordance with the Senior Credit Agreement and (iv) allowed for a replacement benchmark rate to the London Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR). The Second Amendment also added provisions related to a loan incurred by us under the Paycheck Protection Program of the CARES Act. We used, and the Second Amendment required us to use, the loan proceeds for CARES Forgivable Uses under the CARES Act. Additionally, the Second Amendment waived, for the fiscal quarter ended June 30, 2020, that we comply with the requirement under the Senior Credit Agreement that we unwind certain swap agreements for which settlement payments were calculated in such fiscal quarter to exceed 100% of actual production.

On November 21, 2019 (Successor), we entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00.

As of September 30, 2020 (Successor), 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 (Successor), we entered into 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. 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. We are required to pay principal and interest installments of $0.1 million monthly beginning November 16, 2020. The maturity date of the PPP Loan is April 16, 2022.

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-

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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 the terms of the CARES Act during the eight week period after loan origination and the maintenance or achievement of certain employee levels. We believe we are eligible for, and are currently 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, 2019 (Successor).

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Results of Operations

​
Three Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)
​

We reported a net loss of $153.1 million and $63.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The table included below sets forth financial information for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Three Months | ​ | ​ | Three Months
​ | ​ | Ended | ​ | ​ | Ended
In thousands (except per unit and per Boe amounts) |  | September 30, 2020 |  |  | September 30, 2019
Net income (loss) | ​ | $ | (153,125) | ​ | ​ | $ | (63,284)
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | ​ | 33,638 | ​ | ​ | ​ | 46,275
Natural gas | ​ | ​ | 1,912 | ​ | ​ | ​ | 301
Natural gas liquids | ​ | ​ | 3,896 | ​ | ​ | ​ | 3,987
Other | ​ | ​ | 384 | ​ | ​ | ​ | 246
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 10,091 | ​ | ​ | ​ | 11,958
Workover and other | ​ | ​ | 905 | ​ | ​ | ​ | 1,566
Taxes other than income | ​ | ​ | 2,722 | ​ | ​ | ​ | 3,012
Gathering and other | ​ | ​ | 13,500 | ​ | ​ | ​ | 10,147
Restructuring | ​ | ​ | — | ​ | ​ | ​ | 3,223
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 3,491 | ​ | ​ | ​ | 21,701
Stock-based compensation | ​ | ​ | 620 | ​ | ​ | ​ | (2,278)
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 15,326 | ​ | ​ | ​ | 18,036
Depreciation – Other | ​ | ​ | 283 | ​ | ​ | ​ | 2,371
Accretion expense | ​ | ​ | 146 | ​ | ​ | ​ | 105
Full cost ceiling impairment | ​ | ​ | 128,336 | ​ | ​ | ​ | 45,568
(Gain) loss on sale of Water Assets | ​ | ​ | — | ​ | ​ | ​ | (164)
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | (15,843) | ​ | ​ | ​ | 13,457
Interest expense and other | ​ | ​ | (1,692) | ​ | ​ | ​ | (10,547)
Reorganization items, net | ​ | ​ | — | ​ | ​ | ​ | (1,758)
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 877 | ​ | ​ | ​ | 863
Natural Gas - MMcf | ​ | ​ | 2,266 | ​ | ​ | ​ | 1,924
Natural gas liquids – MBbls | ​ | ​ | 316 | ​ | ​ | ​ | 333
Total MBoe(1) | ​ | ​ | 1,571 | ​ | ​ | ​ | 1,517
Average daily production – Boe/d(1) | ​ | ​ | 17,076 | ​ | ​ | ​ | 16,489
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 38.36 | ​ | ​ | $ | 53.62
Natural gas price - Mcf | ​ | ​ | 0.84 | ​ | ​ | ​ | 0.16
Natural gas liquids price - Bbl | ​ | ​ | 12.33 | ​ | ​ | ​ | 11.97
Total per Boe(1) | ​ | ​ | 25.11 | ​ | ​ | ​ | 33.33
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 6.42 | ​ | ​ | $ | 7.88
Workover and other | ​ | ​ | 0.58 | ​ | ​ | ​ | 1.03
Taxes other than income | ​ | ​ | 1.73 | ​ | ​ | ​ | 1.99
Gathering and other | ​ | ​ | 8.59 | ​ | ​ | ​ | 6.69
Restructuring | ​ | ​ | — | ​ | ​ | ​ | 2.12
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.22 | ​ | ​ | ​ | 14.31
Stock-based compensation | ​ | ​ | 0.39 | ​ | ​ | ​ | (1.50)
Depletion | ​ | ​ | 9.76 | ​ | ​ | ​ | 11.89

(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 $39.4 million and $50.6 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. For the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), production averaged 17,076 Boe/d and 16,489 Boe/d, respectively. Average realized prices (excluding the effects of hedging arrangements) were $25.11 per Boe and $33.33 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease operating expenses were $10.1 million and $12.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, lease operating expenses were $6.42 per Boe and $7.88 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decrease in lease operating expenses in 2020 results from our focus on optimization of production operations and decreased salt water disposal costs due to lower production volumes and less produced water.

Workover and other expenses were $0.9 million and $1.6 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, workover and other expenses were $0.58 per Boe and $1.03 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decreased costs in 2020 relate to recent strides in improving well and completion designs and fewer workovers performed.

Taxes other than income were $2.7 million and $3.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), 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 $1.73 per Boe and $1.99 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Gathering and other expenses were $13.5 million and $10.1 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our gathering support infrastructure, gas treating fees, rig stacking charges and other. Approximately $3.8 million and $2.5 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Approximately $9.7 million and $7.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities. Our overall production volumes were slightly higher in the current year period primarily from an increase in our produced natural gas in Monument Draw. These natural gas volumes are processed through our hydrogen sulfide treating plant in the area, which led to higher operating expenses, such as chemical costs, associated with our treating equipment during the current year period.

Restructuring expense was approximately $3.2 million for the three months ended 2019 (Predecessor). During the three months ended September 30, 2019 (Predecessor), senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally, during the 2019 period, we made the decision to consolidate into one corporate office located in Houston, Texas. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $3.5 million and $21.7 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits. Payroll and employee-related benefits decreased due to a reduction in our workforce since the prior year period. The decrease in general and administrative costs also results from other administrative cost reductions as part of our continued focus on efficiencies and cost savings. On a per unit basis, general and administrative expenses were $2.22 per Boe and $14.31 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

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Stock-based compensation expense was $0.6 million and a credit of $2.3 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Stock-based compensation expense decreased in the current period due to a reduction in our workforce. During the three months ended September 30, 2019 (Predecessor), senior executives resigned from their positions. In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the three months ended September 30, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $1.1 million associated with these modifications. Stock-based compensation expense also decreased in the prior year period due to a reduction in our workforce.

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 $15.3 million and $18.0 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, depletion expense was $9.76 per Boe and $11.89 per Boe for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The lower depletion rate in the Successor period is attributable to the change in our depletable base as a result of the adoption of fresh-start accounting and the full cost ceiling test impairment incurred in the three months ended June 30, 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 September 30, 2020 (Successor), we recorded a full cost ceiling impairment of $128.3 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 $47.37 per barrel at June 30, 2020 (Successor) to $43.63 per barrel at September 30, 2020 (Successor). The ceiling test impairment also reflects the transfer of $23.6 million of unevaluated property costs to the full cost pool due to our intent to focus available capital on Monument Draw. At September 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $45.6 million. The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in first-day-of-the-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-the-month average price for crude oil was $61.45 per barrel. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
​

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million. We recognized a cumulative $115.4 million gain on the sale which includes the $0.2 million increase in the three months ended September 30, 2019 (Predecessor) due to customary post-closing adjustments.

​

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 September 30, 2020 (Successor), we had a $28.7 million derivative asset, $19.0 million of which was classified as current, and we had a $12.3 million derivative liability, $9.1 million of which was classified as current. We recorded a net derivative loss of $15.8 million ($21.1 million net unrealized loss and $5.3 million net realized gain on settled and early terminated contracts) for the three months ended September 30, 2020 (Successor). During this period, we terminated certain derivative contracts in advance of their natural expiration dates and received proceeds of approximately $6.6 million, which were included in the $5.3 million net realized gains for the period. For the three months ended September 30, 2019 (Predecessor), we recorded a net derivative gain of $13.5 million ($11.6 million net unrealized gain and $1.9 million net realized gain on settled and early terminated contracts).
​

Interest expense and other was $1.7 million and $10.5 million for the three months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement and the PPP Loan. Interest expense in the Predecessor period

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represents interest associated with the Predecessor Credit Agreement and DIP Facility. In addition to interest expense, during the three months ended September 30, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

​

We recorded a net loss on reorganization items of $1.8 million for the three months ended September 30, 2019 (Predecessor) which includes the following:

​ | ​ | ​ | ​
​ | ​ | Predecessor
​ | ​ | Three Months
​ | ​ | Ended
​ | ​ | September 30, 2019
Accrued interest | ​ | $ | 20,274
Write-off debt discount/premium and debt issuance costs | ​ | ​ | (10,953)
Reorganization professional fees and other | ​ | ​ | (11,079)
Gain (loss) on reorganization items | ​ | $ | (1,758)

​

​

​

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Nine Months Ended September 30, 2020 (Successor) and 2019 (Predecessor)
​

We reported a net loss of $166.0 million and $1.0 billion for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The table included below sets forth financial information for the periods presented.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Successor | ​ | ​ | Predecessor
​ | ​ | Nine Months | ​ | ​ | Nine Months
​ | ​ | Ended | ​ | ​ | Ended
In thousands (except per unit and per Boe amounts) | ​ | September 30, 2020 | ​ | ​ | September 30, 2019
Net income (loss) | ​ | $ | (165,950) | ​ | ​ | $ | (1,040,687)
Operating revenues: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil | ​ | ​ | 91,313 | ​ | ​ | ​ | 145,024
Natural gas | ​ | ​ | 3,102 | ​ | ​ | ​ | 107
Natural gas liquids | ​ | ​ | 10,086 | ​ | ​ | ​ | 13,229
Other | ​ | ​ | 1,222 | ​ | ​ | ​ | 743
Operating expenses: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | ​ | 32,880 | ​ | ​ | ​ | 39,617
Workover and other | ​ | ​ | 2,767 | ​ | ​ | ​ | 5,580
Taxes other than income | ​ | ​ | 7,130 | ​ | ​ | ​ | 9,213
Gathering and other | ​ | ​ | 39,275 | ​ | ​ | ​ | 36,057
Restructuring | ​ | ​ | 2,580 | ​ | ​ | ​ | 15,148
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 11,444 | ​ | ​ | ​ | 44,585
Stock-based compensation | ​ | ​ | 1,793 | ​ | ​ | ​ | (8,035)
Depletion, depreciation and accretion: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depletion – Full cost | ​ | ​ | 46,931 | ​ | ​ | ​ | 84,579
Depreciation – Other | ​ | ​ | 796 | ​ | ​ | ​ | 6,026
Accretion expense | ​ | ​ | 440 | ​ | ​ | ​ | 307
Full cost ceiling impairment | ​ | ​ | 188,443 | ​ | ​ | ​ | 985,190
(Gain) loss on sale of Water Assets | ​ | ​ | — | ​ | ​ | ​ | 3,618
Other income (expenses): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Net gain (loss) on derivative contracts | ​ | ​ | 67,695 | ​ | ​ | ​ | (34,332)
Interest expense and other | ​ | ​ | (4,889) | ​ | ​ | ​ | (37,606)
Reorganization items, net | ​ | ​ | — | ​ | ​ | ​ | (1,758)
Income tax benefit (provision) | ​ | ​ | — | ​ | ​ | ​ | 95,791
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil – MBbls | ​ | ​ | 2,589 | ​ | ​ | ​ | 2,723
Natural Gas - MMcf | ​ | ​ | 6,437 | ​ | ​ | ​ | 6,381
Natural gas liquids – MBbls | ​ | ​ | 917 | ​ | ​ | ​ | 911
Total MBoe(1) | ​ | ​ | 4,579 | ​ | ​ | ​ | 4,698
Average daily production – Boe(1) | ​ | ​ | 16,712 | ​ | ​ | ​ | 17,209
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average price per unit (2): | ​ | ​ | ​ | ​ | ​ | ​ | ​
Oil price - Bbl | ​ | $ | 35.27 | ​ | ​ | $ | 53.26
Natural gas price - Mcf | ​ | ​ | 0.48 | ​ | ​ | ​ | 0.02
Natural gas liquids price - Bbl | ​ | ​ | 11.00 | ​ | ​ | ​ | 14.52
Total per Boe(1) | ​ | ​ | 22.82 | ​ | ​ | ​ | 33.71
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average cost per Boe: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Production: | ​ | ​ | ​ | ​ | ​ | ​ | ​
Lease operating | ​ | $ | 7.18 | ​ | ​ | $ | 8.43
Workover and other | ​ | ​ | 0.60 | ​ | ​ | ​ | 1.19
Taxes other than income | ​ | ​ | 1.56 | ​ | ​ | ​ | 1.96
Gathering and other | ​ | ​ | 8.58 | ​ | ​ | ​ | 7.67
Restructuring | ​ | ​ | 0.56 | ​ | ​ | ​ | 3.22
General and administrative: | ​ | ​ | ​ | ​ | ​ | ​ | ​
General and administrative | ​ | ​ | 2.50 | ​ | ​ | ​ | 9.49
Stock-based compensation | ​ | ​ | 0.39 | ​ | ​ | ​ | (1.71)
Depletion | ​ | ​ | 10.25 | ​ | ​ | ​ | 18.00

(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 $104.5 million and $158.4 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. For the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), production averaged 16,712 Boe/d and 17,209 Boe/d, respectively. Our average daily oil, natural gas and natural gas liquids production decreased in the nine months ended September 30, 2020 (Successor) when compared to the same period in the prior year primarily due to our temporary shut-in of a portion of producing wells across all our operating areas during the months of May and June 2020. Estimated downtime associated with these temporary shut-ins was approximately 1,800 Boe/d for the nine months ended September 30, 2020 (Successor). The production decline caused by temporary shut-ins in the current year period was partially offset by new wells put online since the prior year period. Average realized prices (excluding the effects of hedging arrangements) were $22.82 per Boe and $33.71 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease operating expenses were $32.9 million and $39.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, lease operating expenses were $7.18 per Boe and $8.43 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decrease in lease operating expenses in 2020 results from our focus on optimization of production operations and decreased salt water disposal costs due to lower production volumes and less produced water.

Workover and other expenses were $2.8 million and $5.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, workover and other expenses were $0.60 per Boe and $1.19 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decreased costs in 2020 relate to recent strides in improving well and completion designs and fewer workovers performed.

Taxes other than income were $7.1 million and $9.2 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), 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 $1.56 per Boe and $1.96 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Gathering and other expenses were $39.3 million and $36.1 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our gathering support infrastructure, gas treating fees, rig stacking charges and other. Approximately $9.0 million and $9.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Oil and natural gas production volumes were lower in the current period due to the temporary shut-in of a portion of producing wells during the months of May and June 2020. Approximately $26.9 million and $24.8 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities. In April 2019 (Predecessor), we installed a hydrogen sulfide treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Until the treating plant was operational, we incurred $10.9 million of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties during the nine months ended September 30, 2019 (Predecessor). Our produced natural gas from the Monument Draw area increased in the current year period, despite a decrease in our overall production volumes. These natural gas volumes are processed through our hydrogen sulfide treating plant in the area, which led to higher operating expenses, such as chemical costs, associated with our treating equipment during the current year period. Also included are $3.4 million and $0.8 million of rig stacking charges for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor).

Restructuring expense was approximately $2.6 million and $15.1 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. During the nine months ended September 30, 2020 (Successor), we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our

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workforce due to efforts to improve efficiencies and go forward costs. In May 2020 (Successor), 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. During the nine months ended September 30, 2019 (Predecessor), several senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally, during the 2019 period, we made the decision to consolidate into one corporate office located in Houston, Texas. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $11.4 million and $44.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits. Payroll and employee-related benefits decreased due to a reduction in our workforce since the prior year period. The decrease in general and administrative costs also results from other administrative cost reductions as part of our continued focus on efficiencies and cost savings. On a per unit basis, general and administrative expenses were $2.50 per Boe and $9.49 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively.

Stock-based compensation expense was $1.8 million and a credit of $8.0 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. During the nine months ended September 30, 2019 (Predecessor), several senior executives resigned from their positions. In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon terminations. For the nine months ended September 30, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $9.5 million associated with these modifications. Stock-based compensation expense also decreased in the current period due to a reduction in our workforce.

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 $46.9 million and $84.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. On a per unit basis, depletion expense was $10.25 per Boe and $18.00 per Boe for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. The lower depletion rate in the Successor period is attributable to the change in our depletable base as a result of the adoption of fresh-start accounting and the full cost ceiling test impairment incurred in the three months ended June 30, 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 September 30, 2020 (Successor), we recorded a full cost ceiling impairment of $128.3 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 $47.37 per barrel at June 30, 2020 (Successor) to $43.63 per barrel at September 30, 2020 (Successor). The ceiling test impairment also reflects the transfer of $23.6 million of unevaluated property costs to the full cost pool due to our intent to focus available capital on Monument Draw. At June 30, 2020 (Successor), 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 (Successor) to $47.37 per barrel at June 30, 2020 (Successor). This average price decline was partially offset by favorable differentials and lower operating expenses. We recorded a full cost ceiling test impairment charge of $985.2 million for the nine months ended September 30, 2019 (Predecessor). The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in the first-day-of-the-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-month average price for crude oil was $61.45 per barrel. At June 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $664.4 million. The ceiling test impairment at June 30, 2019 (Predecessor) was primarily driven by our continued focus on Monument Draw. Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019 (Predecessor), the majority of which was associated with our Hackberry Draw area. At March 31, 2019 (Predecessor), we recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 (Predecessor) was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling

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test calculation and our intent to expend capital only on our most economic areas. As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019 (Predecessor). Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

​

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million. We recognized a cumulative $115.9 million gain on the sale. The gain was reduced during the nine months ended September 30, 2019 by approximately $3.6 million as a result of customary post-closing adjustments.

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 September 30, 2020 (Successor), we had a $28.7 million derivative asset, $19.0 million of which was classified as current, and we had a $12.3 million derivative liability, $9.1 million of which was classified as current. We recorded a net derivative gain of $67.7 million ($24.0 million net unrealized gain and $43.7 million net realized gain on settled and early terminated contracts) for the nine months ended September 30, 2020 (Successor). During the nine months ended September 30, 2020 (Successor), we terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million, which were included in the $43.7 million net realized gain for the period. For the nine months ended September 30, 2019 (Predecessor), we recorded a net derivative loss of $34.3 million ($45.8 million net unrealized loss and $11.5 million net realized gain on settled and early terminated contracts).

Interest expense and other was $4.9 million and $37.6 million for the nine months ended September 30, 2020 (Successor) and 2019 (Predecessor), respectively. Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement and the PPP loan. Interest expense in the Predecessor period represents interest associated with the Predecessor Credit Agreement, the DIP Facility and the 6.75% senior notes. In addition to interest expense, during the nine months ended September 30, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

We recorded a net loss on reorganization items of $1.8 million for the nine months ended September 30, 2019 (Predecessor) which includes the following:

​ | ​ | ​ | ​
​ | ​ | Predecessor
​ | ​ | Nine Months
​ | ​ | Ended
​ | ​ | September 30, 2019
Accrued interest | ​ | $ | 20,274
Write-off debt discount/premium and debt issuance costs | ​ | ​ | (10,953)
Reorganization professional fees and other | ​ | ​ | (11,079)
Gain (loss) on reorganization items | ​ | $ | (1,758)

​

We recorded an income tax benefit of $95.8 million for the nine months ended September 30, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the ceiling test impairment on oil and gas properties and the deferred tax asset created by the tax loss from operations. The 8.4% effective tax rate for the nine months ended September 30, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation and non-deductible realized built in losses, and valuation allowances on deferred tax assets.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item1. Condensed Consolidated Financial Statements (Unaudited)—Note 1, “Financial Statement Presentation.”

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, 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 at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile 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 September 30, 2020 (Successor), 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 10, “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, restricted cash, accounts receivable, noncurrent accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 9, “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 September 30, 2020 (Successor), the principal amount of our debt was $180.2 million, of which approximately 1.2% bears interest at a weighted average fixed interest rate of 1.0% per year. The remaining 98.8% of our total debt at September 30, 2020 (Successor) 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 September 30, 2020 (Successor), the weighted average interest rate on our variable rate debt was 3.8% per year. If the balance of our variable interest rate at September 30, 2020 (Successor) 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 September 30, 2020

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(Successor). 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 September 30, 2020 (Successor) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings to which we are a party is set forth in Item 1. Condensed Consolidated Financial Statements (Unaudited)—Note 12, “Commitments and Contingencies,” which is incorporated herein by reference.

​

ITEM 1A. RISK FACTORS

​

There have been no changes to the risk factors described in our 2019 Annual Report on Form 10-K, for the fiscal year ended December 31, 2019 (Successor), except as described below.

​

Events beyond our control, including a global or domestic health crisis, may result in unexpected adverse operating and financial results.

​

In response to the novel coronavirus (COVID-19) pandemic governments around the world, including U.S. federal and state governments, have imposed restrictions intended to limit the extent and spread of the virus, including travel restrictions, quarantines and business closures. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting and lead to disruptions in our permitting activities and critical business relationships. Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the potential for future outbreaks are uncertain and difficult to predict. COVID-19 or another similar outbreak may negatively impact our business in numerous ways, including, but not limited to, the following:

​

| ● | reducing our revenues if the outbreak results in a substantial or prolonged decrease in demand for oil and natural gas due to an economic downturn or recession;

​

| ● | disrupting our operations if our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to measures designed to contain the outbreak;

​

| ● | disrupting the operations of our midstream service providers, on whom we rely for the gathering, processing and transportation of our production, due to measures designed to contain the outbreak, and/or the difficult economic environment may lead to capital spending constraints, bankruptcy, the closing of facilities or inability to maintain infrastructure, which may adversely affect our ability to market our production, increase our costs, lower the prices we receive, or result in the shut-in of our producing wells or a delay or discontinuation of our development plans; and

​

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| ● | the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to access capital, monetize assets and successfully execute our plans.

​

The COVID-19 pandemic may also have the effect of heightening many of the other risks set forth in Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2019 (Successor). Any of these factors could have a material adverse effect on our business, operations, financial results and liquidity. Recently, oil and natural gas prices declined to historically low levels and we reduced our planned capital expenditures, delayed our drilling and completion plans and temporarily shut-in some of our producing wells, among other responses. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the pandemic continues, its ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased.

​

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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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).
10.12*† | ​ | Employment Agreement between R. Kevin Andrews and Battalion Oil Corporation effective as of August 17, 2020.
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* | ​ | XBRL Instance Document
101.SCH* | ​ | XBRL Taxonomy Extension Schema Document
101.CAL* | ​ | XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* | ​ | XBRL Taxonomy Extension Definition Document
101.LAB* | ​ | XBRL Taxonomy Extension Label Linkbase Document
101.PRE* | ​ | XBRL Taxonomy Extension Presentation Linkbase 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
​ | ​
​ | ​
November 9, 2020 | By: | /s/ RICHARD H. LITTLE
​ | ​ | Name: | Richard H. Little
​ | ​ | Title: | Chief Executive Officer
​ | ​ | ​
​ | ​ | ​
November 9, 2020 | By: | /s/ R. KEVIN ANDREWS
​ | ​ | Name: | R. Kevin Andrews
​ | ​ | Title: | Executive Vice President, Chief Financial Officer and Treasurer

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