Battalion Oil 10K 2020 Annual report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

Commission File Number: 001-35467

Battalion Oil Corporation

(Exact name of registrant as specified in its charter)

Delaware	20-0700684
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

1000 Louisiana Street, Suite 6600, Houston, TX 77002

(Address of principal executive offices)

(832) 538-0300

(Registrant’s telephone number)

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


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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒

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

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☒

Smaller reporting company ☒

Emerging growth company ☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

As of March 4, 2021, there were 16,267,157 shares outstanding of registrant’s $.0001 par value common stock. Based upon the closing price for the registrant’s common stock on the New York Stock Exchange as of June 30, 2020, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $24.1 million.

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 ☐

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13, and 14, is incorporated by reference to portions of the registrant’s definitive proxy statement for its 2021 annual meeting of stockholders which will be filed no later than 120 days after December 31, 2020.

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TABLE OF CONTENTS

		PAGE
PART I
ITEM 1.	Business	8
ITEM 1A.	Risk factors	24
ITEM 1B.	Unresolved staff comments	39
ITEM 2.	Properties	39
ITEM 3.	Legal proceedings	39
ITEM 4.	Mine safety disclosures	39
PART II
ITEM 5.	Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities	40
ITEM 6.	Selected financial data	40
ITEM 7.	Management’s discussion and analysis of financial condition and results of operations	41
ITEM 7A.	Quantitative and qualitative disclosures about market risk	59
ITEM 8.	Consolidated financial statements and supplementary data	61
ITEM 9.	Changes in and disagreements with accountants on accounting and financial disclosure	118
ITEM 9A.	Controls and procedures	118
ITEM 9B.	Other information	118
PART III
ITEM 10.	Directors, executive officers and corporate governance	118
ITEM 11.	Executive compensation	119
ITEM 12.	Security ownership of certain beneficial owners and management and related stockholder matters	119
ITEM 13.	Certain relationships and related transactions, and director independence	119
ITEM 14.	Principal accountant fees and services	119
PART IV
ITEM 15.	Exhibits and financial statements schedules	119
ITEM 16.	Form 10-K Summary	121

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Special note regarding forward-looking statements

This Annual Report on Form 10-K 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 this report and other sections of this report 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:

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

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

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

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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;

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we have historically had substantial indebtedness and we may incur more debt in the future;

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higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

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

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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;

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

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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;

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

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

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

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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;

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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;

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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;

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

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competition, including competition for acreage in our resource play;

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environmental risks;

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exploration and development risks;

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

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

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social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or acts of terrorism or sabotage;

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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;

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

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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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Glossary of Oil and Natural Gas Terms

The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas differs significantly from the price for a barrel of oil. A barrel of NGLs also differs significantly in price from a barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed property. Property where wells have been drilled and production equipment has been installed.

Development well. A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Extension well. A well drilled to extend the limits of a known reservoir.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Hydraulic fracturing. The injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

H2S. Hydrogen sulfide, a colorless, flammable and extremely hazardous naturally occurring gas that is sometimes produced from oil and natural gas wells.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

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MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million Boe.

MMBtu. One million Btu.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs. Natural gas liquids, i.e. hydrocarbons removed as a liquid, such as ethane, propane and butane.

Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves. Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reserve-to-production ratio or Reserve life. A ratio determined by dividing estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud. Commencement of actual drilling operations.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

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Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

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PART I

ITEM 1. BUSINESS

Overview

Unless the context otherwise requires, all references in this report to “Battalion,” “our,” “us,” and “we” refer to Battalion Oil Corporation and its subsidiaries, as a common entity. Battalion is the successor reporting company to Halcón Resources Corporation (Halcón). On January 21, 2020, we filed a Certificate of Amendment to our Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of our corporate name from Halcón Resources Corporation to Battalion Oil Corporation.

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy on October 8, 2019. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019, the convenience date applied for fresh-start accounting. 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. Refer to Item 8. Consolidated Financial Statements and Supplementary Data – Note 2, “Reorganization” and Note 3, “Fresh-start Accounting,” for further details.

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.

At December 31, 2020 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell) using the Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average prices of West Texas Intermediate (WTI) crude oil spot price of $39.54 per Bbl and Henry Hub natural gas spot price of $1.99 per MMBtu, were approximately 63.4 MMBoe, consisting of 38.2 MMBbls of oil, 12.1 MMBbls of natural gas liquids, and 78.5 Bcf of natural gas. Approximately 57% of our estimated proved reserves were classified as proved developed as of December 31, 2020 (Successor). We maintain operational control of 99.9% of our estimated proved reserves.

Our total operating revenues for the year ended December 31, 2020 (Successor) were approximately $148.3 million, compared to total operating revenues for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) of approximately $65.6 million and $159.1 million, respectively, or $224.7 million combined. Full year 2020 (Successor) production averaged 16,858 Boe/d. During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, or 17,986 Boe/d combined. The decrease in total operating revenues and average daily production year over year was driven by 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 as well as average realized prices that were lower by approximately $10.25 per Boe. The estimated production decrease associated with these temporary shut-ins was approximately 1,300 Boe/d for 2020 (Successor). In December 2020 (Successor), we divested properties that produced approximately 600 Boe/d during the nine months ended September 30, 2020 (Successor). In 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.

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Recent Developments

Risk and Uncertainties

We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including 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 subsequently agreed 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 ongoing effects 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 (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. The results presented in this Form 10-K 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 Annual Report on Form 10-K.

Northern West Quito Assets Divestiture

On December 18, 2020 (Successor), we sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total sales price of $26.3 million in cash, subject to customary post-closing adjustments as provided in the Purchase and Sale Agreement. The effective date of the transaction was October 1, 2020 (Successor). Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded. We used the net proceeds from the sale to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes. Estimated proved reserves associated with the North West Quito Assets were approximately 2 MMBoe, or approximately 3% of our year-end 2019 proved reserves. The North West Quito Assets generated net production of approximately 600 Boe/d, or approximately 4% of our average daily production for the nine months ended September 30, 2020 (Successor).

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, set the borrowing base to $190.0 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (discussed below). The Third Amendment also reduced the amount available for issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the

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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 Limited Waiver to Senior Secured Revolving Credit Agreement 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 for 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 (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.

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 covered period after loan origination and the maintenance or achievement of certain employee levels. We believe we are eligible for, and intend to pursue, 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.

Acid Gas Injection Well Permits

During the year ended December 31, 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.

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

2021 Capital Budget

We expect to spend approximately $40.0 million to $50.0 million on capital expenditures during 2021. Overall, we currently plan to drill two gross operated wells during the year, complete six gross operated wells, and bring six gross operated wells on production. Our 2021 capital budget currently contemplates running one operated rig in the Delaware Basin at the beginning of the year. We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve core acreage and meet contractual obligations, and therefore our capital budget is subject to change.

We expect to fund our budgeted 2021 capital expenditures with cash and cash equivalents on hand, cash flows from operations and, if necessary, borrowings under our Senior Credit Agreement. In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending.

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 predominately 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.

Business Strategy

Our primary long-term objective is to increase stockholder value by safely and cost-effectively increasing our production of oil, natural gas and natural gas liquids, adding to our proved reserves and growing our inventory of economic drilling locations, while acting as a responsible corporate citizen in the areas in which we operate. To accomplish this objective, we intend to execute the following business strategies:

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Develop our Liquids-Rich Acreage Positions to Grow Production and Reserves Efficiently. We intend to drill and develop our multi-zone resource play to maximize value and resource potential. Our near-term development plans are focused on production growth and acreage preservation in our liquids-rich Monument Draw area.

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Enhance Returns Through Continued Improvements in Operational and Cost Efficiencies. We are the operator for the majority of our acreage, which gives us control over the timing of capital expenditures, execution and costs. It also allows us to adjust our capital spending based on drilling results and the economic environment. As operator, we are able to evaluate industry drilling results and implement improved operating practices that may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital. In addition to operational efficiencies, we continue to implement cost-saving measures to reduce corporate administrative expenses.

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Maintain Strong Balance Sheet and Financial Flexibility. Our management team is focused on maintaining a strong balance sheet, which we intend to achieve through conservative use of leverage and continued improvements on rates of return. We believe our internally-generated cash flows and borrowing capacity under our Senior Credit Agreement will provide us with sufficient liquidity to execute our current capital program and strategy. We have no material near-term debt maturities. We also employ a hedging program to reduce the variability of our cash flows used to support our capital spending.

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Attain Growth Through Strategic Business Combinations. We intend to pursue merger and acquisition opportunities to meet our strategic and financial targets, including the maintenance of a conservative leverage position. Selective business combinations provide opportunities to acquire high quality assets complementary to our core acreage, expand our drilling inventory and gain operational scale. We believe our management team’s geologic and engineering expertise, particularly in the Permian Basin, provides a competitive advantage in the identification of acquisition targets and evaluation of resource potential.

Oil and Natural Gas Reserves

The proved reserves estimates reported herein for the years ended December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves reports incorporated herein are Mr. Neil H. Little and Mr. Edward C. Roy III. Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at Netherland, Sewell since 2011 and has over nine years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from University of Houston in 2007 with a Master of Business Administration Degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at Netherland, Sewell since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology. Netherland, Sewell has reported to us that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are both proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our board of directors has established a reserves committee composed of independent directors with experience in energy company reserve evaluations. Our independent engineering firm reports jointly to the reserves committee and to our Executive Vice President and Chief Operating Officer. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to our board of directors as to whether to approve the report prepared by our independent engineering firm. Mr. Daniel P. Rohling, our Executive Vice President and Chief Operating Officer is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. He has more than 14 years of oil and gas operations experience and earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is an active member of the Society of Petroleum Engineers.

The reserves information in this Annual Report on Form 10-K represents only estimates. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary significantly. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. For additional information regarding estimates of proved reserves, the preparation of such estimates by Netherland, Sewell and other information about our oil and natural gas reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).”

Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2020 (Successor). Average prices for the 12-month period were as follows: WTI crude oil spot price of $39.54 per Bbl, adjusted by lease or field for quality, transportation fees, and market

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differentials and a Henry Hub natural gas spot price of $1.99 per MMBtu, as adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.

The following table presents certain proved reserve information as of December 31, 2020 (Successor).


Proved Reserves (MBoe)⁽¹⁾
Developed		36,232
Undeveloped		27,143
Total		63,375

(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.

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2020 and 2019 (Successor). Shut-in wells currently not capable of production are excluded from the well information below.


	Years Ended December 31,
	2020		2019
	Gross	Net	Gross	Net
Oil	151	129.6	122	94.1
Natural Gas	13	10.2	11	7.7
Total	164	139.8	133	101.8

Oil and Natural Gas Production

Core Resource Play—Delaware Basin

We have working interests in 41,676 net acres in the Delaware Basin as of December 31, 2020 (Successor) in Pecos, Reeves, Ward and Winkler Counties, Texas. This core resource play is characterized by high oil and liquids-rich natural gas content in thick, continuous sections of source rock that can provide repeatable drilling opportunities and significant initial production rates. Our primary targets in this area are the Wolfcamp and Bone Spring formations. As of December 31, 2020 (Successor), we had 113 operated wells producing in this area in addition to minor working interests in 8 non-operated wells. Our average daily net production from this area for the year ended December 31, 2020 (Successor) was 16,790 Boe/d. As of December 31, 2020 (Successor), estimated proved reserves for the Delaware Basin were approximately 63.3 MMBoe, of which approximately 57% were classified as proved developed and approximately 43% as proved undeveloped.

Risk Management

We have designed a risk management policy for the use of derivative instruments to provide partial protection against certain risks relating to our ongoing business operations, such as commodity price declines and price differentials between the NYMEX commodity price and the index price at the location where our production is sold. Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. Our objective generally is to hedge 65-85% of our anticipated oil and natural gas production for up to 30 months. However, our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions, provided, however, that under our Senior Credit Agreement we are contractually obligated to hedge no less than 65% of our anticipated production under swap contracts through at least December 31, 2022. Our hedge policies and objectives change as our operational profile changes. Our future performance is subject to commodity price risks and our future cash flows from operations may be volatile. We do not enter into derivative contracts for speculative trading purposes.

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While there are many different types of derivatives available, we typically use fixed-price swap, costless collar, basis swap, and WTI NYMEX roll agreements to attempt to manage price risk. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. 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.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. As of December 31, 2020 (Successor), we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Consolidated Financial Statements and Supplementary Data—Note 10, “Derivative and Hedging Activities,” for additional information.

Oil and Natural Gas Operations

Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties. Generally, our oil and natural gas leases remain in force as long as production in paying quantities is maintained. Leases on undeveloped oil and natural gas properties are typically for a primary term of three to five years within which we are generally required to develop the property or the lease will expire. In some cases, the primary term of leases on our undeveloped properties can be extended by option payments; the amount of any payments and time extended vary by lease. The table below sets forth the results of our drilling activities for the periods indicated:


	Years Ended December 31,
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive ⁽¹⁾	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total Exploratory	—	—	—	—	—	—
Extension Wells:
Productive ⁽¹⁾	—	—	11	9.9	15	12.5
Dry	—	—	—	—	—	—
Total Extension	—	—	11	9.9	15	12.5
Development Wells:
Productive ⁽¹⁾	7	6.3	7	6.1	15	15.0
Dry	—	—	—	—	—	—
Total Development	7	6.3	7	6.1	15	15.0
Total Wells:
Productive ⁽¹⁾	7	6.3	18	16.0	30	27.5
Dry	—	—	—	—	—	—
Total	7	6.3	18	16.0	30	27.5

⁽¹⁾	Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly extension or exploratory wells where there is no production history.

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We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying provisions. The following table presents a summary of our acreage interests as of December 31, 2020 (Successor):


	Developed Acreage		Undeveloped Acreage		Total Acreage
State	Gross	Net	Gross	Net	Gross	Net
North Dakota	3,510	694	33,981	13,945	37,491	14,639
Texas	30,038	28,098	14,663	13,578	44,701	41,676
Total Acreage	33,548	28,792	48,644	27,523	82,192	56,315

The table below reflects the percentage of our total net undeveloped acreage as of December 31, 2020 (Successor) that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included or do not pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease.


Year	Percentage Expiration
2021	10	%
2022	39	%
2023	—	%
2024 & beyond	51	%
	100	%

Of the acreage with 2021 and 2022 expiration dates, approximately 450 and zero net acres, respectively, relate to our core area of operations. We continually review our near-term lease expirations to preserve acreage in our core area of operations, either through our drilling program or through lease extensions or renewals, if necessary. We have no current plans to drill on acreage in areas outside of our core area of operations.

At December 31, 2020 (Successor), we had estimated proved reserves of approximately 63.4 MMBoe comprised of 38.2 MMBbls of crude oil, 12.1 MMBbls of natural gas liquids, and 78.5 Bcf of natural gas. The following table sets forth these reserves:


	Proved	Proved	Total
	Developed	Undeveloped	Proved
Oil (MBbls)	20,371	17,845	38,216
Natural Gas Liquids (MBbls)	7,345	4,730	12,075
Natural Gas (MMcf)	51,097	27,409	78,506
Equivalent (MBoe)⁽¹⁾	36,232	27,143	63,375

(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.

At December 31, 2020 (Successor), total estimated proved reserves were approximately 63.4 MMBoe, a 1.3 MMBoe net increase from the previous year’s estimate of 62.1 MMBoe. The net increase in total proved reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by production of 6.2 MMBoe, sales of 2.0 MMBoe, and negative revisions of 2.9 MMBoe due primarily to decreases in SEC pricing.

At December 31, 2020 (Successor), our estimated proved undeveloped (PUD) reserves were approximately 27.1 MMBoe, a 3.0 MMBoe net increase from the previous year’s estimate of 24.1 MMBoe. The net increase in total PUD reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by development of 6.5 MMBoe and negative revisions of 2.8 MMBoe due primarily to decreases in SEC pricing.

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As of December 31, 2020 (Successor), all of our PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2020, approximately $43.3 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line openhole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells. We relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves. Out of total PUD reserves of 27.1 MMBoe at December 31, 2020 (Successor), 13.7 MMBoe were associated with 15 gross PUD locations that were more than one offset location from a producing well.

The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. For additional information on our oil and natural gas reserves, including a table detailing the changes by year of our proved reserves, see Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).” We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations. Accordingly, all costs incurred in the acquisition, exploration, and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, direct internal costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test. See further discussion in Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, “Oil and Natural Gas Properties.”

Capitalized costs of our evaluated and unevaluated properties at December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) are summarized as follows (in thousands):


	Successor				Predecessor
	December 31, 2020		December 31, 2019		December 31, 2018
Oil and natural gas properties (full cost method):
Evaluated	$	509,274	$	420,609	$	1,470,509
Unevaluated		75,494		105,009		971,918
Gross oil and natural gas properties		584,768		525,618		2,442,427
Less - accumulated depletion		(295,163)		(19,474)		(639,951)
Net oil and natural gas properties	$	289,605	$	506,144	$	1,802,476

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The following table summarizes our oil, natural gas and natural gas liquids production volumes, average sales price per unit and average costs per unit:


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Production:
Crude oil - MBbl
Delaware		3,430		1,050		2,718		3,544
Other		16		7		5		14
Total		3,446		1,057		2,723		3,558
Natural gas - MMcf
Delaware		8,744		2,754		6,378		4,607
Other		25		1		3		—
Total		8,769		2,755		6,381		4,607
Natural gas liquids - MBbl
Delaware		1,258		351		911		749
Other		4		—		—		—
Total		1,262		351		911		749

Production:
Total MBoe ⁽¹⁾		6,170		1,867		4,698		5,075
Average daily production - Boe ⁽¹⁾		16,858		20,293		17,209		13,904

Average price per unit (excluding impact of settled derivatives):
Crude oil price - Bbl	$	36.56	$	55.18	$	53.26	$	56.10
Natural gas price - Mcf		0.66		0.62		0.02		1.47
Natural gas liquids price - Bbl		11.86		14.45		14.52		25.55
Barrel of oil equivalent price - Boe ⁽¹⁾		23.79		34.88		33.71		44.44

Average price per unit (including impact of settled derivatives)⁽²⁾:
Crude oil price - Bbl	$	48.87	$	54.15	$	52.33	$	56.82
Natural gas price - Mcf		0.94		0.81		0.96		1.90
Natural gas liquids price - Bbl		11.86		21.76		23.90		30.68
Barrel of oil equivalent price - Boe ⁽¹⁾		31.07		35.94		36.26		46.09

Average cost per Boe:
Production:
Lease operating	$	6.82	$	6.86	$	8.43	$	4.94
Workover and other		0.60		0.89		1.19		1.69
Taxes other than income		1.63		2.00		1.96		2.52
Gathering and other		9.08		5.79		7.67		11.84

(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)	Cash paid on, or cash received from, settled derivative contracts are reflected as “Net gain (loss) on derivative contracts” in the consolidated statements of operations, consistent with our decision not to elect hedge accounting.

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Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers, transporters and take-away capacity for the oil and natural gas we produce and hiring and retaining key employees. There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and the states in which our properties are located. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Other Business Matters

Markets and Major Customers

The purchasers of our oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, we have not experienced any significant losses from uncollectible accounts. In 2020 (Successor), two individual purchasers of our production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 57% of our total sales for the year. For the combined periods of October 2, 2019 through December 31, 2019 (Successor), and January 1, 2019 through October 1, 2019 (Predecessor), two individual purchasers of our production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 80% of our total sales for the period. In 2018 (Predecessor), two individual purchasers of our production, Western Refining Inc. and Sunoco, Inc., each accounted for more than 10% of total sales, collectively representing 77% of our total sales for the year.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for crude oil can often be higher in the summer months during the peak travel season. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Operational Risks

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to be overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental releases of toxic or hazardous materials, such as hydrogen sulfide, petroleum liquids, or drilling fluids into the environment, or cause significant injury to persons or property. In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position or cash flows. For further discussion on risks see Item 1A. Risk Factors.

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Regulations

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases. In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.

The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Environmental Regulations

Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the United States Environmental Protection Agency, commonly referred to as the EPA, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

Beyond existing requirements, new programs and changes in existing programs may address various aspects of our business, including naturally occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons may include the current or former owner or operator of the disposal site or sites where the release occurred and companies

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that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances released into the environment, for damages to natural resources and for the costs of some health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste. Periodically, however, there are proposals to reclassify oil and gas wastes as hazardous wastes or to subject them to enhanced solid waste regulation. If such proposals were to be enacted, they could have a significant impact on our operating costs and on those of all the industry in general.

In the ordinary course of our operations, moreover, we do handle materials that may be subject to extensive existing RCRA regulations or that may be classified as hazardous substances under CERCLA. From time to time, releases of those materials have occurred at locations we own or at which we have operations. Under CERCLA, RCRA and analogous state laws, we have been and may be required to remove or remediate such materials.

Water Discharges

Our operations also may be subject to the federal Clean Water Act and analogous state statutes. Those laws regulate discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. These laws also require the preparation and implementation of spill prevention, control, and countermeasure plans in connection with on-site storage of significant quantities of oil. In the event of a discharge of oil into U.S. waters, we could be liable under the Oil Pollution Act for cleanup costs, damages and economic losses.

Our oil and natural gas production also generates salt water, which we dispose of by underground injection. The federal Safe Drinking Water Act (SDWA), the Underground Injection Control (UIC) regulations promulgated under the SDWA, and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

Our completion operations are subject to regulations that may become more stringent in either the short- or long-term. In particular, the well completion technique known as hydraulic fracturing, which is used to stimulate production of oil and natural gas, has come under increased scrutiny by the environmental community, and many local, state and federal regulators. Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depths to stimulate oil and natural gas production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

Working at the direction of Congress, the EPA issued a study in 2016 finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. The EPA also promulgated pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants. Environmental groups have encouraged the EPA to supplement those requirements. Various members of Congress likewise have from time to time introduced bills that would result in more stringent control or outright bans of the hydraulic fracturing process.

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In addition, the Department of the Interior promulgated regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations. While the Trump Administration rescinded those rules, that decision is being challenged in court. Regardless of how the federal issues are eventually resolved, states have been imposing new restrictions or bans on hydraulic fracturing. Even local jurisdictions, such as Denton, Texas and several cities in Colorado, have adopted, or tried to adopt, regulations restricting hydraulic fracturing. Additional hydraulic fracturing requirements at the federal, state or local level may limit our ability to operate or increase our operating costs.

Air Emissions

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of other requirements. In addition, the EPA has developed and may continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

In 2012 and 2016, the EPA issued air regulations for the oil and natural gas industry that address emissions from certain new sources of volatile organic compounds, sulfur dioxide, air toxics, and methane. The rules included the first federal air standards for natural gas and oil wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks. Although the EPA later made technical amendments to reduce the regulatory burden of the 2012 and 2016 rules, compliance has imposed additional requirements and costs on our operations.

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation has been ongoing and has resulted in expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas could be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response, governments increasingly have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and several countries, including those comprising the European Union, have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have been implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emissions targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration took a variety of steps to address climate change. For example, the EPA issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from oil and natural gas facilities. Beyond its measuring and reporting rules, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step in issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

In addition, the Obama Administration developed a Strategy to Reduce Methane Emissions that was intended to result by 2025 in a 40-45% decrease in methane emissions from the oil and gas industry as compared to 2012 levels.

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Consistent with that strategy, the EPA issued air rules for oil and gas production sources, and the federal Bureau of Land Management (BLM) promulgated standards for reducing venting and flaring on public lands.

The Trump Administration tried to roll back many of the Obama-era climate change policies and rules. But shortly after his inauguration, President Biden accepted the Paris Agreement on behalf of the United States, declared climate considerations an essential part of the United States’ foreign policy, issued a moratorium on new oil and gas leases on federal lands, and directed federal agencies to incorporate climate change considerations in their operations. Thus, new federal programs relating to climate change appear to be likely over at least the next four years.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions control systems or other compliance costs, and reduce demand for our products.

The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Threatened and endangered species, migratory birds, and natural resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Water Act. The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

Human Capital

Employees

At Battalion, our success is delivered through our highly capable and diverse workforce. Our team is comprised of individuals with extensive technical, industry and other professional experience. By recruiting, hiring and retaining an experienced and diverse team, we are able to leverage years of experience, new ideas and problem solving in a collaborative environment. As of December 31, 2020 (Successor), we had 60 full-time employees. We also engage the services of independent contractors and consultants along with certain professional service firms to support our work in specific areas. We have no collective bargaining agreements with our employees. We believe that we have good relations with our employees.

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Driving and Supporting a Safety First Culture

The safety of our employees, contractors and the communities in which we operate is one of our most critical responsibilities. We believe that driving a safety culture requires daily prioritization and includes a multi-faceted approach to provide our employees with the tools, support, education and incentives to operate safely.

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All employees, contractors and consultants performing work in the field participate in ongoing environmental, health and safety engagements including training, routine meetings, and individual coaching

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Work stop authority – all of our employees and contractors have a responsibility to intercede and stop observed high hazard activities or conditions without proper controls

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Policies and procedures implemented to support a safe working environment

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Environmental and safety metrics measuring performance linked to compensation

Our employees and contractors are educated on the risks inherent in our operations and are equipped with the tools necessary to ensure they can operate safely.

COVID-19 Response

In response to the COVID-19 pandemic, we implemented changes to ensure the health and safety of our employees and the communities where we operate. We complied with the guidelines published by the Centers for Disease Control or mandated by local authorities. We implemented work from home arrangements for our staff employees and additional safety measures for those continuing critical on-site work in the field including social distancing, masks, testing, self-reporting and procedures for those testing positive.

Compensation and Benefits

We have designed our compensation program to attract and retain talented employees with the requisite knowledge and experience. We offer market-competitive compensation programs, as well as strong health and welfare benefits along with a competitive 401(k) program. We have designed paid time off policies to allow our employees time off for family and other priorities. We have operational and financial metrics tied to our short-term incentives that align with our business strategy and the interests of our stockholders.

Diversity and Inclusion

We believe all employees should be treated fairly and valued in our organization. Diversity of thoughts and experiences allows us to identify the best solutions within our company. All Battalion employees must act in accordance with our Employee Handbook, which is inclusive of our Code of Conduct. The Employee Handbook covers various topics including, among others, policies prohibiting harassment, discrimination and retaliation and policies covering workplace anti-violence, cybersecurity, confidential information and conduct. On an annual basis, employees are required to acknowledge and agree to abide by these policies.

Principal Office

As of December 31, 2020 (Successor), we leased corporate office space in Houston, Texas at 1000 Louisiana Street.

Access to Company Reports

We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Securities Exchange Act of 1934, as amended. We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Forms 3, 4 and 5 filed on behalf of directors and officers, and any amendments to such reports, available free of charge through our corporate website at www.battalionoil.com as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. In addition, our insider trading policy,

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regulation FD policy, corporate governance guidelines, code of conduct, code of ethics, audit committee charter, compensation committee charter, nominating and corporate governance committee charter and reserves committee charter are available on our website under the heading “Investors—Corporate Governance”. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the code of conduct and the code of ethics for our chief executive officer and senior financial officers and any waivers applicable to senior officers as defined in the applicable code, as required by the Sarbanes-Oxley Act of 2002. In addition, our reports, proxy and information statements, and our other filings are also available to the public over the internet at the SEC’s website at www.sec.gov. Unless specifically incorporated by reference in this Annual Report on Form 10-K, information that you may find on our website is not part of this report.

ITEM 1A. RISK FACTORS

COVID-19 Risk Factors

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:

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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;

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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;

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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 below. 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.

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A financial downturn could negatively affect our business, results of operations, financial condition and liquidity.

Actual or anticipated declines in domestic or foreign economic 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 we receive for our oil and natural gas production, inhibiting our lenders from funding borrowings under our Senior Credit Agreement or resulting in our lenders reducing 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, the borrowing capacity under our Senior Credit Agreement.

Operational Risk Factors

We are substantially dependent upon our drilling success on our Delaware Basin properties.

We are a pure-play, single-basin operator in the Delaware Basin in West Texas. As a consequence of this geographical concentration, we may have greater exposure to the impact of regional supply and demand factors, delays or interruptions in production from governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, or other conditions adversely impacting our ability to produce or market our production. Such events could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted rates of return.

Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon current and future market prices for our oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. The costs of drilling and completing a well are often uncertain, and are affected by many factors, including:

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unexpected drilling conditions;

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pressure or irregularities in formations;

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equipment failures or accidents and shortages or delays in the availability of drilling and completion equipment and services;

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adverse weather conditions; and

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compliance with governmental requirements.

If we are unable to accurately predict and control the costs of drilling and completing a well, we may be forced to limit, delay or cancel drilling operations.

We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate enough cash flow from operations or be able to raise sufficient capital to do so. Commodities pricing may also make drilling

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some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we conduct may not be successful or result in additional proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

As of December 31, 2020 (Successor), we owned leasehold interests in approximately 41,700 net acres in the Delaware Basin in West Texas of which approximately 13,600 net acres are undeveloped. Unless production in paying quantities is established on units containing these leases during their terms or unless we pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties. We have no current plans to drill on acreage in other areas outside of our core area of operations.

Our drilling plans are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. As a non-operating leaseholder we have less control over the timing of drilling and are therefore subject to additional risk of expirations.

Our oil and natural gas activities are subject to various risks that are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest. Such risks and hazards include:

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human error, accidents and other events beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

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blowouts, fires, adverse weather events, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

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accidental leaks of natural gas, including gas with high levels of hydrogen sulfide (H2S), and other hydrocarbons or toxic or hazardous materials in the environment as a result of human error or the malfunction of equipment or facilities, which can result in personal injury and loss of life, pollution, damage to equipment and suspension of operations;

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well-on-well interference that may reduce recoveries;

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unavailability of materials and equipment;

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engineering and construction delays;

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unanticipated transportation costs and delays;

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unfavorable weather conditions;

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hazards resulting from unusual or unexpected geological or environmental conditions;

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changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

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fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

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the availability of alternative fuels and the price at which they become available.

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Some of these risks may be exacerbated by other risks that we face. For instance, certain of our wells produce high levels of H2S, a highly toxic, naturally-occurring gas frequently associated with oil and natural gas production. Safely handling H2S gas requires highly skilled operations and field personnel as well as specialized infrastructure, treating facilities, disposal facilities, and/or third party sour gas takeaway. If we are unable to attract and retain qualified and highly skilled personnel our ability to effectively manage this and other risks may be adversely impacted. Additionally, if we are unable to successfully operate our specialized treating facilities or secure adequate sour gas takeaway capacity from third parties when and if necessary, our ability to effectively manage the H2S levels we see in our natural gas production may be adversely impacted. As a result, our production, revenues, operating costs and liabilities and expenses may be materially and adversely affected and may differ materially from those anticipated by us.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of natural gas, condensate or oil being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems available in our operating areas, it may be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks or trains to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions, the availability and cost of capital, regulatory restrictions and judicial challenges. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently expect, which would adversely affect our results of operations.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of weather conditions (which may worsen due to climate changes), accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

We could experience periods of higher costs for various reasons, including due to higher commodity prices, increased drilling activity in the Delaware Basin and trade disputes that affect the costs of steel and other raw materials that we and our vendors rely upon, which could adversely affect our ability to execute our exploration and development plans on a timely basis and within budget.

Our industry is cyclical. When oil, natural gas and natural gas liquids prices increase, shortages of drilling rigs, equipment, supplies, water or qualified personnel may result. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production, particularly in the Delaware Basin, likewise may increase demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. Cost increases may also result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other materials that we and our vendors rely upon and increases in the cost of services to process, treat and transport our production. Any escalation or expansion of tariffs could result in higher costs and affect a greater range of materials we rely upon in our business. The unavailability or high cost of drilling rigs, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability. In order to secure drilling rigs and pressure pumping equipment and related services, we may enter into contracts that extend over several months or years. If demand for drilling rigs and pressure pumping equipment subside during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.

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Our strategy involves drilling in shale formations, using horizontal drilling and modern completion techniques. The results of our drilling program using these techniques may be subject to more uncertainties than conventional drilling programs. These uncertainties could result in an inability to meet our expectations for reserves and production.

The drilling of long horizontal laterals and the use of modern completion techniques with multi-stage fracture stimulation in shale formations involves certain risks and complexities that do not exist in conventional wells. Such risks include, but are not limited to, landing the horizontal wellbore in the desired drilling zone, maintaining the desired drilling zone while drilling horizontally through the wellbore formation, running casing through the full span of the wellbore, and being able to run tools and other necessary equipment consistently throughout the horizontal wellbore. Additionally, horizontal drilling and completion techniques may result in faster production decline rates relative to conventional drilling methods. The ultimate success of our drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established.

If our drilling results are less than anticipated our investment in these areas may not be as attractive as we anticipate and could result in material write-downs of unevaluated properties and future declines in the value of our undeveloped acreage.

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

We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Financial and Liquidity Risk Factors

Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability, future growth and the carrying value of our properties depend substantially on prevailing oil and natural gas prices. Prices also affect the amount of cash flow we have available for capital expenditures and our ability to borrow and raise additional capital. The amount we are able to borrow under our Senior Credit Agreement is subject to periodic redeterminations based in part on the value of our estimated proved reserves, which reflect current oil and natural gas prices, and on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

Oil and natural gas prices are volatile. Among the factors that affect volatility are:

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domestic and foreign supplies of oil and natural gas;

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the ability of members of the Organization of Petroleum Exporting Countries and other oil exporting countries, including Russia, to agree upon and maintain production quotas;

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social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks;

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the level of consumer demand for oil and natural gas, including demand growth in developing countries, such as China and India;

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labor unrest in oil and natural gas producing regions;

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weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand for oil and natural gas;

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the price and availability of alternative fuels and energy sources;

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the price and availability of foreign imports and domestic exports; and

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worldwide and regional economic and political conditions impacting the global supply and demand for oil and natural gas, which may be driven by many factors, including health epidemics (such as the current global COVID-19 coronavirus outbreak).

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

Our business requires substantial capital expenditures primarily to fund our drilling program. We may also continue to selectively increase our core acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. It is possible that we will acquire acreage in other areas that we believe are prospective for oil and natural gas production and expend capital to develop such acreage. We expect to use borrowings under our Senior Credit Agreement and proceeds from potential future capital markets transactions, if necessary, to fund capital expenditures that are in excess of our operating cash flow and cash on hand.

Our Senior Credit Agreement limits our borrowings to the lesser of the borrowing base and the total commitments. As of December 31, 2020 (Successor), our Senior Credit Agreement had a borrowing base of $190.0 million. As of December 31, 2020 (Successor), we had $158.0 million of indebtedness outstanding, approximately $4.7 million of letters of credit outstanding and approximately $27.3 million of borrowing capacity available under our Senior Credit Agreement. A reduction in our borrowing base could require us to repay borrowings, if any, in excess of the borrowing base. Our Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio and (ii) a Current Ratio, each as defined in the Senior Credit Agreement. We have periodically sought amendments to the covenants under our revolving credit agreements, including the financial covenants, where we have anticipated difficulty in maintaining compliance. In the event we have difficulty in the future meeting the covenants under our Senior Credit Agreement, we would be required to seek additional relief, and there is no assurance that it would be granted. Failure to comply with the covenants in our Senior Credit Agreement may limit our ability to borrow, result in an event of default and cause amounts outstanding under our Senior Credit Agreement to become immediately due and payable.

Additionally, certain segments of the investor community have developed negative sentiment towards investing in our industry, with some investors and investment advisors adopting policies negatively impacting investment in the oil and gas sector based on social and environmental considerations. Commercial and investment banks have also come under pressure to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could potentially result in a reduction of available capital funding for development projects, thus impacting future financial results.

If we are not able to borrow sufficient amounts under our Senior Credit Agreement, or otherwise, and are unable to raise sufficient capital to fund our capital expenditures, we may be required to curtail our drilling, development, land acquisitions and other activities, which could result in a decrease in our production of oil and natural gas, forfeiture of leasehold interests if we are unable or unwilling to renew them, and could force us to sell some of our assets on an unfavorable basis, each of which could have a material adverse effect on our results and future operations.

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Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Our future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition, results of operations, cash flows and potentially the borrowing capacity under our Senior Credit Agreement.

Borrowings under our Senior Credit Agreement are limited by our borrowing base, which is subject to periodic redetermination, and our Senior Credit Agreement is currently funded substantially by one financial institution with plans to exit the United States oil and gas investment banking business.

The borrowing base under our Senior Credit Agreement is currently $190.0 million and is redetermined at least semiannually on each May 1 and November 1, with us and the lenders 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 such other information as lenders deem appropriate in their sole credit discretion and consistent with the normal and customary standards and practices they use for determining the value of oil and gas properties and criteria for reserve based oil and gas lending as it exists at the time. Accordingly, the borrowing base is influenced by many factors and our lenders have significant discretion in establishing it. Under our Senior Credit Agreement, any proposed increase in the borrowing base must be approved by all lenders while maintaining or decreasing the borrowing base requires the approval only of lenders holding two thirds of unused commitments under the facility. Bank of Montreal, who recently announced its plans to exit the United States oil and gas investment banking business, currently holds substantially all of the commitments under our Senior Credit Agreement and, therefore, at present, has the sole ability to determine the borrowing base.

The borrowing base could be reduced upon a redetermination, particularly to the extent recent substantial declines in oil and natural gas prices in response to actions by Saudi Arabia and Russia negatively impact future price expectations. If the borrowing base under our Senior Credit Agreement is further reduced, it could negatively impact our liquidity and require us to repay outstanding borrowings to the extent such borrowings exceed the redetermined borrowing base. We may not have sufficient funds to make such payments, which could result in a default under the terms of our Senior Credit Agreement and acceleration of our obligations thereunder, or to fund our business or planned capital expenditures. We could be required to seek additional capital, which may not be available to us or may be more costly, and we may be required to curtail our drilling, development, land acquisition and other activities, which could result in a decrease in our production of oil and natural gas, forfeiture of leasehold interests to the extent we are unable or unwilling to renew them and could force us to sell assets on an untimely or unfavorable basis, each of which could have a material adverse effect on our results and future operations.

Bank of Montreal’s decision to exit investment banking in the United States oil and gas industry could lead to similar decisions with regard to its participation in oil and gas lending in the United States, resulting in the sale of our Senior Credit Agreement to another financial institution, hedge fund, or other third party, without our approval or consent, and could also lead us to seek alternative forms of financing, the terms of which may be more costly, provide less liquidity, or impose more restrictive covenants, each of which could have a material adverse effect on our results and future operations.

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Historically, we have had substantial indebtedness and we may incur substantially more debt in the future. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We have approximately $158.0 million principal amount of debt as of December 31, 2020 (Successor). As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, or potentially outstanding principal, which will reduce the amount of cash flow we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes or adverse developments in our business or economic downturns impacting the industry in which we operate. Indebtedness under our Senior Credit Agreement is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have hedging arrangements that are effective in offsetting interest rate fluctuations. Currently, certain borrowings under our Senior Credit Agreement may bear interest at LIBOR, however financial regulators are working to transition away from LIBOR as a benchmark by the end of 2021. It is currently unclear whether new methods of calculating LIBOR will be established after 2021, or whether different benchmark rates to price indebtedness will develop. At this time, the impact on our borrowing costs, if any, under an alternative benchmark to LIBOR is uncertain.

We may incur substantially more debt in the future. At December 31, 2020 (Successor), we had approximately $27.3 million of additional borrowing capacity available under our Senior Credit Agreement. Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional shares of common or preferred stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of our reserves.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves in accordance with SEC requirements is complex, involving significant estimates and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The estimates of our reserves as of December 31, 2020 (Successor) are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, in accordance with SEC requirements, estimates of oil and gas reserves, future net revenue from proved reserves and the present value of our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the 12-month first-day-of-the-month average oil and gas prices for the year ended December 31, 2020 (Successor). Average prices for oil and natural gas for the 12-month period were as follows: WTI crude oil spot price of $39.54 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $1.99 per MMBtu, adjusted by lease or field for energy content, transportation fees, and market differentials. Any significant variance in the actual future prices from these assumptions could materially affect the estimated quantity and value of our reserves set forth in this report.

In addition, at December 31, 2020 (Successor), approximately 43% of our estimated proved reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Estimated proved reserves as of December 31, 2020 (Successor) assume that we will make future capital expenditures of approximately $315.1 million in the aggregate primarily from 2021 through 2025, which are necessary to develop and realize the value of proved reserves on our properties. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with

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SEC regulations, however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

We are subject to various contractual limitations that affect the discretion of our management in operating our business.

Our Senior Credit Agreement contains various provisions that may limit our management’s discretion in certain respects. In particular, the Senior Credit Agreement limits our and our subsidiaries’ ability to, among other things:

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pay dividends on, redeem or repurchase shares of our common stock and any other capital stock we may issue;

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make loans to others;

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make investments;

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incur additional indebtedness;

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create certain liens;

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sell assets;

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enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

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consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;

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engage in transactions with affiliates;

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increase our exposure to commodity price fluctuations;

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create unrestricted subsidiaries; and

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enter into sale and leaseback transactions.

Compliance with these and other limitations may limit our ability to operate and finance our business and engage in certain transactions in the manner we might otherwise. In addition, if we fail to comply with the limitations under our Senior Credit Agreement, our creditors, to the extent the agreement so provides, may accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.

Federal legislation and rulemaking could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. The Dodd-Frank Act may require us to comply with margin requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The counterparties to our derivative instruments may also spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

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personal injury;

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bodily injury;

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third party property damage;

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medical expenses;

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legal defense costs;

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pollution in some cases;

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well blowouts in some cases; and

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workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our financial position, results of operations and cash flows.

Our ability to use net operating loss carryforwards and realized built in losses to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses (NOLs), and realized built in losses (RBILS), to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% stockholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders’ lowest percentage ownership during the testing period (generally three years).

We experienced ownership changes in December 2018 and October 2019 and we may experience additional ownership changes in the future. Limitations imposed on our ability to use NOLs and RBILS to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs and RBILS to expire unused, in each case reducing or eliminating the benefit of such NOLs and RBILS. Similar rules and limitations may apply for state income tax purposes.

We may be required to take non-cash asset write-downs.

We may be required under full cost accounting rules to write-down the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of oil and natural gas properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using the unweighted arithmetic average of the first day of each month for the 12-month period ending at the balance sheet date. If the net book value of oil and natural gas properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, SEC regulations require us to impair or “write-down” the book value of our oil and natural gas properties.

During the year ended December 31, 2020 (Successor), we recorded cumulative full cost ceiling impairments of $215.1 million, primarily driven by a decline in the average pricing used in the valuation of our reserves. As ceiling test

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computations depend upon the calculated unweighted arithmetic average prices, it is impossible to predict the likelihood, timing and magnitude of any future impairments. Depending on the magnitude, a ceiling test write-down could negatively affect our results of operations.

Costs associated with unevaluated properties, which were approximately $75.5 million at December 31, 2020 (Successor), are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. 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 ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to depletion and the ceiling test limitation.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production and comply with the requirements of our Senior Credit Agreement, we have entered into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such 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. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

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our production is less than expected;

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there is a widening of price differentials between delivery points for our production; or

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the counterparties to our hedging agreements fail to perform under the contracts.

Investment in Securities Risk Factors

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds advised by Luminus Management, LLC, Oaktree Capital Management, LP and LSP Investment Advisors, LLC, held approximately 37.8%, 24.5% and 14.6%, respectively, of our common stock as of March 4, 2021 (Successor). Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional equity securities or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

A large percentage of our shares of common stock are held by a relatively small number of investors. Further, we entered into a registration rights agreement with certain of those investors pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could cause the market

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price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We are currently authorized to issue 100.0 million shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of March 4, 2021 (Successor), we had outstanding approximately 16.3 million shares of common stock, and warrants, options and restricted stock units to purchase or receive an aggregate of 8.2 million shares of our common stock. As of March 4, 2021 (Successor), we have also reserved an additional 0.2 million shares for future issuance to our directors, officers and employees under our 2020 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

Regulatory Risk Factors

We are subject to complex federal, state, local and other laws and regulations that frequently are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

Companies that explore for and develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our activities, we may not be able to conduct our operations as planned. We also may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

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water discharge and disposal permits for drilling operations;

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drilling bonds;

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drilling permits;

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reports concerning operations;

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air quality, air emissions, noise levels and related permits;

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spacing of wells;

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rights-of-way and easements;

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unitization and pooling of properties;

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pipeline construction;

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gathering, transportation and marketing of oil and natural gas;

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taxation; and

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waste transport and disposal permits and requirements.

Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase our costs of doing business. For example, negative public perception regarding us and/or our industry may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Under environmental, health and safety laws and regulations, we also could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Such laws may impose strict as well as joint and several liability for environmental contamination,

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which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling and pipeline projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation by oil and natural gas producing states relating to conservation practices and protection of correlative rights. Such regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. By way of example, in 2015 the EPA lowered the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation, which has been ongoing, eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or may in the future, plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to require more stringent federal control or outright bans of hydraulic fracturing. Further, the EPA issued a study in 2016 finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity. Other governmental reviews have also been conducted that focus on environmental aspects of hydraulic fracturing. Such activities eventually could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Certain states, including Texas where we conduct our operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing.

The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

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are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and international negotiations over climate change and greenhouse gases are continuing. Meanwhile, several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

In the United States, many states, either individually or through multi-state regional initiatives, have been implementing legal measures to reduce emissions of greenhouse gases, primarily through emission inventories, emission targets, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

At the federal level, the Obama Administration addressed climate change through a variety of administrative actions. The EPA thus issued greenhouse gas monitoring and reporting regulations that cover oil and natural gas facilities, among other industries. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding certain greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as the first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities. In March 2014, moreover, then President Obama released a Strategy to Reduce Methane Emissions that included consideration of both voluntary programs and targeted regulations for the oil and gas sector. Consistent with that strategy, the EPA issued final rules in 2016 for new and modified oil and gas production sources (including hydraulically fractured oil wells, natural gas well sites, natural gas processing plants, natural gas gathering and boosting stations and natural gas transmission sources) to reduce emissions of methane as well as volatile organic compound and toxic pollutants. In addition, the BLM promulgated standards for reducing venting and flaring on public lands.

The Trump Administration tried to roll back many of the Obama-era climate change policies and rules. But shortly after his inauguration, President Biden accepted the Paris Agreement on behalf of the United States, declared climate considerations an essential part of the United States’ foreign policy, issued a moratorium on new oil and gas leases on federal lands, and directed federal agencies to incorporate climate change considerations in their operation. Thus, new federal programs relating to climate change appear to be likely over at least the next four years.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have or contribute to significant greenhouse gas emissions. Such cases may seek emissions reductions, challenge air emissions or other permits or request damages for alleged climate change impacts to the environment, people, and property.

Any new initiatives that may be adopted to reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our products.

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas liquids and natural gas, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny and regulation of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

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Cybersecurity Risk Factors

We depend on computer, telecommunications and information technology systems to conduct our business, and failures, disruptions, cyber-attacks or other breaches in data security could significantly disrupt our business operations, create liability and increase our costs.

The oil and natural gas industry in general has become increasingly dependent upon technology to conduct day-to-day operations, including certain exploration, development and production activities. We have agreements with third parties for hardware, software, telecommunications and other information technology services necessary to our business and have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We use these systems and data to, among other things, estimate quantities of oil, natural gas liquids and natural gas reserves, process and record financial data and communicate with our employees and third parties. Failures in these systems due to hardware or software malfunctions, computer viruses, natural disasters, fire, human error or other causes could significantly affect our ability to conduct our business. In particular, cyber-security attacks on systems are increasing in frequency and sophistication and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to them, there can be no assurance that these procedures and controls will be sufficient to prevent security threats from materializing and any interruptions to our arrangements with third parties, to our computing and communications infrastructure or our information systems could significantly disrupt our business operations. Further, the loss or corruption of sensitive information could have a material adverse effect on our reputation, financial position, results of operations or cash flows. In addition, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks. We generally do not maintain insurance coverage for the costs associated with cyber-security events.

Risk Factors Relating to Our Prior Restructuring

Our actual financial results may vary materially from the projections that we filed with the bankruptcy court in connection with the confirmation of our plan of reorganization.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of our plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. As a result, investors should not rely on these projections.

Our historical financial information may not be indicative of our future financial performance.

Our capital structure was significantly altered under the Plan. We adopted fresh-start accounting effective October 1, 2019, as an accounting convenience date to coincide with the timing of our normal fourth quarter reporting, and as a result, our assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Further, as a result of the implementation of our plan of reorganization and the transactions contemplated thereby, our historical financial information may not be indicative of our future financial performance. Accordingly, our financial condition and results of operations following our emergence from chapter 11 are not comparable to the financial condition and results of operations reflected in our historical financial statements.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Item 8. Consolidated Financial Statements and Supplementary Data—Note 12, “Commitments and Contingencies,” and is incorporated herein by reference.

From time to time, we 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, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our consolidated operating results, financial position or cash flows.

Under rules promulgated by the SEC, administrative or judicial proceedings arising under any federal, state or local provisions that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment are disclosed if the governmental authority is party to such proceeding and the proceeding involves potential monetary sanctions of $300,000 or more. We are not party to any such proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

On February 20, 2020, our common stock commenced trading on the NYSE American exchange under the symbol “BATL.” Previously, on July 22, 2019, we were notified by the New York Stock Exchange (NYSE) that due to “abnormally low” trading price levels, pursuant to Section 802.01D of the NYSE Listed Company Manual, the NYSE determined to commence delisting proceedings to delist our Predecessor common stock under the symbol “HK” and warrants exercisable for common stock. Trading in our securities was suspended on July 22, 2019. On July 23, 2019, our Predecessor common stock commenced trading on the OTC Pink marketplace under the symbols “HKRS,” “HKRSQ,” and “HALC.” On October 8, 2019, upon emergence from chapter 11 bankruptcy, all existing shares of our Predecessor common stock were cancelled and we, as the Successor Company, issued approximately 16.2 million shares of new common stock.

We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant. We are also restricted from paying cash dividends on common stock under our Senior Credit Agreement.

Approximately 56 registered stockholders of record as of March 4, 2021 held our common stock. In most instances, a registered stockholder holds shares in street name for one or more customers who beneficially own the shares.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

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ITEM 7. 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 and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy on October 8, 2019. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019, the convenience date applied for fresh-start accounting. 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. Refer to Item 8. Consolidated Financial Statements and Supplementary Data – Note 2, “Reorganization” and Note 3, “Fresh-start Accounting,” for further details.

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.

Overview

At December 31, 2020 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (Netherland, Sewell), using Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average prices of West Texas Intermediate (WTI) crude oil spot price of $39.54 per Bbl and Henry Hub natural gas spot price of $1.99 per MMBtu, were approximately 63.4 MMBoe, consisting of 38.2 MMBbls of oil, 12.1 MMBbls of natural gas liquids, and 78.5 Bcf of natural gas. Approximately 57% of our proved reserves were classified as proved developed as of December 31, 2020 (Successor). We maintain operational control of 99.9% of our proved reserves. Substantially all of our proved reserves and production at December 31, 2020 (Successor) are associated with our Delaware Basin properties.

Our total operating revenues for the year ended December 31, 2020 (Successor) were approximately $148.3 million. Our total operating revenues for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $65.6 million and $159.1 million, respectively, or $224.7 million combined. Full year 2020 (Successor) production averaged 16,858 Boe/d. During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, or 17,986 Boe/d combined. The decrease in total operating revenues and average daily production year over year was driven by our temporary shut-in of a portion of producing wells across all our operating areas in May and June 2020 (Successor) as a consequence of low oil prices as well as average realized prices that were lower by approximately $10.25 per Boe. The estimated production decrease associated with these temporary shut-ins was approximately 1,300 Boe/d for 2020 (Successor). In December 2020 (Successor), we divested properties that produced approximately 600 Boe/d during the nine months ended September 30, 2020 (Successor).

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

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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.

In 2020 (Successor), we spent approximately $101.8 million on oil and gas capital expenditures. In early 2020, we ran one operated rig in the Delaware Basin, and in March 2020, as a result of changes in market conditions and commodity prices, we began to scale back our capital operations and spending and eventually released the rig. 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 during the year.

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 first-day-of-the-month average for the 12-months ended March 31, 2021 of the WTI crude oil spot price of $39.95 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 March 31, 2021 of the Henry Hub natural gas price of $2.16 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation would not have generated an additional impairment at December 31, 2020 (Successor), holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

Risk and Uncertainties

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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-K 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 Annual Report on Form 10-K.

Northern West Quito Assets Divestiture

Successor Senior Revolving Credit Facility

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 for 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.

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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

Acid Gas Injection Well Permits

Listing of our Common Stock on NYSE American

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 year ended December 31, 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.

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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.

We expect to spend approximately $40.0 million to $50.0 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, during 2021. These near-term capital spending requirements are expected to be funded with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement, which has a current borrowing base of $190.0 million. Amounts borrowed under our Senior Credit Agreement will mature on October 8, 2024. At December 31, 2020 (Successor), we had $158.0 million of indebtedness outstanding and approximately $4.7 million letters of credit outstanding under our Senior Credit Agreement, resulting in $27.3 million of borrowing capacity under the current borrowing base. 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 matters relating to the Senior Credit Agreement and we explore 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. Bank of Montreal, who recently announced its plans to exit the United States oil and gas investment banking business, currently holds substantially all of the commitments under our Senior Credit Agreement. Bank of Montreal’s decision to exit its US investment banking business could lead to similar decisions with regard to its participation in oil and gas lending in the United States, resulting in the sale of our Senior Credit Agreement to another financial institution, hedge fund, or other third party and could also lead us to seek alternative forms of financing, the terms of which may be more costly, provide less liquidity, or impose more restrictive covenants. While we believe that alternatives to maintain liquidity under, or to 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.

Depressions in oil and natural gas prices during 2020 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

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the fiscal quarters ending September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021. As of December 31, 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. As discussed above, the primary lender under the Senior Credit Agreement has scaled back certain of its activities in the United States, and it is unknown to what extent, if any, its oil and gas lending activities in the United States may be impacted by that decision or whether that, or other factors, may impact our ability to obtain covenant modifications in the future, if necessary. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than 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. While we use derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices, the total volumes we hedge are less than our expected production, varies from period to period based on our view of current and future market conditions and generally extends up to 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 utilize fixed price swaps to hedge at least 65% of anticipated production from proved developed producing reserves through December 31, 2022. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

Our future capital resources and liquidity depend, in part, 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.

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Cash Flow

In 2020 (Successor), cash generated by operating activities, borrowings under our Senior Credit Agreement and proceeds from the North West Quito Assets divestiture were used to fund our drilling and completion program. 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
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Cash flows provided by (used in) operating activities	$	50,197	$	13,654	$	(39,731)	$	67,155
Cash flows provided by (used in) investing activities		(72,354)		(42,790)		(254,417)		(706,485)
Cash flows provided by (used in) financing activities		16,177		10,026		276,667		262,125
Net increase (decrease) in cash, cash equivalents and restricted cash	$	(5,980)	$	(19,110)	$	(17,481)	$	(377,205)

Operating Activities. Net cash flows provided by operating activities for the year ended December 31, 2020 (Successor) was $50.2 million. Net cash flows provided by operating activities for the period of October 2, 2019 through December 31, 2019 (Successor) were $13.7 million and net cash flows used in operating activities for the period of January 1, 2019 through October 1, 2019 (Predecessor) were $39.7 million. Net cash flows provided by operating activities was $67.2 million for the year ended December 31, 2018 (Predecessor).

Operating cash flows for the year ended December 31, 2020 (Successor) increased from the prior year 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 year ended December 31, 2020 (Successor), which included the early termination of certain derivative contracts. During the year ended December 31, 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.

For the period of October 2, 2019 through December 31, 2019 (Successor), operating cash flows increased due to higher oil and natural gas revenues resulting from increased average daily production, as well as decreases in our operating expenses. For the period of January 1, 2019 through October 1, 2019 (Predecessor), operating cash flows decreased from the prior year due to increases in our operating expenses, primarily from third party water hauling and disposal costs, reorganization costs and severances paid to executives.

Operating cash flows for the year ended December 31, 2018 (Predecessor) decreased from prior year primarily due to our divestitures in 2017, in which we divested non-core producing properties in other areas for primarily undeveloped acreage in the Delaware Basin. This decrease was partially offset by $35.2 million of proceeds related to hedge monetizations that occurred during the year.

Investing Activities. Net cash flows used in investing activities for the year ended December 31, 2020 (Successor) were approximately $72.4 million. Net cash flows used in investing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were approximately $42.8 million and $254.4 million, respectively. Net cash flows used in investing activities for the year ended December 31, 2018 (Predecessor) were approximately $706.5 million.

During the year ended December 31, 2020 (Successor) we spent $101.8 million on oil and natural gas capital expenditures, of which $65.1 million related to drilling and completion costs and $33.9 million related to the development of our treating equipment and gathering support infrastructure. We received $29.0 million in proceeds from

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the sale of oil and natural gas properties, primarily from the North West Quito Assets in December 2020. In addition, we received $0.5 million in insurance proceeds associated with a casualty loss on our support infrastructure.

During the period of October 2, 2019 through December 31, 2019 (Successor), we spent $43.2 million on oil and natural gas capital expenditures, of which $29.2 million related to drilling and completion costs and $13.2 million related to the development of our treating equipment and our gathering support infrastructure. During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent $167.2 million on oil and natural gas expenditures, of which $158.6 million related to drilling and completion costs. During the period of January 1, 2019 through October 1, 2019 (Predecessor), we spent approximately $85.6 million on capital expenditures to develop our treating equipment and our gathering support infrastructure.

In 2018 (Predecessor), we incurred cash expenditures of $333.9 million on acquisition activities, the majority of which related to the acquisitions of acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) and in the northern tract of the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets). Additionally, we spent $475.7 million on oil and natural gas capital expenditures, of which $444.4 million related to drilling and completion costs. We also spent approximately $117.0 million on capital expenditures primarily to develop our water recycling facilities and gas gathering and treating infrastructure. These cash outflows were offset by proceeds from the sale of our water infrastructure assets located in the Delaware Basin (the Water Assets) of $213.8 million.

Financing Activities. Net cash flows provided by financing activities for the year ended December 31, 2020 (Successor) were approximately $16.2 million. Net cash flows provided by financing activities for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) were $10.0 million and $276.7 million, respectively. Net cash flows provided by financing activities for the year ended December 31, 2018 (Predecessor) were approximately $262.1 million.

During the year ended December 31, 2020 (Successor), net borrowings of $14.0 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 period of October 2, 2019 through December 31, 2019 (Successor), net borrowings of $14.0 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. During the period of January 1, 2019 through October 1, 2019 (Predecessor), we received proceeds of $150.2 million from a rights offering to our unsecured senior noteholders and $5.8 million from a rights offering to our previous common stockholders, both related to our chapter 11 bankruptcy. In addition, we borrowed $130.0 million under our Senior Credit Agreement. The proceeds from our offerings and borrowings under our Senior Credit Agreement were used to refinance our DIP facility and the Predecessor credit agreement. Borrowings under our DIP facility and under our Predecessor credit agreement were used to fund our drilling and completions program, as well as the development of our treating equipment and our gathering infrastructure.

In 2018 (Predecessor), we issued an additional $200.0 million aggregate principal amount of our 6.75% senior notes due 2025. Proceeds from the private placement were approximately $202.4 million after initial purchasers’ premiums and deducting commissions and offering expenses. Additionally, we sold 9.2 million shares of common stock in a public offering at a price of $6.90 per share. The net proceeds from the offering were approximately $60.4 million after deducting underwriters’ discounts and offering expenses.

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

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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.

On October 29, 2020 (Successor),we entered into the Third Amendment. The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment. The Third Amendment also reduced the amount available for issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On 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 which, among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then to be 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

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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, to not greater than 3.50 to 1.00.

As of December 31, 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 SBA. Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.

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

Off-Balance Sheet Arrangements

At December 31, 2020 (Successor), we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, “Summary of Significant Events and Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

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Fresh-start Accounting

Upon our emergence from chapter 11 bankruptcy, on October 8, 2019, we adopted fresh-start accounting in accordance with the provisions set forth in ASC 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date.

We elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of our normal fourth quarter reporting period, which resulted in us becoming a new entity for financial reporting purposes. We 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. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related fresh-start adjustments are included in the accompanying consolidated statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

Fresh-start accounting requires an entity 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, we will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor companies may 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. Refer to Item 8. Consolidated Financial Statements and Supplementary Data—Note 3, “Fresh-Start Accounting,” for further details.

Oil and Natural Gas Activities

Accounting for oil and natural gas activities is subject to unique rules. Two generally accepted methods of accounting for oil and natural gas activities are available-successful efforts and full cost. The most significant differences between these two methods are the treatment of unsuccessful exploration costs and the manner in which the carrying value of oil and natural gas properties are amortized and evaluated for impairment. The successful efforts method requires unsuccessful exploration costs to be expensed as they are incurred upon a determination that the well is uneconomical while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and natural gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and natural gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and natural gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using the unweighted arithmetic average of the first day of the month for each of the 12-month prices for oil and natural gas within the period, holding prices and costs constant and applying a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

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Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) were prepared by Netherland, Sewell, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).”

Depletion Expense

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2020 (Successor), a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.40 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.44 per Boe.

Full Cost Ceiling Test Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and could result in lower amortization expense in future periods. The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and natural gas properties could occur in the future.

If the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ended December 31, 2020 (Successor) had been 10% lower while all other factors remained constant, our ceiling amount related to our net book value of oil and natural gas properties would have been reduced by approximately $93.0 million and would have increased our full cost ceiling impairment by the same amount.

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Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2020 (Successor), a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.23 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.24 per Boe.

Accounting for Derivative Instruments and Hedging Activities

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. From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil, natural gas, and natural gas liquids production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

Income Taxes

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

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence we recorded an increase of $10.8 million to our valuation allowance as a result of increases to deferred tax assets for deferred deductions and net operating losses offset by the write-off of deferred tax assets for oil and gas properties and other deferred tax assets during 2020 (Successor). A valuation allowance of $489.5 million has been applied against our deferred tax assets as of December 31, 2020 (Successor).

We follow ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the

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appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

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Comparison of Results of Operations

Year Ended December 31, 2020 (Successor) Compared to Year Ended December 31, 2019 (Successor)

The table included below sets forth financial information for the periods presented. The period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) are distinct reporting periods as a result of our adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy and are not comparable to prior periods. Refer to the paragraphs following the table below for a discussion around our results of operations.


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through
In thousands (except per unit and per Boe amounts)	December 31, 2020		December 31, 2019		October 1, 2019
Net income (loss)	$	(229,707)	$	(10,460)	$	(1,156,053)
Operating revenues:
Oil		125,985		58,325		145,024
Natural gas		5,818		1,719		107
Natural gas liquids		14,972		5,071		13,229
Other		1,514		467		743
Operating expenses:
Production:
Lease operating		42,106		12,804		39,617
Workover and other		3,709		1,655		5,580
Taxes other than income		10,056		3,730		9,213
Gathering and other		56,016		10,812		36,057
Restructuring		2,580		1,175		15,148
General and administrative:
General and administrative		15,878		5,111		44,585
Stock-based compensation		2,578		—		(8,035)
Depletion, depreciation and accretion:
Depletion – Full cost		60,543		19,476		84,579
Depreciation – Other		925		376		6,026
Accretion expense		585		144		307
Full cost ceiling impairment		215,145		—		985,190
(Gain) loss on sale of Water Assets		—		(506)		3,618
Other income (expenses):
Net gain (loss) on derivative contracts		38,759		(16,692)		(34,332)
Interest expense and other		(6,634)		(1,275)		(37,606)
Reorganization items, net		—		(3,298)		(117,124)
Income tax benefit (provision)		—		—		95,791

Production:
Crude oil – MBbls		3,446		1,057		2,723
Natural gas – MMcf		8,769		2,755		6,381
Natural gas liquids – MBbls		1,262		351		911
Total MBoe⁽¹⁾		6,170		1,867		4,698
Average daily production – Boe⁽¹⁾		16,858		20,293		17,209

Average price per unit ⁽²⁾:
Crude oil price - Bbl	$	36.56	$	55.18	$	53.26
Natural gas price - Mcf		0.66		0.62		0.02
Natural gas liquids price - Bbl		11.86		14.45		14.52
Total per Boe⁽¹⁾		23.79		34.88		33.71

Average cost per Boe:
Production:
Lease operating	$	6.82	$	6.86	$	8.43
Workover and other		0.60		0.89		1.19
Taxes other than income		1.63		2.00		1.96
Gathering and other		9.08		5.79		7.67
Restructuring		0.42		0.63		3.22
General and administrative:
General and administrative		2.57		2.74		9.49
Stock-based compensation		0.42		—		(1.71)
Depletion		9.81		10.43		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 $146.8 million, $65.1 million and $158.4 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. For the year ended December 31, 2020 (Successor), production averaged 16,858 Boe/d. During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively. Our average daily oil, natural gas and natural gas liquids production decreased year over year due primarily to the temporary shut-in of a portion of producing wells across all operating areas during the months of May and June 2020 (Successor). Estimated production decreases associated with these temporary shut-ins was approximately 1,300 Boe/d for the year ended December 31, 2020 (Successor). Average realized prices (excluding the effects of hedging arrangements) were $23.79 per Boe, $34.88 per Boe and $33.71 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $42.1 million, $12.8 million and $39.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. On a per unit basis, lease operating expenses were $6.82 per Boe, $6.86 per Boe and $8.43 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $3.7 million, $1.7 million and $5.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. On a per unit basis, workover and other expenses were $0.60 per Boe, $0.89 per Boe and $1.19 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $10.1 million, $3.7 million and $9.2 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 $1.63 per Boe, $2.00 per Boe and $1.96 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Gathering and other expenses were $56.0 million, $10.8 million and $36.1 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $13.9 million, $2.7 million and $9.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 2020 due to the temporary shut-in of certain producing wells during the months of May and June 2020 (Successor). Approximately $38.7 million, $8.1 million and $24.8 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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

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produced from our Monument Draw properties during the period of January 1, 2019 through October 1, 2019 (Predecessor). Our produced natural gas from the Monument Draw area increased in the current year due to our development activities, 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. Also included are $3.4 million and $0.8 million of rig termination and stacking charges for the year ended December 31, 2020 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Restructuring expense was approximately $2.6 million, $1.2 million and $15.1 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. During the year ended December 31, 2020 (Successor), we incurred restructuring charges related to the consolidation into one corporate office and had reductions in our workforce due to efforts to improve efficiencies and reduce future 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 2019 (for both the Successor and Predecessor periods), 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, in 2019 (Predecessor), when the decision was made to consolidate into one corporate office, we began to incur restructuring charges which included both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $15.9 million, $5.1 million and $44.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. The decrease in general and administrative expense primarily results from a reduction in our payroll and employee-related benefits due to a reduction in our workforce since the prior year period and other administrative cost reductions as part of our continued focus on efficiencies and cost savings. The decrease in general and administrative expenses is also attributed to prepetition costs incurred in 2019 associated with our chapter 11 bankruptcy that year. On a per unit basis, general and administrative expense were $2.57 per Boe, $2.74 per Boe and $9.49 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Stock-based compensation expense was $2.6 million and a credit of $8.0 million for the year ended December 31, 2020 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor). During 2019 (for both the Successor and Predecessor periods), 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 termination. For the period of January 1, 2019 through October 1, 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 year 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 $60.5 million, $19.5 million and $84.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. On a per unit basis, depletion expense was $9.81 per Boe, $10.43 per Boe and $18.00 per Boe for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 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 impairments incurred in 2020.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any

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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. During 2020, the net book value of our oil and gas properties at June 30, September 30 and December 31 (Successor) exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $60.1 million, $128.3 million and $26.7 million, respectively, for the periods. The ceiling test impairments during 2020 (Successor) were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation. Additionally, during the three months ended September 30, 2020 (Successor), 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 also contributed to the impairment recorded for the period. During the three months ended December 31, 2020 (Successor), proved undeveloped reserves additions as a result of changes to our five year development plan partially offset the impact on the impairment of the average price decline for the period. During 2019, the net book value of our oil and gas properties at March 31, June 30 and September 30 (Predecessor) exceeded the ceiling amount and we recorded full cost ceiling test impairments before income taxes of $275.2 million, $664.4 million, and $45.6 million, respectively, for the periods. The ceiling test impairments during 2019 (Predecessor) were driven by transfers of unevaluated property to the full cost pool that occurred during the year and decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation. For the three months ended June 30, 2019 (Predecessor), we transferred approximately $481.7 million of unevaluated property costs to the full cost pool, the majority of which were associated with our Hackberry Draw area. For the three months ended March 31, 2019 (Predecessor), we identified certain leases in our Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool. These transfers of unevaluated property to the full cost pool in 2019 (Predecessor) were the result of our intent to focus available capital on our Monument Draw area. 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 which includes the $0.5 million addition and $3.6 million reduction in the period of October 2, 2019 through December 31, 2019 (Successor) and January 1, 2019 through October 1, 2019 (Predecessor), respectively, due to customary 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 consolidated statements of operations. At December 31, 2020 (Successor), we had a $12.6 million derivative asset, $8.6 million of which was classified as current, and we had a $26.4 million derivative liability, $22.1 million of which was classified as current. We recorded a net derivative gain of $38.8 million ($6.1 million net unrealized loss and $44.9 million net realized gain on settled and early terminated contracts) for the year ended December 31, 2020 (Successor). During 2020, 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 $44.9 million realized gains for the year. We recorded a net derivative loss of $16.7 million ($18.7 million net unrealized loss and $2.0 million net realized gain on settled and early terminated contracts) and 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) for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively.

Interest expense and other was $6.6 million, $1.3 million and $37.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. Interest expense for the Successor periods 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 for the respective periods in which borrowings were outstanding under each type of credit facility or senior notes. In addition to interest expense, in the period from January 1, 2019 through October 1, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor credit agreement.

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Reorganization items represent (i) expenses or income incurred subsequent to August 7, 2019 (when we filed voluntary petitions for relief under chapter 11) as a direct result of the reorganization Plan, (ii) gains or losses from liabilities settled, and (iii) fresh-start accounting adjustments. The following table summarizes the net reorganization items (in thousands):


	Successor		Predecessor
	Period from		Period from
	October 2, 2019		January 1, 2019
	through		through
	December 31, 2019		October 1, 2019
Gain on settlement of liabilities subject to compromise	$	—	$	481,777
Fresh start adjustments		—		(591,300)
Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount		—		20,274
Write-off debt discount/premium and debt issuance costs		—		(10,953)
Reorganization professional fees and other		(3,298)		(16,922)
Gain (loss) on reorganization items	$	(3,298)	$	(117,124)

We recorded an income tax benefit of $95.8 million using the discrete effective rate method for the period of January 1, 2019 through October 1, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the full cost ceiling impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations. The 7.7% effective tax rate for the period from January 1, 2019 through October 1, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation, 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 Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, “Summary of Significant Events and Accounting Policies.”

ITEM 7A. 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 and in a manner consistent with at least the minimum requirements that may be in effect from time to time under our Senior Credit Agreement. Our hedge policies and objectives may change significantly as our operational profile and contractual obligations changes. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of December 31, 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

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an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—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, cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—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 December 31, 2020 (Successor), the principal amount of our debt was $160.2 million, of which approximately 1.4% bears interest at a weighted average fixed interest rate of 1.0% per year. The remaining 98.6% of our total debt at December 31, 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 December 31, 2020 (Successor), the weighted average interest rate on our variable rate debt was 3.51% per year. If the balance of our variable interest rate at December 31, 2020 (Successor) were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.6 million per year.

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ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Management’s report on internal control over financial reporting		62
Report of independent registered public accounting firm		63
Consolidated statements of operations		66
Consolidated balance sheets		67
Consolidated statements of stockholders’ equity		68
Consolidated statements of cash flows		69
Notes to the consolidated financial statements		70
Supplemental oil and gas information (unaudited)		112

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Battalion Oil Corporation (the Company), including the Company’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, Management concluded that Battalion Oil Corporation’s internal control over financial reporting was effective as of December 31, 2020.

This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding the effectiveness of the Company’s internal control over financial reporting. Management’s report was not subject to attestation by its independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only Management’s report in this Annual Report on Form 10-K.

/s/ RICHARD H. LITTLE		/s/ R. KEVIN ANDREWS
Richard H. Little		R. Kevin Andrews
Chief Executive Officer		Executive Vice President,
		Chief Financial Officer and Treasurer
Houston, Texas
March 8, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of Battalion Oil Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Battalion Oil Corporation and subsidiaries (the "Company") as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity, and cash flows, for the year ended December 31, 2020 and for the period from October 2, 2019 to December 31, 2019 (effective October 2, 2019, the “Successor Company”), the period of January 1, 2019 to October 1, 2019, and for the year ended December 31, 2018 (pre-October 2, 2019, the “Predecessor Company”), and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Successor Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the year ended December 31, 2020 and for the period from October 2, 2019 to December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements referred to above present fairly, in all material respects, its operations and its cash flows for the period from January 1, 2019 to October 1, 2019 and for the year ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, on September 24, 2019, the Bankruptcy Court entered an order confirming the plan of reorganization which became effective after the close of business on October 8, 2019. Accordingly, the accompanying financial statements have been prepared in conformity with FASB Accounting Standard Codification 852, Reorganizations, for the Successor Company as a new entity with assets, liabilities, and a capital structure having carrying values not comparable with prior periods as described in Note 3 to the consolidated financial statements.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgements. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which they relate.

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Proved Oil and Natural Gas Property and Depletion — Oil and Natural Gas Reserve Quantities — Refer to Note 1 and 7 to the financial statements

Critical Audit Matter Description

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. The Company’s proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment by the full cost ceiling impairment test utilizing the Company’s oil and natural gas reserves in accordance with accounting principles generally accepted in the United States and SEC guidelines. The development of the Company’s oil and natural gas reserve quantities and the related net present value of future cash flows from the related proved reserves requires management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines, and the future development costs associated with these reserves. The Company engages an independent reservoir engineering firm, management’s specialist, to estimate oil and natural gas quantities using these estimates and assumptions and engineering data. Changes in these assumptions or engineering data could have a significant impact on the amount of depletion and impairment recorded for the Company’s proved oil and natural gas properties. The gross proved oil and natural gas properties balance was $509.3 million with an accumulated depletion balance of $295.2 million as of December 31, 2020. Depletion, depreciation, and amortization was $60.5 million for the twelve months ended December 31, 2020. Full cost ceiling impairment was $215.1 million for the twelve months ended December 31, 2020.

Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities and the related net cash flows, including management’s estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within the five-year development period and future development costs, requires a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures of management’s significant judgments and assumptions related to oil and natural gas reserves quantities and estimates of the future net cash flows included the following, among others:

●

We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to:

Historical conversions of proved undeveloped oil and natural gas reserves into proved developed oil and natural gas reserves.

Internal communications to management and the Board of Directors.

Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies.

The financial capability of the Company to execute its drilling program.

●

We evaluated the reasonableness of management’s estimate of future development costs by comparing the estimate to:

Historical development of similar wells, including location of the well.

Future development costs to internal data.

Internal communications to management and the Board of Directors.

Approval for expenditures.

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●

We evaluated the reasonableness of management’s estimated reserve quantities by performing the following:

Evaluating the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm.

Performing analytical procedures on the reserve quantities developed by management’s specialist.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 8, 2021

We have served as the Company’s auditor since 2012.

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	125,985	$	58,325	$	145,024	$	199,601
Natural gas		5,818		1,719		107		6,791
Natural gas liquids		14,972		5,071		13,229		19,137
Total oil, natural gas and natural gas liquids sales		146,775		65,115		158,360		225,529
Other		1,514		467		743		1,080
Total operating revenues		148,289		65,582		159,103		226,609

Operating expenses:
Production:
Lease operating		42,106		12,804		39,617		25,075
Workover and other		3,709		1,655		5,580		8,574
Taxes other than income		10,056		3,730		9,213		12,787
Gathering and other		56,016		10,812		36,057		60,090
Restructuring		2,580		1,175		15,148		128
General and administrative		18,456		5,111		36,550		62,056
Depletion, depreciation and accretion		62,053		19,996		90,912		77,527
Full cost ceiling impairment		215,145		—		985,190		—
(Gain) loss on sale of oil and natural gas properties		—		—		—		7,235
(Gain) loss on sale of Water Assets		—		(506)		3,618		(119,003)
Total operating expenses		410,121		54,777		1,221,885		134,469
Income (loss) from operations		(261,832)		10,805		(1,062,782)		92,140

Other income (expenses):
Net gain (loss) on derivative contracts		38,759		(16,692)		(34,332)		92,625
Interest expense and other		(6,634)		(1,275)		(37,606)		(43,015)
Reorganization items, net		—		(3,298)		(117,124)		—
Total other income (expenses)		32,125		(21,265)		(189,062)		49,610
Income (loss) before income taxes		(229,707)		(10,460)		(1,251,844)		141,750
Income tax benefit (provision)		—		—		95,791		(95,791)
Net income (loss)	$	(229,707)	$	(10,460)	$	(1,156,053)	$	45,959

Net income (loss) per share of common stock:
Basic	$	(14.18)	$	(0.65)	$	(7.27)	$	0.29
Diluted	$	(14.18)	$	(0.65)	$	(7.27)	$	0.29
Weighted average common shares outstanding:
Basic		16,204		16,204		158,925		157,011
Diluted		16,204		16,204		158,925		157,295

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

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BATTALION OIL CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	Successor
	December 31, 2020		December 31, 2019
Current assets:
Cash and cash equivalents	$	4,295	$	5,701
Accounts receivable, net		32,242		48,504
Assets from derivative contracts		8,559		4,995
Restricted cash		—		4,574
Prepaids and other		2,740		7,379
Total current assets		47,836		71,153
Oil and natural gas properties (full cost method):
Evaluated		509,274		420,609
Unevaluated		75,494		105,009
Gross oil and natural gas properties		584,768		525,618
Less - accumulated depletion		(295,163)		(19,474)
Net oil and natural gas properties		289,605		506,144
Other operating property and equipment:
Other operating property and equipment		3,535		3,655
Less - accumulated depreciation		(1,149)		(378)
Net other operating property and equipment		2,386		3,277
Other noncurrent assets:
Assets from derivative contracts		4,009		224
Operating lease right of use assets		310		3,165
Funds in escrow and other		2,351		703
Total assets	$	346,497	$	584,666

Current liabilities:
Accounts payable and accrued liabilities	$	58,928	$	97,333
Liabilities from derivative contracts		22,125		8,069
Current portion of long-term debt		1,720		—
Operating lease liabilities		403		923
Asset retirement obligations		—		109
Total current liabilities		83,176		106,434
Long-term debt		158,489		144,000
Other noncurrent liabilities:
Liabilities from derivative contracts		4,291		4,854
Asset retirement obligations		10,583		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;
16,203,979 and 16,203,940 shares issued and outstanding as of
December 31, 2020 and 2019, respectively		2		2
Additional paid-in capital		330,123		327,108
Retained earnings (accumulated deficit)		(240,167)		(10,460)
Total stockholders' equity		89,958		316,650
Total liabilities and stockholders' equity	$	346,497	$	584,666

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

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)


						Retained
				Additional		Earnings
	Common Stock			Paid-In		(Accumulated		Stockholders'
	Shares	Amount		Capital		Deficit)		Equity
Balances at December 31, 2017 (Predecessor)	149,379	$	15	$	1,016,281	$	55,702	$	1,071,998
Net income (loss)	—		—		—		45,959		45,959
Common stock issuance	9,200		1		63,479		—		63,480
Equity issuance costs	—		—		(3,044)		—		(3,044)
Stock option exercises	42		—		323		—		323
Long-term incentive plan grants	2,327		—		—		—		—
Long-term incentive plan forfeitures	(262)		—		—		—		—
Reduction in shares to cover
individuals' tax withholding	(73)		—		(301)		—		(301)
Stock-based compensation	—		—		18,629		—		18,629
Balances at December 31, 2018 (Predecessor)	160,613		16		1,095,367		101,661		1,197,044
Net income (loss)	—		—		—		(1,156,053)		(1,156,053)
Long-term incentive plan grants	4,164		—		—		—		—
Long-term incentive plan forfeitures	(2,101)		—		—		—		—
Reduction in shares to cover
individuals' tax withholding	(1,174)		—		(494)		—		(494)
Stock-based compensation	—		—		(10,020)		—		(10,020)
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
Net income (loss)	—		—		—		(229,707)		(229,707)
Equity issuance costs and other	—		—		(14)		—		(14)
Stock-based compensation	—		—		3,029		—		3,029
Balances at December 31, 2020 (Successor)	16,204	$	2	$	330,123	$	(240,167)	$	89,958

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

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Cash flows from operating activities:
Net income (loss)	$	(229,707)	$	(10,460)	$	(1,156,053)	$	45,959
Adjustments to reconcile net income (loss) to net cash provided by (used
in) operating activities:
Depletion, depreciation and accretion		62,053		19,996		90,912		77,527
Full cost ceiling impairment		215,145		—		985,190		—
(Gain) loss on sale of oil and natural gas properties		—		—		—		7,235
(Gain) loss on sale of Water Assets		—		(506)		3,618		(119,003)
Deferred income tax provision (benefit)		—		—		(95,791)		95,791
Stock-based compensation, net		2,578		—		(8,035)		15,266
Unrealized loss (gain) on derivative contracts		6,143		18,681		45,834		(84,274)
Amortization and write-off of deferred loan costs		—		—		1,859		1,405
Amortization of discount and premium		—		—		134		288
Reorganization items, net		(6,565)		(3,615)		108,887		—
Other expense (income)		312		253		535		(1,608)
Change in assets and liabilities:
Accounts receivable		13,513		(10,571)		3,781		378
Prepaids and other		4,712		2,911		(6,729)		5,840
Accounts payable and accrued liabilities		(17,987)		(3,035)		(13,873)		22,351
Net cash provided by (used in) operating activities		50,197		13,654		(39,731)		67,155

Cash flows from investing activities:
Oil and natural gas capital expenditures		(101,788)		(43,230)		(167,235)		(475,685)
Proceeds received from sales of oil and natural gas assets		29,029		—		1,247		3,816
Acquisition of oil and natural gas properties		(23)		—		(2,809)		(333,857)
Other operating property and equipment capital expenditures		(82)		—		(85,613)		(116,995)
Proceeds received from sale of other operating property and equipment		—		6		—		216,083
Funds held in escrow and other		510		434		(7)		153
Net cash provided by (used in) investing activities		(72,354)		(42,790)		(254,417)		(706,485)

Cash flows from financing activities:
Proceeds from borrowings		148,209		36,000		445,234		438,000
Repayments of borrowings		(132,000)		(22,000)		(315,234)		(232,000)
Cash payments to Common Holders, Noteholders and Preferred Holders		—		—		(4)		—
Debt issuance costs		—		(1,471)		(8,764)		(4,334)
Common stock issued		—		—		155,929		63,480
Equity issuance costs and other		(32)		(2,503)		(494)		(3,021)
Net cash provided by (used in) financing activities		16,177		10,026		276,667		262,125

Net increase (decrease) in cash, cash equivalents and restricted cash		(5,980)		(19,110)		(17,481)		(377,205)

Cash, cash equivalents and restricted cash at beginning of period		10,275		29,385		46,866		424,071
Cash, cash equivalents and restricted cash at end of period	$	4,295	$	10,275	$	29,385	$	46,866

Supplemental cash flow information:
Cash paid (received) for interest	$	7,577	$	(197)	$	33,071	$	37,526
Cash paid (refunded) for income taxes		(1,250)		—		—		(5,000)
Cash paid for reorganization items		6,565		6,913		8,237		—

Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	(592)	$	293	$	2,932	$	2,217
Accrued equity issuance costs		(19)		(2,484)		2,503		—
Accrued debt issuance costs		—		(1,471)		1,471		(90)

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

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

Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. 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. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.

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 subsequently agreed 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-K 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 Annual Report on Form 10-K.

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 Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Company’s chapter 11 proceedings

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

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 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 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 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 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 and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated fair value of assets sold in connection with the Williston Divestiture (see Note 6, “Acquisitions and Divestitures,” for information on the Williston Divestiture), including the gain on sale recorded, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

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BATTALION OIL CORPORATION

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Cash, Cash Equivalents and Restricted Cash

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the consolidated balance sheets included in “Cash and cash equivalents” and “Restricted cash” reconcile to the Company’s consolidated statements of cash flows as follows:


	Successor
	December 31, 2020		December 31, 2019

Cash and cash equivalents	$	4,295	$	5,701
Restricted cash		—		4,574
Total cash, cash equivalents and restricted cash	$	4,295	$	10,275

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

Oil and Natural Gas Properties

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

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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, 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.

Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approach used to record other operating property and equipment at fair value as of October 1, 2019. Refer to Note 6, “Acquisitions and Divestitures,” for a discussion of other operating property and equipment divested.

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 2020, the Company incurred approximately $2.6 million in restructuring charges related to the consolidation into one corporate office and reductions in its workforce due to efforts to improve efficiencies and reduce future costs. In May 2020 (Successor), in furtherance of the consolidation into one corporate office, the Company exercised a one-time early termination option under the lease agreement for the Company’s office space in Denver, Colorado. Refer to Note 4, “Leases,” for further details.

During 2019 (both in Successor and Predecessor periods), 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 third quarter of 2019 (Predecessor), the Company 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. Consequently, for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred approximately $1.2 million and $15.1 million, respectively, in restructuring charges.

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

Concentrations of Credit Risk

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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. In 2020 (Successor), two individual purchasers of the Company’s production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 57% of its total sales for the year. For the combined periods of October 2, 2019 through December 31, 2019 (Successor), and January 1, 2019 through October 1, 2019 (Predecessor), two individual purchasers of the Company’s production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 80% of its total sales for the period. For the year ended December 31, 2018 (Predecessor), two individual purchasers of the Company’s production, Western Refining Inc. and Sunoco, Inc., each accounted for more than 10% of total sales, collectively representing 77% of its total sales for the year.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. Joint operating agreements govern the operations of an oil or natural gas well and, in most instances, provide for offsetting of amounts payable or receivable between the Company and its joint interest owners. 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 December 31, 2020 (Successor), the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Senior Credit Agreement.

Risk Management Activities

The Company follows ASC 815, Derivatives and Hedging (ASC 815). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. The Company recognized all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

Income Taxes

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The Company follows ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements.

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

The Company has no liability for unrecognized tax benefits as of December 31, 2020 and 2019 (Successor). Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor). In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

The Company includes interest and penalties relating to uncertain tax positions within “Interest expense and other” on the Company’s consolidated statements of operations. Refer to Note 14, “Income Taxes,” for more details.

Generally, the Company’s income tax years 2017 through 2020 remain open for federal purposes and are subject to examination by federal tax authorities. The Company’s income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes.

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

Asset Retirement Obligations

ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

401(k) Plan

The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $0.8 million, $0.2 million and $1.1 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. The Company provided matching contributions of $1.5 million for the year ended December 31, 2018 (Predecessor). The Company matches employee contributions dollar-for-dollar on the first 10% of an employee’s pre-tax earnings, subject to individual IRS limitations.

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 condensed consolidated statement of operations for the year ended December 31, 2020 (Successor).

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 currently 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

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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

●

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 represent 30% of the New Common Shares issued pursuant to the Plan.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 our registration obligations and indemnification.

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. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

reorganization adjustments and fresh-start adjustments are included in the accompanying consolidated statement of operations in “Reorganization items, net” for the period from January 1, 2019 through October 1, 2019 (Predecessor).

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 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 are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require 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

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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		—		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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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Reorganization adjustments

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 DIP 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)

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.

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.

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 DIP Facility of $3.5 million and ii) professional fees associated with the chapter 11 bankruptcy of $1.5 million.

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 DIP Facility of $35.0 million using proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

Reflects the initial borrowing on the Senior Credit Agreement.

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

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 Company 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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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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):


	Successor		Predecessor
	Period from		Period from
	October 2, 2019		January 1, 2019
	through		through
	December 31, 2019		October 1, 2019
Gain on settlement of liabilities subject to compromise	$	—	$	481,777
Fresh start adjustments		—		(591,300)
Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount		—		20,274
Write-off debt discount/premium and debt issuance costs		—		(10,953)
Reorganization professional fees and other		(3,298)		(16,922)
Gain (loss) on reorganization items	$	(3,298)	$	(117,124)

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 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 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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 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 December 31, 2020 and 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 year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) (in thousands, except years and discount rate):


	Successor						Predecessor
				Period from			Period from
				October 2, 2019			January 1, 2019
	Year Ended			through			through
	December 31, 2020			December 31, 2019			October 1, 2019
Lease cost
Operating lease costs	$	1,986		$	260		$	1,932
Short-term lease costs		16,650			4,408			12,262
Variable lease costs		913			215			1,210
Total lease costs	$	19,549		$	4,883		$	15,404

Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	2,350		$	254		$	1,936
Right-of-use assets obtained in exchange for new operating lease liabilities		—			3,394			5,462
Weighted-average remaining lease term - operating leases		0.5	years		3.5	years		3.7	years
Weighted-average discount rate - operating leases		3.70	%		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, “Summary of Significant Events and Accounting Policies,” 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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 consolidated statements of operations for the year ended December 31, 2020 (Successor).

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


	Successor
	December 31, 2020
2021	$	406
2022		—
2023		—
2024		—
2025		—
Thereafter		—
Total operating lease payments		406
Less: discount to present value		3
Total operating lease liabilities		403
Less: current operating lease liabilities		403
Noncurrent operating lease liabilities	$	—

Practical Expedients

The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: (i) the Company does not separate lease and non-lease components of a contract, (ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, (iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and (iv) the Company does not assess whether existing or expired land easements that were previously accounted for as leases are or contain a lease under ASC 842.

5. OPERATING REVENUES

Revenue Recognition

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 $24.5 million and $36.4 million as of December 31, 2020 and 2019 (Successor), respectively, as “Accounts receivable” and “Other assets” on the 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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	125,985	$	58,325	$	145,024	$	199,601
Natural gas		5,818		1,719		107		6,791
Natural gas liquids		14,972		5,071		13,229		19,137
Total oil, natural gas and natural gas liquids sales		146,775		65,115		158,360		225,529
Other		1,514		467		743		1,080
Total operating revenues	$	148,289	$	65,582	$	159,103	$	226,609

Oil Sales

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

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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. 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.

Practical Expedients

The Company does not disclose the transaction price of unsatisfied performance obligations for i) contracts with an original expected duration of one year or less and ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied).

6. ACQUISITIONS AND DIVESTITURES

Acquisitions

West Quito Draw Properties

On February 6, 2018 (Predecessor), a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018 (Predecessor), and the Company closed the transaction on April 4, 2018 (Predecessor). The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 8, “Debt,” and Note 13, “Stockholders’ Equity,” respectively.

Monument Draw Assets (Ward and Winkler Counties, Texas)

On January 9, 2018 (Predecessor), the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $108.2 million in cash.

Divestitures

Northern West Quito Assets

On December 18, 2020 (Successor), the Company sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total sales price of $26.3 million in cash, subject to customary post-closing adjustments as provided in the Purchase and Sale Agreement. The effective date of the transaction was October 1, 2020 (Successor). Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded. The Company used the net proceeds from the sale to repay amounts outstanding under the Company’s Senior Credit Agreement and for general corporate purposes.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 (WaterBridge) for a total adjusted sales 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 WaterBridge. There were no drilling or throughput commitments associated with the Water Infrastructure Divestiture. WaterBridge 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.

During the year ended December 31, 2018 (Predecessor), the Company recorded a gain of $119.0 million on the sale of the Water Assets on the consolidated statements of operations in “(Gain) loss on sale of Water Assets.” The gain on the sale was increased by $0.5 million during the period of October 2, 2019 through December 31, 2019 (Successor) and reduced during the period of January 1, 2019 through October 1, 2019 (Predecessor) by approximately $3.6 million as a result of customary post-closing adjustments.

Williston Basin Operated Assets

On July 10, 2017 (Predecessor), the Company and certain of its subsidiaries entered into an agreement with Bruin Williston Holdings, LLC for the sale of all of the Company’s operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion (the Williston Divestiture). The effective date of the sale was June 1, 2017 (Predecessor) and the transaction closed on September 7, 2017 (Predecessor). The Company used the net proceeds from the sale to repay borrowings outstanding under its Predecessor Credit Agreement, repurchase approximately $425.0 million principal amount of the then outstanding $850.0 million principal amount of its 6.75% senior notes (refer to Note 8, “Debt”), redeem all of its then outstanding 12% senior secured second lien notes due 2022 and for general corporate purposes.

The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $1.39 billion was allocated to the Company’s oil and natural gas properties and approximately $10.9 million was allocated to other operating property and equipment.

As discussed further in Note 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, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017 (Predecessor). This gain was reduced by $7.2 million during the year ended December 31, 2018 (Predecessor) as a result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on the sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

7. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties as of December 31, 2020 and 2019 (Successor) consisted of the following (in thousands):


	Successor
	December 31, 2020		December 31, 2019

Subject to depletion	$	509,274	$	420,609
Not subject to depletion:
Exploration and extension wells in progress		—		—
Other capital costs:
Incurred in 2020		983		—
Incurred in 2019⁽¹⁾		74,511		105,009
Incurred in 2018		—		—
Incurred in 2017 and prior		—		—
Total not subject to depletion		75,494		105,009
Gross oil and natural gas properties		584,768		525,618
Less accumulated depletion		(295,163)		(19,474)
Net oil and natural gas properties	$	289,605	$	506,144

(1)	In 2019, with the adoption of fresh-start accounting, the Company’s unevaluated properties were recorded at fair value.

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. 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 $60.5 million, $19.5 million and $84.6 million for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. Depletion expense is recorded in “Depletion, depreciation and accretion” in the Company’s consolidated statements of operations.

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. Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approaches used.

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 consolidated balance sheet as of the Emergence Date. Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approaches used.

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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. For the three months ended September 30, 2020 (Successor), the Company transferred approximately $23.6 million of unevaluated property costs to the full cost pool. For the three months ended June 30, 2019 (Predecessor), the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool, the majority of which were associated with the Company’s Hackberry Draw area. For the three months ended March 31, 2019 (Predecessor), 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. These transfers of unevaluated property to the full cost pool in 2020 and 2019 were the result of the Company’s intent to focus available capital on Monument Draw.

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


	West Texas Intermediate (per barrel) ⁽¹⁾		Henry Hub (per MMBtu) ⁽¹⁾
December 31, 2020	$	39.54	$	1.99
December 31, 2019		55.85		2.58
December 31, 2018		65.56		3.10

(1)	Unweighted average of the first day of the 12-months ended spot price, adjusted by lease or field for quality, transportation fees and market differentials.

The Company’s net book value of oil and natural gas properties at June 30, September 30, and December 31, 2020 (Successor) exceeded the ceiling amount and the Company recorded full cost ceiling test impairments before income taxes of $60.1 million, $128.3 million, and $26.7 million, respectively, for those periods, or $215.1 million for the year ended December 31, 2020 (Successor). The ceiling test impairments during 2020 (Successor) were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation. Additionally, during the three months ended September 30, 2020 (Successor), the transfer of unevaluated property costs to the full cost pool, as discussed above, also contributed to the impairment recorded for the period. During the three months ended December 31, 2020 (Successor), proved undeveloped reserves additions as a result of changes to the Company’s five year development plan partially offset the impact on the impairment of the average price decline for the period. The Company’s net book value of oil and natural gas properties at March 31, June 30, and September 30, 2019 (Predecessor) exceeded the ceiling amount and the Company recorded full cost ceiling test impairments before income taxes of $275.2 million, $664.4 million and $45.6 million, respectively, for the periods. The ceiling test impairments during 2019 (Predecessor) were driven by the transfers of unevaluated property to the full cost pool that occurred during the year, as discussed above, and decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations. The Company’s net book value of oil and natural gas properties in 2018 (Predecessor) did not exceed the ceiling amount.

Full cost ceiling test impairments are recorded in “Full cost ceiling impairment” in the Company’s consolidated statements of operations and in “Accumulated depletion” in the Company’s consolidated balance sheets.

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


	Successor
	December 31, 2020		December 31, 2019
Successor senior revolving credit facility	$	158,000	$	144,000
Paycheck Protection Program loan		2,209		—
Total debt		160,209		144,000
Current portion of Paycheck Protection Program loan		1,720		—
Total long-term debt	$	158,489	$	144,000

Successor Senior Revolving Credit Facility

On October 8, 2019, the Company entered into a senior secured revolving credit agreement, as amended, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, both discussed below. 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. 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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

At December 31, 2020 (Successor), the Company had $158.0 million indebtedness outstanding, approximately $4.7 million letters of credit outstanding and approximately $27.3 million of borrowing capacity available 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, set the borrowing base to $190.0 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (discussed below). The Third Amendment also reduced the amount available for issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%. Additionally, the Third Amendment provided for new covenants that, among other things, require the Company to enter into swap agreements representing not less than 65% of the Company’s reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of the Company’s uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days. Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

On 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 for the fiscal quarter ended June 30, 2020.

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, to 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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

is administered by the U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022. As long as the Company makes a timely application of forgiveness to the SBA, the Company is not required to make any payments under the PPP Loan until the forgiveness amount is communicated to the Company by the SBA.

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

Under the terms of the CARES Act, the Company can apply for and be granted forgiveness for all or a portion of the PPP Loan. Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels. The Company believes it is eligible for, and intends to pursue, 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.

Debtor-in-Possession Financing

In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 9, 2019 (the Interim Order), the Predecessor Company entered into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent.

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019 (Predecessor). The DIP Facility was refinanced by the Senior Credit Agreement upon emergence from chapter 11 bankruptcy.

The DIP Loans bore interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by the Company.

Predecessor Senior Revolving Credit Facility

On September 7, 2017, the Predecessor Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Predecessor Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Predecessor Credit Agreement, the lenders party thereto agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a borrowing base of $225.0 million as of October 1, 2019 (Predecessor). The maturity date of the Predecessor Credit Agreement was September 7, 2022. The borrowing base was redetermined semi-annually, 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 took 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 Predecessor Credit Agreement bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the Company’s utilization of the facility. The Predecessor Credit Agreement was refinanced by the Senior Credit Agreement upon emergence from chapter 11 bankruptcy.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

6.75% Senior Notes

On February 16, 2017, the Predecessor Company issued $850.0 million aggregate principal amount of 6.75% senior notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bore interest at a rate of 6.75% per annum, payable semi-annually on February 15 and August 15 of each year. The maturity date of the 2025 Notes was February 15, 2025.

On February 15, 2018, the Predecessor Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at a price to the initial purchasers of 103.0% of par (the Additional 2025 Notes). The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after deducting initial purchasers’ premiums, commissions and estimated offering expenses. The proceeds were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 6, "Acquisitions and Divestitures,” and for general corporate purposes, including to fund the Company’s 2018 drilling program.

On the Petition Date, the 2025 Notes represented "Liabilities subject to compromise" and the corresponding discount of $6.6 million and premium of $4.9 million were written-off to "Reorganization items, net" on the consolidated statements of operations. On October 8, 2019, upon emergence from chapter 11 bankruptcy, the 2025 Notes were cancelled. The Company discontinued recording interest on the 2025 Notes as of the Petition Date. The contractual interest expense not accrued or recorded in the consolidated statement of operations was approximately $7.1 million, representing interest expense from the Petition Date through the Effective Date. Refer to Note 2, “Reorganization” for further details.

Debt Maturities

Aggregate maturities required on debt at December 31, 2020 (Successor) due in future years are as follows (in thousands):


2021	$	1,720
2022		489
2023		—
2024		158,000
2025		—
Thereafter		—
Total	$	160,209

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company expensed to ��Reorganization items, net” $9.3 million of debt issuance costs associated with its 2025 Notes, which were cancelled upon emergence from chapter 11 bankruptcy. During the period, the Company also expensed to “Interest expense and other” $0.7 million of debt issuance costs associated with its Predecessor Credit Agreement. At December 31, 2020 and 2019 (Successor), the Company did not have any unamortized debt issuance costs.

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 the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own

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



	Successor
	December 31, 2020
	Level 1		Level 2		Level 3		Total
Assets
Assets from derivative contracts	$	—	$	12,568	$	—	$	12,568

Liabilities
Liabilities from derivative contracts	$	—	$	26,416	$	—	$	26,416


	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 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.

The estimated fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company’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 December 31, 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 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 consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value

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amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2020 and 2019 (Successor) (in thousands):


Derivatives not designated		Asset derivative contracts					Liability derivative contracts
as hedging contracts under		Successor					Successor
ASC 815	Balance sheet location	December 31, 2020		December 31, 2019		Balance sheet location	December 31, 2020		December 31, 2019

Commodity contracts	Current assets - assets from derivative contracts	$	8,559	$	4,995	Current liabilities - liabilities from derivative contracts	$	(22,125)	$	(8,069)
Commodity contracts	Other noncurrent assets - assets from derivative contracts		4,009		224	Other noncurrent liabilities - liabilities from derivative contracts		(4,291)		(4,854)
Total derivatives not designated as hedging contracts under ASC 815		$	12,568	$	5,219		$	(26,416)	$	(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 consolidated statements of operations (in thousands):


		Amount of gain or (loss) recognized in income on derivative contracts for the
		Successor				Predecessor
				Period from		Period from
Derivatives not designated	Location of gain or (loss)			October 2, 2019		January 1, 2019
as hedging contracts	recognized in income	Year Ended		through		through		Year Ended
under ASC 815	on derivative contracts	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Commodity contracts:
Unrealized gain (loss) on commodity contracts	Other income (expenses) - net gain (loss) on derivative contracts	$	(6,143)	$	(18,681)	$	(45,834)	$	84,274
Realized gain (loss) on commodity contracts	Other income (expenses) - net gain (loss) on derivative contracts		44,902		1,989		11,502		8,351
Total net gain (loss) on derivative contracts		$	38,759	$	(16,692)	$	(34,332)	$	92,625

During the year ended December 31, 2020 (Successor), the Company terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $22.9 million, which were recorded in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

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At December 31, 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
2021	Fixed-Price Swap	Crude Oil	3,076,979	$	44.98
2021	Fixed-Price Swap	Natural Gas	4,657,871		2.74
2021	Basis Swap	Crude Oil	3,235,500		(0.07)
2021	Basis Swap	Natural Gas	4,657,871		(0.24)
2021	WTI NYMEX Roll	Crude Oil	2,941,000		(0.31)
2022	Fixed-Price Swap	Crude Oil	1,659,434		46.58
2022	Fixed-Price Swap	Natural Gas	1,297,420		3.01
2022	Producer Collar (Ceiling)	Natural Gas	2,388,624		2.65
2022	Producer Collar (Floor)	Natural Gas	2,388,624		2.50
2022	Basis Swap	Crude Oil	1,659,434		0.44
2022	Basis Swap	Natural Gas	3,686,044		(0.30)
2022	WTI NYMEX Roll	Crude Oil	1,843,434		(0.07)

The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2020 and 2019 (Successor) (in thousands):


	Derivative Assets				Derivative Liabilities
	Successor				Successor
Offsetting of Derivative Assets and Liabilities	December 31, 2020		December 31, 2019		December 31, 2020		December 31, 2019
Gross amounts presented in the consolidated balance sheet	$	12,568	$	5,219	$	(26,416)	$	(12,923)
Amounts not offset in the consolidated balance sheet		(8,968)		(4,557)		8,968		4,557
Net amount	$	3,600	$	662	$	(17,448)	$	(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.

The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 2, "Reorganization," constituted an event of default under the Company's derivatives contracts that gave the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 (Predecessor) and the Company received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, were secured on a super-priority pari passu basis with the Company's Predecessor Credit Agreement during the bankruptcy process and remained in place following the Company's chapter 11 bankruptcy.

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 consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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, 2018 (Predecessor)	$	6,914
Liabilities settled and divested⁽¹⁾		(229)
Additions		354
Accretion expense		307
Revisions in estimated cash flows		2,807
Liability for asset retirement obligations as of October 1, 2019 (Predecessor)	$	10,153
Fair Value Adjustment	$	—


Liability for asset retirement obligations as of October 1, 2019 (Successor)	$	10,153
Additions		293
Accretion expense		144
Liability for asset retirement obligations as of December 31, 2019 (Successor)	$	10,590
Liabilities settled and divested⁽¹⁾		(1,132)
Additions		488
Accretion expense		585
Revisions in estimated cash flows		52
Liability for asset retirement obligations as of December 31, 2020 (Successor)	$	10,583

(1)	See Note 6, “Acquisitions and Divestitures,” for additional information on the Company’s divestiture activities.

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 December 31, 2020 (Successor), the Company had in place two long-term crude oil contracts and 12 long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production.

Contingencies

On February 26, 2019 (Predecessor), a subsidiary of the Company was ordered to pay $9.1 million in a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013-0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage. The Court of Common Pleas of Mercer County, Pennsylvania marked the judgment as satisfied on February 3, 2020 (Successor) and the Company considers this contingency resolved.

In addition to the matter described above, 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 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, 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.

On February 9, 2018 (Predecessor), the Company sold 9.2 million shares of common stock, par value $0.0001 per share, in a public offering at a price of $6.90 per share. The net proceeds to the Company from the offering were approximately $60.4 million, after deducting the underwriters’ discounts and offering expenses. The Company used the net proceeds, together with the net proceeds from the issuance of the Additional 2025 Notes, to fund the cash consideration for the acquisition of the West Quito Draw Properties, and for general corporate purposes, including funding the Company’s 2018 drilling program.

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 December 31, 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 $42.65, $51.43 and $64.59, respectively.

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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 December 31, 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 year ended December 31, 2020 (Successor), the Company recognized $2.6 million related to stock-based compensation recorded as a component of “General and administrative” on the consolidated statement of operations.

For the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company recognized zero and a credit of $8.0 million, respectively, related to stock-based-compensation recorded as a component of "General and administrative" on the consolidated statement of operations. During 2019 (both in Successor and Predecessor periods), 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 or approval by the Bankruptcy Court. For the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company recognized incremental reductions to stock-based compensation expense of $9.5 million associated with these modifications.

For the year ended December 31, 2018 (Predecessor), the Company recognized $15.3 million related to stock-based compensation recorded as a component of "General and administrative" on the consolidated statement 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.

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The aggregate grant date fair value of options granted during the year ended December 31, 2020 (Successor) was $1.9 million. At December 31, 2020 (Successor), the Company had $0.9 million of unrecognized compensation expense related to non-vested stock-options to be recognized over a weighted-average period of 1.7 years.

No stock options were granted during the period of October 2, 2019 through December 31, 2019 (Successor) or the period of January 1, 2019 through October 1, 2019 (Predecessor).

The aggregate grant date fair value of options granted during the year ended December 31, 2018 (Predecessor) was $3.5 million. During the year ended December 31, 2018, the Predecessor Company received $0.3 million from the exercise of stock options. At December 31, 2018, the Predecessor Company had $5.2 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average vesting period of 0.9 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. The following table sets forth the stock option transactions for the periods indicated:


	Number	Weighted Average Exercise Price Per Share		Aggregate Intrinsic Value⁽¹⁾(In thousands)		Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2017 (Predecessor)	6,735,903	$	8.84	$	29	8.9
Granted	1,206,800		5.65
Exercised	(41,667)		7.75		29
Forfeited	(432,110)		8.68
Outstanding at December 31, 2018 (Predecessor)	7,468,926	$	8.34	$	—	8.1
Granted	—		—
Exercised	—		—
Forfeited	(5,182,238)		8.38
Cancelled⁽²⁾	(2,286,688)		8.26
Outstanding at October 1, 2019 (Predecessor)	—	$	—	$	—	—


Outstanding at October 1, 2019 (Successor)	—	$	—	$	—	—
Granted	—		—
Exercised	—		—
Forfeited	—		—
Outstanding at December 31, 2019 (Successor)	—	$	—	$	—	—
Granted	557,844		28.32
Exercised	—		—
Forfeited	(79,692)		28.32
Outstanding at December 31, 2020 (Successor)	478,152	$	28.32	$	—	6.2

(1)

The period end intrinsic value of stock options was calculated as the amount by which the closing market price on December 31, 2020 (Successor) and 2018 (Predecessor) of the underlying stock exceeded the exercise price of the option. The intrinsic value of stock options exercised during the year ended December 31, 2018 (Predecessor) was calculated as the amount by which the market price at the time of exercise of the underlying stock exceeded the exercise price of the option.

(2)	Immediately prior to emergence from chapter 11 bankruptcy, all outstanding options under the 2016 Plan were cancelled.

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Options outstanding at December 31, 2020 (Successor) consisted of the following:


Outstanding						Exercisable⁽¹⁾
					Weighted Average						Weighted Average
			Weighted Average		Remaining		Weighted Average		Aggregate		Remaining
Range of Grant			Exercise Price		Contractual Life		Exercise Price		Intrinsic		Contractual Life
Prices Per Share		Number	per Share		(Years )	Number	per Share		Value		(Years )
$	18.91	159,384	$	18.91	6.2	—	$	—	$	—	—
	28.23	159,384		28.23	6.2	—		—		—	—
	37.83	159,384		37.83	6.2	—		—		—	—

(1)	At December 31, 2020 (Successor), none of the Company’s stock options were exercisable due to service performance conditions or options exercise prices above current market value of the underlying stock.

The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Company’s stock options for years ended December 31, 2020 (Successor) and 2018 (Predecessor) are set forth in the following table:


	Successor			Predecessor
	Year Ended			Year Ended
	December 31, 2020			December 31, 2018
Weighted average value per option granted during the period	$	3.36		$	2.92
Assumptions:
Stock price volatility⁽¹⁾		61.87	%		52.08	%
Risk free rate of return		1.21	%		2.63	%
Expected term		4.75	years		6	years

(1)	Due to the Successor and Predecessor Company’s limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available.

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 of restricted stock 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 of restricted stock vested six months from the date of grant.

During the year ended December 31, 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 December 31, 2020 (Successor), the Company had $4.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted-average period of 2.5 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. The aggregate grant date fair value of these RSUs was $5.0 million.

●

0.2 million RSUs granted will vest in full only upon achievement of certain business combination goals, as defined in the award agreements. The aggregate grant date fair value of these RSUs was $2.1 million. As of December 31, 2020 (Successor), a business combination, as defined in the award 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.

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●

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. The aggregate grant date fair value of these RSUs was $2.3 million.

No shares of restricted stock were granted during the period of October 2, 2019 through December 31, 2019 (Successor). The aggregate grant date fair value of shares granted during the period from January 1, 2019 through October 1, 2019 (Predecessor) was $5.4 million.

The aggregate grant date fair value of shares granted during the year ended December 31, 2018 (Predecessor) was $12.7 million. At December 31, 2018, the Predecessor Company had $6.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average vesting period of 1.1 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.

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


	Number of Shares	Weighted Average Grant Date Fair Value Per Share		Aggregate Intrinsic Value⁽¹⁾(In thousands)
Unvested outstanding shares at December 31, 2017 (Predecessor)	745,507	$	7.05	$	5,643
Granted	2,326,961		5.47
Vested	(537,411)		5.89
Forfeited	(262,164)		6.29
Unvested outstanding shares at December 31, 2018 (Predecessor)	2,272,893	$	5.80	$	3,864
Granted	4,163,348		1.29
Vested	(1,611,465)		4.65
Accelerated vesting⁽²⁾	(2,724,086)		2.07
Forfeited	(2,100,690)		2.58
Unvested outstanding shares at October 1, 2019 (Predecessor)	—	$	—	$	—


Unvested outstanding shares at October 1, 2019 (Successor)	—	$	—	$	—
Granted	—		—
Vested	—		—
Forfeited	—		—
Unvested outstanding shares at December 31, 2019 (Successor)	—	$	—	$	—
Granted	987,590		9.46
Vested	—		—
Forfeited	(113,456)		9.36
Unvested outstanding shares at December 31, 2020 (Successor)	874,134	$	9.48	$	3,287

(1)

The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2020 (Successor) and 2018 (Predecessor) of the underlying stock multiplied by the number of restricted shares that would be issuable. The total fair value of shares vested was $1.8 million and $2.0 million for the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

(2)	Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock under the 2016 Plan was vested.

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The assumptions used in calculating the Monte Carlo valuation model fair value of the Company’s RSUs with performance based vesting conditions for the year ended December 31, 2020 (Successor) are set forth in the following table:


	Successor
	Year Ended
	December 31, 2020
Weighted average value per performance based RSUs granted during the period	$	6.13
Assumptions:
Stock price volatility⁽¹⁾		51.79	%
Risk free rate of return		1.22	%
Expected term		3.9	years

(1)	Due to the Successor Company’s limited historical data, expected volatility was estimated using volatilities of peer entities as defined in the award agreements whose share prices and assumptions were publicly available.

14. INCOME TAXES

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


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Current:
Federal	$	—	$	—	$	—	$	—
State		—		—		—		—
		—		—		—		—
Deferred:
Federal		—		—		95,791		(95,791)
State		—		—		—		—
		—		—		95,791		(95,791)
Total income tax benefit (provision)	$	—	$	—	$	95,791	$	(95,791)

The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the year ended December 31, 2020 (Successor),

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the period from October 2, 2019 through December 31, 2019 (Successor), the period from January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), as follows (in thousands):


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Expected tax benefit (provision)	$	48,238	$	2,196	$	262,888	$	(29,767)
Stock-based compensation		—		—		(6,093)		(350)
Capital loss		—		—		271,248		—
Increase (reduction) in deferred tax asset		—		—		(9,287)		(201,903)
Change in valuation allowance and related items		(10,849)		(1,506)		(186,851)		136,432
Attribute reduction		(37,985)		—		(229,385)		—
Permanent adjustments		577		(690)		(7,241)		(203)
Other		19		—		512		—
Total income tax benefit (provision)	$	—	$	—	$	95,791	$	(95,791)

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


	Successor
	December 31, 2020		December 31, 2019
Deferred noncurrent income tax assets:
Net operating loss carry-forwards	$	94,742	$	46,382
Built in loss adjustment Section 382		98,416		142,285
Capital loss carryforward		74,848		74,848
Stock-based compensation expense		1,448		—
Asset retirement obligations		2,347		2,224
Book-tax differences in property basis		199,170		200,478
Unrealized hedging transactions		2,908		1,618
Disallowed interest Section 163(j)		13,579		7,722
Basis difference in debt		1,687		2,142
Operating lease liability		85		666
Other		374		991
Gross deferred noncurrent income tax assets		489,604		479,356
Valuation allowance		(489,539)		(478,690)
Deferred noncurrent income tax assets	$	65	$	666

Deferred noncurrent income tax liabilities:
Lease right of use	$	(65)	$	(666)
Deferred noncurrent income tax liabilities	$	(65)	$	(666)
Net noncurrent deferred income tax assets (liabilities)	$	—	$	—

The amount of U.S. consolidated Net Operating Losses (NOLs) available as of December 31, 2020 (Successor) after attribute reduction is estimated to be approximately $905.2 million, but the amount after attribute reduction and the Section 382 limitation is $451.0 million. Of this amount, $105.6 million is subject to the 20 year carryforward period and will expire in 2037. The remaining $345.4 million may be carried forward indefinitely but is in part subject to a Section 382 limitation.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2020 (Successor), a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2020 (Successor) of $489.5 million, an increase of $10.8 million from December 31, 2019 (Successor). The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized.

The Company emerged from Chapter 11 Bankruptcy on October 8, 2019. Under the Plan, a substantial portion of the Company’s pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from chapter 11 bankruptcy proceedings, U.S. CODI was approximately $524.8 million, which reduced the value of the Company’s net operating losses and capital losses on January 1, 2020. The deferred tax balances disclosed above reflect the estimated impact of the attribute reduction on January 1, 2020.

IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company's emergence from chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The limitation under the IRC is based on the value of the corporation as of the emergence date. The ownership changes and resulting annual limitation resulted in the expiration of approximately $454.2 million of net operating losses generated prior to the emergence date. The expiration of these tax attributes was fully offset by a corresponding decrease in the Company's U.S. valuation allowance, which results in no net tax provision. An additional ownership change was experienced in December 2018 (Predecessor). This ownership change and resulting annual limitation generated the estimated expiration of approximately $891.5 million of net operating loss. The expiration of these tax attributes was partially offset by a corresponding decrease in the Company’s U.S. valuation allowance, which resulted in a $95.8 million deferred tax expense placing the Company in a net deferred tax liability position.

ASC 740, Income Taxes (ASC 740) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor).

Generally, the Company’s income tax years 2017 through 2020 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes.

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The Company recognizes interest and penalties accrued to unrecognized benefits in “Interest expense and other” in its consolidated statements of operations. For the year ended December 31, 2020 (Successor), the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recognized no interest and penalties.

During 2020, the CARES Act and the Consolidated Appropriations Act of 2021 (the CAA) were signed into law. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018 to 2020 NOLs, removing the 80% limitation on the utilization of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, as well as other provisions. The CAA extends various expiring tax provisions, clarifies that debt forgiven under the Paycheck Protection Program (PPP) is not included in gross income, clarifies that certain business expenses paid with forgiven PPP funds are tax deductible, as well as other tax provisions. Both the CARES Act and CAA did not have a material impact to the Company’s consolidated financial statements and related disclosures.

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15. 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
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018
Basic:
Net income (loss) available to common stockholders	$	(229,707)	$	(10,460)	$	(1,156,053)	$	45,959
Weighted average basic number of common shares outstanding		16,204		16,204		158,925		157,011
Basic net income (loss) per common share	$	(14.18)	$	(0.65)	$	(7.27)	$	0.29

Diluted:
Net income (loss) available to common stockholders	$	(229,707)	$	(10,460)	$	(1,156,053)	$	45,959
Weighted average basic number of common shares outstanding		16,204		16,204		158,925		157,011
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 stock		—		—		Anti-dilutive		284
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		—		—		—
Vesting of Successor restricted stock units		Anti-dilutive		—		—		—
Weighted average diluted number of common shares outstanding		16,204		16,204		158,925		157,295
Diluted net income (loss) per common share	$	(14.18)	$	(0.65)	$	(7.27)	$	0.29

Common stock equivalents, including warrants, stock options and restricted stock units, if considered issuable, totaling 7.7 million shares for the year ended December 31, 2020 (Successor) 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 loss.

Common stock equivalents, including warrants, totaling 6.9 million shares for the period of October 2, 2019 through December 31, 2019 (Successor) 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 loss. Common stock equivalents, including stock options, restricted shares and warrants totaling 14.1 million shares for the period of January 1, 2019 through October 1, 2019 (Predecessor) 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 loss.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Common stock equivalents, including stock options, restricted shares and warrants, totaling 13.1 million shares for the year ended December 31, 2018 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

16. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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


	Successor
	December 31, 2020		December 31, 2019
Accounts receivable, net:
Oil, natural gas and natural gas liquids revenues	$	22,781	$	36,367
Joint interest accounts		8,543		10,145
Other		918		1,992
	$	32,242	$	48,504
Prepaids and other:
Prepaids	$	892	$	2,093
Income tax receivable		—		1,250
Funds in escrow		1,740		4,000
Other		108		36
	$	2,740	$	7,379
Funds in escrow and other:
Oil, natural gas and natural gas liquids revenues	$	1,720	$	—
Funds in escrow		581		580
Other		50		123
	$	2,351	$	703
Accounts payable and accrued liabilities:
Trade payables	$	22,740	$	36,038
Accrued oil and natural gas capital costs		8,344		22,781
Revenues and royalties payable		16,412		25,457
Accrued interest expense		482		604
Accrued employee compensation		3,223		2,947
Accrued lease operating expenses		7,622		9,230
Other		105		276
	$	58,928	$	97,333

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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates reported herein for the years ended December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves reports incorporated herein are Mr. Neil H. Little and Mr. Edward Roy III. Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at Netherland, Sewell since 2011 and has over nine years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from University of Houston in 2007 with a Master of Business Administration Degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at Netherland, Sewell since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology. Netherland, Sewell has reported to the Company that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are both proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Company’s board of directors has established an independent reserves committee composed of independent directors with experience in energy company reserve evaluations. The Company’s independent engineering firm reports jointly to the reserves committee and to Executive Vice President and Chief Operating Officer. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to the board of directors as to whether to approve the report prepared by the independent engineering firm. Mr. Daniel P. Rohling, the Company’s Executive Vice President and Chief Operating Officer is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. He has more than 14 years of oil and gas operations experience and earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is an active member of the Society of Petroleum Engineers.

The reserves information in this Annual Report on Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of

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drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following tables illustrate changes in the Company’s estimated net proved developed and proved undeveloped reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $39.54 per barrel, $55.85 per barrel and $65.56 per barrel, respectively. The natural gas prices as of December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $1.99 per MMBtu, $2.58 per MMBtu and $3.10 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.


	Total Proved Reserves
			Natural Gas
		Natural Gas	Liquids	Equivalent
	Oil (MBbls)	(MMcf)	(MBbls)	(MBoe)
Proved reserves, December 31, 2017 (Predecessor)	34,133	46,738	9,196	51,119
Extensions and discoveries	31,104	68,772	10,602	53,168
Purchase of minerals in place	2,201	4,770	669	3,665
Production	(3,558)	(4,607)	(749)	(5,075)
Sale of minerals in place	(14)	(20)	(4)	(21)
Revision of previous estimates	(13,212)	(10,904)	(2,614)	(17,644)
Proved reserves, December 31, 2018 (Predecessor)	50,654	104,749	17,100	85,212
Extensions and discoveries	9,161	12,372	1,952	13,175
Production	(3,780)	(9,136)	(1,262)	(6,565)
Revision of previous estimates	(16,801)	(35,724)	(7,015)	(29,769)
Proved reserves, December 31, 2019 (Successor)	39,234	72,261	10,775	62,053
Extensions and discoveries	8,268	12,157	2,090	12,384
Production	(3,446)	(8,769)	(1,262)	(6,170)
Sale of minerals in place	(1,433)	(2,177)	(246)	(2,042)
Revision of previous estimates	(4,407)	5,034	718	(2,850)
Proved reserves, December 31, 2020 (Successor)	38,216	78,506	12,075	63,375

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	Equivalent (Mboe)
	Proved	Proved
	Developed	Undeveloped	Total Proved
	Reserves	Reserves	Reserves
Proved reserves, December 31, 2017 (Predecessor)	16,018	35,101	51,119
Extensions and discoveries	13,091	40,077	53,168
Purchase of minerals in place	3,665	—	3,665
Production	(5,075)	—	(5,075)
Sale of minerals in place	(21)	—	(21)
Transfers	11,964	(11,964)	—
Revision of previous estimates	227	(17,871)	(17,644)
Proved reserves, December 31, 2018 (Predecessor)	39,869	45,343	85,212
Extensions and discoveries	2,813	10,362	13,175
Production	(6,565)	—	(6,565)
Transfers	10,213	(10,213)	—
Revision of previous estimates	(8,395)	(21,374)	(29,769)
Proved reserves, December 31, 2019 (Successor)	37,935	24,118	62,053
Extensions and discoveries	13	12,371	12,384
Production	(6,170)	—	(6,170)
Sale of minerals in place	(2,042)	—	(2,042)
Transfers	6,513	(6,513)	—
Revision of previous estimates	(17)	(2,833)	(2,850)
Proved reserves, December 31, 2020 (Successor)	36,232	27,143	63,375


	Proved Developed Reserves
			Natural Gas
		Natural Gas	Liquids	Equivalent
	Oil (MBbls)	(MMcf)	(MBbls)	(MBoe)
December 31, 2020 (Successor)	20,371	51,097	7,345	36,232
December 31, 2019 (Successor)	22,821	48,558	7,021	37,935
December 31, 2018 (Predecessor)	24,672	44,743	7,740	39,869


	Proved Undeveloped Reserves
			Natural Gas
		Natural Gas	Liquids	Equivalent
	Oil (MBbls)	(MMcf)	(MBbls)	(MBoe)
December 31, 2020 (Successor)	17,845	27,409	4,730	27,143
December 31, 2019 (Successor)	16,413	23,703	3,754	24,118
December 31, 2018 (Predecessor)	25,982	60,006	9,360	45,343

The Company’s proved reserves have been estimated using deterministic methods. At December 31, 2020 (Successor), total proved reserves were approximately 63.4 MMBoe, a 1.3 MMBoe net increase over the previous year’s estimate of 62.1 MMBoe. The net increase in total proved reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by production of 6.2 MMBoe, sales of 2.0 MMBoe, and net negative revisions of 2.9 MMBoe due primarily to decreases in SEC pricing.

At December 31, 2020 (Successor), the Company’s proved developed reserves were approximately 36.2 MMBoe, a 1.7 MMBoe net decrease from the previous year’s estimate of 37.9 MMBoe. The net decrease in total proved reserves was the result of production of 6.2 MMBoe and sales of 2.0 MMBoe, partially offset by development of 6.5 MMBoe (transferred from proved undeveloped).

At December 31, 2020 (Successor), the Company’s estimated proved undeveloped (PUD) reserves were approximately 27.1 MMBoe, a 3.0 MMBoe net increase from the previous year’s estimate of 24.1 MMBoe. The net increase in total PUD reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by development of 6.5 MMBoe and negative revisions of 2.8 MMBoe due primarily to decreases in SEC pricing. Of the 12.4 MMBoe of extensions and discoveries in PUD reserves, all are associated with drilling extensions in the Delaware

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Basin. None of the extensions and discoveries in PUD reserves in 2020 (Successor) were associated with infill drilling activity.

At December 31, 2019 (Successor), the Company’s proved developed reserves were approximately 37.9 MMBoe, a 2.0 MMBoe net decrease from the previous year’s estimate of 39.9 MMBoe. The net decrease in total proved reserves was the result of negative revisions of 8.4 MMBoe and production of 6.5 MMBoe, partially offset by additions and extensions of 2.8 MMBoe and development of 10.1 MMBoe (transferred from proved undeveloped). Negative revisions of 8.4 MMBoe primarily relate to changes in the Company’s development plans to focus on Monument Draw and due to the effect of lower prices. Of the 2.8 MMBoe of extensions and discoveries in proved developed reserves, approximately 1.2 MMBoe are associated with infill drilling activity and 1.6 MMBoe are associated with drilling extensions in the Delaware Basin.

At December 31, 2019 (Successor), the Company’s estimated PUD reserves were approximately 24.1 MMBoe, a 21.2 MMBoe net decrease from the previous year’s estimate of 45.3 MMBoe. The net decrease in total PUD reserves was the result of negative revisions of 21.4 MMBoe and development of 10.2 MMBoe, partially offset by additions and extensions of 10.4 MMBoe. The negative revisions to PUD reserves in 2019 were primarily attributable to the changes in the Company’s development plans to focus on Monument Draw and due to the effect of lower prices. Of the 10.4 MMBoe of extensions and discoveries in PUD reserves, approximately 6.6 MMBoe are associated with infill drilling activity and 3.8 MMBoe are associated with drilling extensions in the Delaware Basin.

At December 31, 2018, the Predecessor Company’s proved developed reserves were approximately 39.9 MMBoe, a 23.9 MMBoe net increase over the previous year’s estimate of 16.0 MMBoe. The net increase in proved developed reserves was the result of additions and extensions of 13.1 MMBoe, acquisitions of 3.7 MMBoe, development of 12.0 MMBoe (transferred from PUD), and net positive revisions of 0.2 MMBoe, partially offset by production of 5.1 MMBoe. Of the 13.1 MMBoe of extensions and discoveries in proved developed reserves, approximately 1.8 MMBoe are associated with infill drilling activity and 11.3 MMBoe are associated with drilling extensions in the Delaware Basin. Net positive revisions of 0.2 MMBoe in proved developed reserves include 0.3 MMBoe in net negative performance revisions and 0.5 MMBoe in positive revisions due to increase in prices.

At December 31, 2018, the Predecessor Company’s estimated PUD reserves were approximately 45.3 MMBoe, a 10.2 MMBoe net increase over the previous year’s estimate of 35.1 MMBoe. The net increase in PUD reserves was the result of additions and extensions of 40.1 MMBoe, partially offset by net negative revisions of 17.9 MMBoe and development of 12.0 MMBoe. Of the 40.1 MMBoe of extensions and discoveries in proved undeveloped reserves, approximately 29.2 MMBoe are associated with infill drilling and 10.8 MMBoe are associated with drilling extensions in the Delaware Basin. Net negative revisions of 17.9 MMBoe in proved undeveloped reserves include net negative revisions of 18.6 MMBoe resulting from the removal of PUD locations that were rescheduled to be developed beyond five years from when they were initially recorded, and 0.7 MMBoe of positive revisions due to the effect of higher prices.

As of December 31, 2020 (Successor) all of the Company’s PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2020 (Successor), approximately $43.3 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

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Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line openhole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic EURs from individual producing wells. The Company relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves. Out of total proved undeveloped reserves of 27.1 MMBoe at December 31, 2020 (Successor), 13.7 MMBoe were associated with 15 gross PUD locations that were more than one offset location from a producing well.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depletion, depreciation and accretion (in thousands):


	Successor				Predecessor
	December 31, 2020		December 31, 2019		December 31, 2018
Evaluated oil and natural gas properties	$	509,274	$	420,609	$	1,470,509
Unevaluated oil and natural gas properties		75,494		105,009		971,918
		584,768		525,618		2,442,427
Accumulated depletion		(295,163)		(19,474)		(639,951)
	$	289,605	$	506,144	$	1,802,476

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:


	Successor				Predecessor
			Period from		Period from
			October 2, 2019		January 1, 2019
	Year Ended		through		through		Year Ended
	December 31, 2020		December 31, 2019		October 1, 2019		December 31, 2018

Property acquisition costs, proved	$	23	$	—	$	—	$	36,505
Property acquisition costs, unproved		—		—		2,809		297,537
Exploration and extension well costs		14,082		9,209		89,389		293,115
Development costs⁽¹⁾		43,256		15,839		60,275		181,987
Total costs	$	57,361	$	25,048	$	152,473	$	809,144

(1)

Excludes $31.5 million, $11.3 million, $72.9 million and $122.0 million for the year ended December 31, 2020 (Successor), the period from October 2, 2019 to December 31, 2019 (Successor), the period from January 1, 2019 to October 1, 2019 (Predecessor), and the year ended December 31, 2018 (Predecessor) of development costs related to the Company’s treating equipment and gathering support facilities.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractive Activities—Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

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The Company believes that the following factors should be taken into account when reviewing the following information:

●

future costs and selling prices will probably differ from those required to be used in these calculations;

●

due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

●

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

●

future net revenues may be subject to different rates of income taxation.

At December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor), as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure is as follows:


	Years Ended December 31,
	2020		2019		2018

	(In thousands)
Future cash inflows	$	1,660,950	$	2,257,083	$	3,602,719
Future production costs		(911,099)		(1,207,370)		(1,441,754)
Future development costs		(315,078)		(261,747)		(412,961)
Future income tax expense		(1,459)		(1,577)		(34,956)
Future net cash flows before 10% discount		433,314		786,389		1,713,048
10% annual discount for estimated timing of cash flows		(223,918)		(377,514)		(859,481)
Standardized measure of discounted future net cash flows	$	209,396	$	408,875	$	853,567

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2020:


	Years Ended December 31,
	2020		2019		2018

	(In thousands)
Beginning of year	$	408,875	$	853,567	$	336,033
Sale of oil and natural gas produced, net of production costs		(34,888)		(104,007)		(119,003)
Purchase of minerals in place		—		—		36,600
Sales of minerals in place		(22,387)		—		(119)
Extensions and discoveries		17,127		71,585		510,492
Changes in income taxes, net		25		5,845		(5,155)
Changes in prices and costs		(231,791)		(306,466)		(12,954)
Previously estimated development costs incurred		68,135		85,538		115,213
Net changes in future development costs		3,867		26,742		23,909
Revisions of previous quantities		(30,757)		(266,538)		(53,580)
Accretion of discount		40,914		85,968		33,699
Changes in production rates and other		(9,724)		(43,359)		(11,568)
End of year	$	209,396	$	408,875	$	853,567

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(f) and 15d-15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 (Successor) to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Management has assessed our internal control over financial reporting as of December 31, 2020 (Successor). The unqualified report of management thereon is included in Item 8. Consolidated Financial Statements and Supplementary Data of this Annual Report on Form 10-K and is incorporated by reference herein.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the three months ended December 31, 2020 (Successor) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2021 Annual Meeting of Stockholders.

The Company's Code of Conduct and Code of Ethics for the Principal Executive Officer and Senior Financial Officers can be found on the Company's website located at www.battalionoil.com. Any stockholder may request a printed copy of such materials by submitting a written request to the Company's Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least twelve months after the initial disclosure of such waiver.

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ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information

The following table sets forth certain information as of December 31, 2020 with respect to compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.


				Number of Securities
				Remaining Available for
				Future Issuance Under
	Number of Securities		Weighted-Average	Equity Compensation
	to be Issued Upon Exercise		Exercise Price of	Plans (Excluding
	of Outstanding		Outstanding Options and	Securities Reflected in
Plan Category	Options and Rights(a)		Rights	Column(a))
Equity compensation plans approved by security holders⁽¹⁾	1,352,286	$	28.32	152,998
Equity compensation plans not approved by security holders	—		—	—
	1,352,286	$	28.32	152,998

(1)	Represents information for the 2020 Long-Term Incentive Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1)

Consolidated Financial Statements:

The consolidated financial statements of the Company and its subsidiaries and reports of independent registered public accounting firms listed in Section 8 of this Annual Report on Form 10-K are filed as a part of this Annual Report on Form 10-K.

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(2)

Consolidated Financial Statements Schedules:

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

(3)

Exhibits:

2.1		Order of the Bankruptcy Court, dated September 24 2019, confirming the Joint Prepackaged Plan of Reorganization of Halcón Resources Corporation, et al, under Chapter 11 of the Bankruptcy Code, together with such Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed September 26, 2019).
2.2		Agreement of Sale and Purchase, dated as of July 10, 2017, by and among Halcón Energy Properties, Inc., Halcón Operating Co., Inc., HRC Operating, LLC, and HRC Energy, LLC, as sellers, Halcón Williston I, LLC and Halcón Williston II, LLC, as the companies, Bruin Williston Holdings, LLC, as purchaser, and Halcón Resources Corporation, as guarantor (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed July 11, 2017).
2.3		Purchase and Sale Agreement dated February 6, 2018, by and between Halcón Energy Properties, Inc. and SWEPI LP (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 8, 2018).
2.4		Asset Purchase Agreement, dated October 31, 2018, by and among Halcón Field Services, LLC, Halcón Operating Co., Inc., Halcón Energy Properties, Inc. and Water Bridge Texas Midstream LLC (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10-Q filed November 8, 2018).
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).
4.1		Description of Battalion Oil Corporation’s securities registered under Section 12 of the Exchange Act. (Incorporated by reference to Exhibit 4.1 of our Annual Report on Form 10-K filed March 25, 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).
10.2		Warrant Agreement, dated as of October 8, 2019, by and between Halcón Resources Corporation and Broadridge Corporate Issuer Solutions, Inc., as warrant agent (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed October 8, 2019).
10.3		Registration Rights Agreement, dated as of October 8, 2019, by and among Halcón Resources Corporation and each of the parties thereto, as investors (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed October 8, 2019).

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10.4	^†	Battalion Oil Corporation 2020 Long-Term Incentive Plan, effective as of January 1, 2020 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 31, 2020).
10.5	^†	Employment Agreement between Richard H. Little and Battalion Oil Corporation effective as of January 28, 2020 (Incorporated by reference to Exhibit 10.5 of our Annual Report on Form 10-K filed March 25, 2020).
10.6	^†	Employment Agreement between Ragan T. Altizer and Battalion Oil Corporation effective as of January 28, 2020 (Incorporated by reference to Exhibit 10.6 of our Annual Report on Form 10-K filed March 25, 2020).
10.7	^†	Employment Agreement between Daniel P. Rohling and Battalion Oil Corporation effective as of January 28, 2020 (Incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K filed March 25, 2020).
10.8	^†	Employment Agreement between R. Kevin Andrews and Battalion Oil Corporation effective as of August 17, 2020 (Incorporated by reference to Exhibit 10.12 of our Quarterly Report on Form 10-Q filed November 9, 2020).
10.22	^†	Form of Nonqualified Stock Option Award Agreement (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed January 31, 2020).
10.23	^†	Form of Base Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed January 31, 2020).
10.24	^†	Form of Performance-Based Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed January 31, 2020).
10.25	^†	Form of M&A Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed January 31, 2020).
21.1^*		List of Subsidiaries of Battalion Oil Corporation
23.1^*		Consent of Deloitte & Touche LLP
23.2^*		Consent of Netherland, Sewell & Associates, Inc.
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
99.1^*		Report of Netherland, Sewell & Associates, Inc.
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.

The registrant has not filed with this report copies of the instruments defining rights of all holders of long-term debt of the registrant and its consolidated subsidiaries based upon the exception set forth in Item 601(b)(4)(iii)(A) of Regulation S-K. Copies of such instruments will be furnished to the SEC upon request.

ITEM 16. FORM 10-K SUMMARY

None.

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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.


	BATTALION OIL CORPORATION


Date: March 8, 2021	By:	/s/ RICHARD H. LITTLE
		Richard H. Little
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

/s/ RICHARD H. LITTLE

Richard H. Little

Director and Chief Executive Officer

March 8, 2021

/s/ R. KEVIN ANDREWS

R. Kevin Andrews

Executive Vice President, Chief Financial Officer and Treasurer

March 8, 2021

/s/ WILLIAM TRANSIER

William Transier

Chairman of the Board

March 8, 2021

/s/ JONATHAN BARRETT

Jonathan Barrett

Director

March 8, 2021

/s/ DAVID CHANG

David Chang

Director

March 8, 2021

/s/ SCOTT GERMANN

Scott Germann

Director

March 8, 2021

/s/ GREGORY HINDS

Gregory Hinds

Director

March 8, 2021

/s/ ALLEN LI

Allen Li

Director

March 8, 2021

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