BATTALION OIL CORP - Annual Report: 2020 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

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FORM 10-K

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

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For the fiscal year ended December 31, 2020

Commission File Number: 001-35467

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Battalion Oil Corporation

(Exact name of registrant as specified in its charter)

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1000 Louisiana Street, Suite 6600, Houston, TX 77002

(Address of principal executive offices)

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(832) 538-0300

(Registrant’s telephone number)

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

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

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

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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 ☒

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

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

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Indicate by check mark 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. ☒

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

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

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Indicate by check mark whether the registrant 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. ☐

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

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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.

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

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DOCUMENTS INCORPORATED BY REFERENCE

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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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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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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.

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Northern West Quito Assets Divestiture

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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).

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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.

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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.

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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

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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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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).

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.

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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:

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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):

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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.

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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:

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):

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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:

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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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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.

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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.

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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

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

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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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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.

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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:

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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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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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.

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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.

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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.

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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.

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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:

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:

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:

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:

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.

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,

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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

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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

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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.

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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

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 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 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.

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. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

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

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

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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.

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Northern West Quito Assets Divestiture

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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).

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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 fiscal quarter ended September 30, 2020 and suspended testing of the Current Ratio until the fiscal quarter ending December 31, 2021.

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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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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

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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

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.

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.”

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.

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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.

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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):

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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.

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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.

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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.

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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.

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.

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.

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