10-K 1 batl-20191231x10k.htm 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2019

Commission File Number: 001‑35467

Battalion Oil Corporation

(Exact name of registrant as specified in its charter)

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

1000 Louisiana Street, Suite 6600, Houston, TX 77002

(Address of principal executive offices)

(832) 538‑0300

(Registrant’s telephone number)

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

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

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

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

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

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

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

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

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

Large accelerated filer ☐ | Accelerated filer ☐ | Non‑accelerated filer ☐ | Smaller reporting company ☒ Emerging growth company ☐

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

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

As of March 20, 2020, there were 16,203,967 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, 2019, the aggregate market value of shares of common stock held by non-affiliates of the registrant was approximately $25.4 million.

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

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13, and 14, is incorporated by reference to portions of the registrant’s definitive proxy statement for its 2020 annual meeting of stockholders which will be filed no later than 120 days after December 31, 2019.

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TABLE OF CONTENTS

|  |  |  | PAGE
PART I |  |  |  |
ITEM 1. |  | Business |  | 8
ITEM 1A. |  | Risk factors |  | 26
ITEM 1B. |  | Unresolved staff comments |  | 42
ITEM 2. |  | Properties |  | 42
ITEM 3. |  | Legal proceedings |  | 42
ITEM 4. |  | Mine safety disclosures |  | 43
PART II |  |  |  |
ITEM 5. |  | Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities |  | 44
ITEM 6. |  | Selected financial data |  | 44
ITEM 7. |  | Management’s discussion and analysis of financial condition and results of operations |  | 45
ITEM 7A. |  | Quantitative and qualitative disclosures about market risk |  | 64
ITEM 8. |  | Consolidated financial statements and supplementary data |  | 66
ITEM 9. |  | Changes in and disagreements with accountants on accounting and financial disclosure |  | 126
ITEM 9A. |  | Controls and procedures |  | 126
ITEM 9B. |  | Other information |  | 127
PART III |  |  |  |
ITEM 10. |  | Directors, executive officers and corporate governance |  | 127
ITEM 11. |  | Executive compensation |  | 127
ITEM 12. |  | Security ownership of certain beneficial owners and management and related stockholder matters |  | 127
ITEM 13. |  | Certain relationships and related transactions, and director independence |  | 127
ITEM 14. |  | Principal accountant fees and services |  | 128
PART IV |  |  |  |
ITEM 15. |  | Exhibits and financial statements schedules |  | 128
ITEM 16. |  | Form 10-K Summary |  | 130

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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:

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

| · |  | our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions;

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

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

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

| · |  | the presence or recoverability of estimated oil and natural gas reserves attributable to our properties and the actual future production rates and associated costs of producing those oil and natural gas reserves;

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

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

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

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

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

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

| · |  | access to adequate gathering systems, processing and treating facilities and transportation take‑away capacity to move our production to marketing outlets to sell our production at market prices;

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

| · |  | contractual limitations that affect our management’s discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

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

| · |  | competition, including competition for acreage in our resource play;

| · |  | environmental risks;

| · |  | exploration and development risks;

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

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

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

| · |  | other economic, competitive, governmental, regulatory, legislative, including federal and state regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

| · |  | the possibility that acquisitions may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and may divert management’s time and energy;

| · |  | our ability to successfully integrate acquired oil and natural gas businesses and operations;

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

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

All forward‑looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward‑looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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

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 (the Williston Divestiture) and in the El Halcón area of East Texas (the El Halcón Divestiture). 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, 2019 (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 the West Texas Intermediate (WTI) crude oil spot price of $55.85 per Bbl and Henry Hub natural gas spot price of $2.578 per MMBtu, were approximately 62.1 MMBoe, consisting of 39.2 MMBbls of oil, 10.8 MMBbls of natural gas liquids, and 72.3 Bcf of natural gas. Approximately 61% of our estimated proved reserves were classified as proved developed as of December 31, 2019 (Successor). We maintain operational control of approximately 99% of our estimated proved reserves.

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, compared to total operating revenues for 2018 (Predecessor) of $226.6 million. 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, compared to average daily production of 13,904 Boe/d during 2018 (Predecessor). Our average daily oil and natural gas production increased year over year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. In 2019 (for the combined Successor and Predecessor periods), we drilled and cased 14 gross (12.5 net) operated wells, completed 17 gross (15.9 net) operated wells, and put online 17 gross (15.9 net) operated wells.

Recent Developments

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.”

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Reorganization

On August 2, 2019, we entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of our 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, we filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to effect a prepackaged plan of reorganization (the Plan) as contemplated in the Restructuring Support Agreement. Our chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019 (the Effective Date), we emerged from chapter 11 bankruptcy. Although we are not a debtor-in-possession, the Predecessor Company was a debtor-in-possession between August 7, 2019 and October 8, 2019. As such, certain aspects of the chapter 11 proceedings and related matters are summarized below to provide context to our financial condition and results of operations for the periods presented.

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

| · |  | borrowings outstanding under the Predecessor Credit Agreement, plus unpaid interest and fees, were repaid in full, in cash, including by a refinancing (see below for further details regarding the credit agreement);

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

| · |  | our general unsecured claims were unimpaired and paid in full in the ordinary course; and

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

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

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

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

Fresh-start Accounting

Upon emergence from chapter 11 bankruptcy, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (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 the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

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 statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to October 1, 2019 are not comparable to our consolidated financial statements prior to October 1, 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. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of us prior to, and including, October 1, 2019, and as such, “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.

Common Stock

On the Effective Date, pursuant to the terms of the Plan, all shares of our Predecessor Company were cancelled and we filed an amended and restated certificate of incorporation with the Delaware Secretary of State and adopted amended and restated bylaws. Pursuant to the amended and restated certificate of incorporation, the number of authorized shares of common stock which we have the authority to issue was reduced from 1,001,000,000 to 101,000,000. Of the 101,000,000 authorized shares, 100,000,000 are common stock, par value $0.0001 per share and 1,000,000 are preferred stock, par value $0.0001 per share.

On the Effective Date, pursuant to the terms of the Plan and the confirmation order, we issued:

| · |  | 421,827 shares of New Common Shares pursuant to the Existing Equity Interests Rights Offering; 8,059,111 shares of New Common Shares pursuant to the Senior Noteholder Rights Offering; and 3,558,334 shares of New Common Shares in connection with the backstop commitment, which includes 657,590 shares of New Common Shares issued as the Backstop Commitment Premium;

| · |  | 3,790,247 shares of New Common Shares to the Senior Noteholders pursuant to a mandatory exchange; and

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| · |  | 374,421 shares of New Common Shares, 1,798,322 Series A Warrants (defined below), 2,247,985 Series B Warrants (defined below) and 2,890,271 Series C Warrants (defined below), to pre-emergence holders of our Existing Equity Interests pursuant to a mandatory exchange.

Warrant Agreement

On the Effective Date, by operation of the Plan and the confirmation order, all warrants of our Predecessor Company were cancelled and we entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which we issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of our Existing Equity Interests pursuant to the Plan.

Each Warrant represents the right to purchase one share of New Common Shares at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On the Effective Date, we issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of New Common Stock, with an initial exercise price of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of New Common Stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of New Common Stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75%, compounding monthly, as provided in the Warrant Agreement.

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of our business.

Registration Rights Agreement

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

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

Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement, as amended on November 21, 2019, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, both of which are discussed below. The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $240.0 million. A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, 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 other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at

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specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process. 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 our assets and the assets of our subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; adverse 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, both commencing with the fiscal quarter ending March 31, 2020.

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

Debtor-in-Possession Financing

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

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019 (Predecessor). The DIP Facility was refinanced with the Senior Credit Agreement on October 8, 2019 (Successor).

We used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with our budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

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

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secured the Predecessor Credit Agreement and (ii) a senior secured perfected security interest on all our unencumbered assets and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

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The DIP Credit Agreement contained certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

Predecessor Senior Revolving Credit Facility

On October 8, 2019 (Successor), borrowings outstanding under the Predecessor Company’s Amended and Restated Senior Secured Revolving Credit Agreement (the Predecessor Credit Agreement) were repaid and refinanced with proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

On May 9, 2019 (Predecessor), we entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Predecessor Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019 (Predecessor), we entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 2019.

2020 Capital Budget

Our 2020 drilling and completion budget, approved by our board in December 2019, contemplated running one operated rig in the Delaware Basin during the year. That budget contemplated spending approximately $123 million to $138 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, to drill seven to ten gross operated wells and to put online 12 to 14 gross operated wells during the year. We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve acreage, and meet our contractual obligations. As a result of recent changes in market conditions and commodity prices, we are considering revisions to our 2020 capital budget which would lower anticipated capital expenditures to approximately $60 million to $76 million and include drilling four to six gross operated wells and putting online six to seven gross operated wells during the year.

We expect to fund our budgeted 2020 capital expenditures with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement. In the event our cash flows are materially less 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.

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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:

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

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

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

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

Oil and Natural Gas Reserves

The proved reserves estimates reported herein for the years ended December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (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. Mike K. Norton. 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. Norton, a Licensed Professional Geoscientist in the State of Texas (No. 441), has been a practicing petroleum geoscience consultant at Netherland, Sewell since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor 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.

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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, 2019 (Successor). Average prices for the 12‑month period were as follows: WTI crude oil spot price of $55.85 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.578 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, 2019 (Successor).

Proved Reserves (MBoe)(1) |  |
Developed |  | 37,935
Undeveloped |  | 24,118
Total |  | 62,053

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

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2019 (Successor) and 2018 (Predecessor). Shut‑in wells currently not capable of production are excluded from the well information below.

|  | Years Ended December 31,
|  | 2019 |  | 2018
|  | Gross |  | Net |  | Gross |  | Net
Oil |  | 122 |  | 94.1 |  | 109 |  | 87.1
Natural Gas |  | 11 |  | 7.7 |  | 13 |  | 9.5
Total |  | 133 |  | 101.8 |  | 122 |  | 96.6

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Oil and Natural Gas Production

During 2017 (Predecessor), we divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas, which represented substantially all of our proved reserves and production at the time, and we acquired certain properties in the Delaware Basin. As a consequence, our estimated proved reserves, oil and natural gas production and anticipated capital expenditures are currently focused entirely in this core area.

Core Resource Play—Delaware Basin

We have working interests in approximately 52,368 net acres in the Delaware Basin as of December 31, 2019 (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, 2019 (Successor), we had approximately 120 operated wells producing in this area in addition to minor working interests in 19 non-operated wells. Our average daily net production from this area for the year ended December 31, 2019 (for the combined Successor and Predecessor periods) was approximately 17,950 Boe/d. As of December 31, 2019 (Successor), estimated proved reserves for the Delaware Basin were approximately 62.0 MMBoe, of which approximately 61% were classified as proved developed and approximately 39% 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 75‑85% of our anticipated oil and natural gas production for the next 24 to 36 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. 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.

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, 2019 (Successor), we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. 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.

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Oil and Natural Gas Operations

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

|  | Years Ended December 31,
|  | 2019 |  | 2018 |  | 2017
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
Exploratory Wells: |  |  |  |  |  |  |  |  |  |  |  |
Productive (1) |  | — |  | — |  | — |  | — |  | — |  | —
Dry |  | — |  | — |  | — |  | — |  | — |  | —
Total Exploratory |  | — |  | — |  | — |  | — |  | — |  | —
Extension Wells: |  |  |  |  |  |  |  |  |  |  |  |
Productive (1) |  | 11 |  | 9.9 |  | 15 |  | 12.5 |  | 84 |  | 13.0
Dry |  | — |  | — |  | — |  | — |  | — |  | —
Total Extension |  | 11 |  | 9.9 |  | 15 |  | 12.5 |  | 84 |  | 13.0
Development Wells: |  |  |  |  |  |  |  |  |  |  |  |
Productive (1) |  | 7 |  | 6.1 |  | 15 |  | 15.0 |  | 40 |  | 20.7
Dry |  | — |  | — |  | — |  | — |  | — |  | —
Total Development |  | 7 |  | 6.1 |  | 15 |  | 15.0 |  | 40 |  | 20.7
Total Wells: |  |  |  |  |  |  |  |  |  |  |  |
Productive (1) |  | 18 |  | 16.0 |  | 30 |  | 27.5 |  | 124 |  | 33.7
Dry |  | — |  | — |  | — |  | — |  | — |  | —
Total |  | 18 |  | 16.0 |  | 30 |  | 27.5 |  | 124 |  | 33.7

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

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, 2019 (Successor):

|  | Developed Acreage |  | Undeveloped Acreage |  | Total Acreage
State |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
North Dakota |  | 3,510 |  | 694 |  | 33,981 |  | 13,945 |  | 37,491 |  | 14,639
Oklahoma |  | — |  | — |  | 387 |  | 137 |  | 387 |  | 137
Texas |  | 35,087 |  | 32,306 |  | 25,187 |  | 20,062 |  | 60,274 |  | 52,368
Total Acreage |  | 38,597 |  | 33,000 |  | 59,555 |  | 34,144 |  | 98,152 |  | 67,144

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The table below reflects the percentage of our total net undeveloped acreage as of December 31, 2019 (Successor) that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included or do not pay (to the extent we have the contractual right to pay) delay rentals or obtain other extensions to maintain the lease.

Year |  | Percentage Expiration
2020 |  | 12 | %
2021 |  | 9 | %
2022 |  | 31 | %
2023 & beyond |  | 48 | %
|  | 100 | %

For our proved undeveloped locations that are not scheduled to be drilled until after lease expiration, we continually review our near‑term lease expirations to determine which lease extensions and renewals to actively pursue, and modify our drilling schedules in order to preserve the leases. We have no current plans to drill on acreage in areas outside of our core area of operations.

At December 31, 2019 (Successor), we had estimated proved reserves of approximately 62.1 MMBoe comprised of 39.2 MMBbls of crude oil, 10.8 MMBbls of natural gas liquids, and 72.3 Bcf of natural gas. The following table sets forth, at December 31, 2019 (Successor), these reserves:

|  | Proved |  | Proved |  | Total
|  | Developed |  | Undeveloped |  | Proved
Oil (MBbls) |  | 22,821 |  | 16,413 |  | 39,234
Natural Gas Liquids (MBbls) |  | 7,021 |  | 3,754 |  | 10,775
Natural Gas (MMcf) |  | 48,558 |  | 23,703 |  | 72,261
Equivalent (MBoe)(1) |  | 37,935 |  | 24,118 |  | 62,053

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

At December 31, 2019 (Successor), total estimated proved reserves were approximately 62.1 MMBoe, a 23.1 MMBoe net decrease from the previous year’s estimate of 85.2 MMBoe. The net decrease in total proved reserves was the result of negative revisions of 29.7 MMBoe and production of 6.6 MMBoe, partially offset by additions and extensions of 13.2 MMBoe.

At December 31, 2019 (Successor), our estimated proved undeveloped (PUD) reserves were approximately 24.1 MMBoe, a 21.2 MMBoe net decrease from the previous year’s estimate of 45.3 MMBoe. The net decrease in total PUD reserves was the result of negative revisions of 21.4 MMBoe and development of 10.2 MMBoe, partially offset by additions and extensions of 10.4 MMBoe.

As of December 31, 2019 (Successor), all of our PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2019, approximately $76.1 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

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proved reserves. Out of total proved undeveloped reserves of 24.1 MMBoe at December 31, 2019 (Successor), 4.9 MMBoe were associated with five 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, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor) are summarized as follows (in thousands):

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018 |  | December 31, 2017
Oil and natural gas properties (full cost method): |  |  |  |  |  |  |  |  |  |
Evaluated |  | $ | 420,609 |  |  | $ | 1,470,509 |  | $ | 877,316
Unevaluated |  |  | 105,009 |  |  |  | 971,918 |  |  | 765,786
Gross oil and natural gas properties |  |  | 525,618 |  |  |  | 2,442,427 |  |  | 1,643,102
Less - accumulated depletion |  |  | (19,474) |  |  |  | (639,951) |  |  | (570,155)
Net oil and natural gas properties |  | $ | 506,144 |  |  | $ | 1,802,476 |  | $ | 1,072,947

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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. In addition, this table summarizes our production for each field that contains 15% or more of our total proved reserves:

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Production: |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil - MBbl |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware |  |  | 1,050 |  |  |  | 2,718 |  |  | 3,544 |  |  | 919
Bakken / Three Forks |  |  | 6 |  |  |  | 5 |  |  | 14 |  |  | 6,235
Other |  |  | 1 |  |  |  | — |  |  | — |  |  | 357
Total |  |  | 1,057 |  |  |  | 2,723 |  |  | 3,558 |  |  | 7,511
Natural gas - MMcf |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware |  |  | 2,754 |  |  |  | 6,378 |  |  | 4,607 |  |  | 1,230
Bakken / Three Forks |  |  | 1 |  |  |  | — |  |  | — |  |  | 4,584
Other |  |  | — |  |  |  | 3 |  |  | — |  |  | 1,625
Total |  |  | 2,755 |  |  |  | 6,381 |  |  | 4,607 |  |  | 7,439
Natural gas liquids - MBbl |  |  |  |  |  |  |  |  |  |  |  |  |
Delaware |  |  | 351 |  |  |  | 911 |  |  | 749 |  |  | 218
Bakken / Three Forks |  |  | — |  |  |  | — |  |  | — |  |  | 924
Other |  |  | — |  |  |  | — |  |  | — |  |  | 107
Total |  |  | 351 |  |  |  | 911 |  |  | 749 |  |  | 1,249
Production: |  |  |  |  |  |  |  |  |  |  |  |  |
Total MBoe (1) |  |  | 1,867 |  |  |  | 4,698 |  |  | 5,075 |  |  | 10,000
Average daily production - Boe (1) |  |  | 20,293 |  |  |  | 17,209 |  |  | 13,904 |  |  | 27,397
Average price per unit (excluding impact of settled derivatives): |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil price - Bbl |  | $ | 55.18 |  |  | $ | 53.26 |  | $ | 56.10 |  | $ | 45.36
Natural gas price - Mcf |  |  | 0.62 |  |  |  | 0.02 |  |  | 1.47 |  |  | 2.18
Natural gas liquids price - Bbl |  |  | 14.45 |  |  |  | 14.52 |  |  | 25.55 |  |  | 15.19
Barrel of oil equivalent price - Boe (1) |  |  | 34.88 |  |  |  | 33.71 |  |  | 44.44 |  |  | 37.58
Average price per unit (including impact of settled derivatives)(2): |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil price - Bbl |  | $ | 54.15 |  |  | $ | 52.33 |  | $ | 56.82 |  | $ | 47.62
Natural gas price - Mcf |  |  | 0.81 |  |  |  | 0.96 |  |  | 1.90 |  |  | 2.29
Natural gas liquids price - Bbl |  |  | 21.76 |  |  |  | 23.90 |  |  | 30.68 |  |  | 15.19
Barrel of oil equivalent price - Boe (1) |  |  | 35.94 |  |  |  | 36.26 |  |  | 46.09 |  |  | 39.36
Average cost per Boe: |  |  |  |  |  |  |  |  |  |  |  |  |
Production: |  |  |  |  |  |  |  |  |  |  |  |  |
Lease operating |  | $ | 6.86 |  |  | $ | 8.43 |  | $ | 4.94 |  | $ | 6.17
Workover and other |  |  | 0.89 |  |  |  | 1.19 |  |  | 1.69 |  |  | 2.17
Taxes other than income |  |  | 2.00 |  |  |  | 1.96 |  |  | 2.52 |  |  | 3.08
Gathering and other |  |  | 5.79 |  |  |  | 7.67 |  |  | 11.84 |  |  | 4.08

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

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| (2) |  | Cash paid on, or cash received from, settled derivative contracts are reflected as “Net gain (loss) on derivative contracts” in the consolidated statements of operations, consistent with our decision not to elect hedge accounting.

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 and transporters of 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. 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, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 77% of our total sales for the year. In 2017 (Predecessor), two individual purchasers of our production, Crestwood Midstream Partners and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% 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.

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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.

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.

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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 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 that have been 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 lift the existing exemption for oil and gas wastes and reclassify them 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 some wastes generated in connection with our exploration and production activities may be regulated as solid waste under RCRA, as hazardous waste under existing RCRA regulations or as hazardous substances under CERCLA. From time to time, releases of materials or wastes 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 or wastes.

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 regulation, which may increase in 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.

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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.

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. Compliance with these regulations has imposed additional requirements and costs on our operations. The Trump Administration may rescind some of the 2012 and 2016 requirements, but supporters of the existing regulations likely would seek judicial review of any such decision.

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 will take place over several years; however, the new standard could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely 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.

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At the federal level, the EPA has 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 has 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. 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 has been trying to roll back many of the Obama‑era climate change policies and rules; however, the long‑term direction of federal climate regulation is uncertain.

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.

Employees and Principal Office

As of December 31, 2019 (Successor), we had 69 full‑time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that we have good relations with our employees.

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As of December 31, 2019 (Successor), we leased corporate office space in Houston, Texas at 1000 Louisiana Street, where our principal offices are located.

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, 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

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:

| · |  | domestic and foreign supplies of oil and natural gas;

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

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

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

| · |  | labor unrest in oil and natural gas producing regions;

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

| · |  | the price and availability of alternative fuels and energy sources;

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

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

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

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

Our business requires substantial capital expenditures primarily to fund our drilling program. We may also continue to selectively increase our core acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. In addition, 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, 2019 (Successor), our Senior Credit Agreement had a borrowing base of $240.0 million. As of December 31, 2019 (Successor), we had $144.0 million of indebtedness outstanding, approximately $2.3 million of letters of credit outstanding and approximately $93.7 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 contained in the Predecessor Credit Agreement, 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 the Senior Credit Agreement may limit our ability to borrow, result in an event of default and cause amounts outstanding under the Senior Credit Agreement to become immediately due and payable.

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.

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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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.

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. Actual results will likely vary significantly from those contemplated by the projections. 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.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Under the Plan, the composition of our Board of Directors (the Board) changed significantly from an eight member Board with three classes with terms of three years to, upon emergence, a seven member Board, structured into two classes with the first class serving until the 2020 Annual Meeting and the second class serving until the 2021 Annual Meeting. Commencing with the 2021 Annual Meeting, each nominee for director shall stand for election to a one-year term expiring at the next annual meeting of stockholders. None of our current directors served on our Board pre-emergence from bankruptcy. Our new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

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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 40.5%, 24.6% and 16.3%, respectively, of our post-reorganization common stock as of March 20, 2020 (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 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 20, 2020 (Successor), we had outstanding approximately 16.2 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 20, 2020, 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.

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.

Borrowings under our Senior Credit Agreement are limited by our borrowing base, which is subject to periodic redetermination.

The borrowing base under our Senior Credit Agreement is currently $240 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

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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 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. To facilitate syndication of our Senior Credit Agreement with additional lenders, we previously agreed to reduce the borrowing base from $275 million to the current $240 million and to reduce the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) from 4.00 to 1.00 to 3.50 to 1.00, and to make certain other changes. We have also agreed that to the extent necessary to facilitate syndication of the Senior Credit Agreement, Bank of Montreal may increase the applicable interest rates under our Senior Credit Agreement by not more than 50 basis points per annum. If Bank of Montreal is unsuccessful in syndicating our Senior Credit Agreement, we may find it necessary to agree to further changes to the terms of such facility, including a further reduction to the borrowing base, tightening of covenants or increase in applicable interest rates.

Whether or not Bank of Montreal is successful in syndicating our Senior Credit Agreement, 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 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 the 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.

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:

| · |  | unexpected drilling conditions;

| · |  | pressure or irregularities in formations;

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

| · |  | adverse weather conditions; and

| · |  | compliance with governmental requirements.

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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.

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 $144.0 million principal amount of debt as of December 31, 2019 (Successor). As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, 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, 2019 (Successor), we had approximately $93.7 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, 2019 (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 twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2019 (Successor). Average prices for oil and natural gas for the 12-month period were as follows: WTI crude oil spot price of $55.85 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.578 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, 2019 (Successor), approximately 39% 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, 2019 (Successor) assume that we will make future capital expenditures of approximately $261.7 million in the aggregate primarily from 2020 through 2024,

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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 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 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 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, 2019 (Successor), we owned leasehold interests in approximately 52,400 net acres in the Delaware Basin in West Texas of which approximately 20,100 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.

We depend on the continued presence of key personnel for critical management decisions.

Retaining and understanding historical knowledge from our key personnel is critical to allowing our new management team to more effectively progress our business plan. As part of the restructuring, there were a number of positions that were consolidated and/or replaced. While it is important to have the new team focused on the future, retaining and understanding the decisions that were made in the past allows for a more seamless transition into the future. Anytime personnel are replaced, there is a risk that there may be a loss of service, albeit temporary, that could result in an adverse effect on the business.

Our oil and natural gas activities are subject to various risks which 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:

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

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

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

| · |  | well-on-well interference that may reduce recoveries;

| · |  | unavailability of materials and equipment;

| · |  | engineering and construction delays;

| · |  | unanticipated transportation costs and delays;

| · |  | unfavorable weather conditions;

| · |  | hazards resulting from unusual or unexpected geological or environmental conditions;

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

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

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

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, whether as a result of uncertainty associated with our restructuring in bankruptcy or otherwise, 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.

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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. Recently, for instance, the President exercised his authority to impose significant tariffs on imports of steel and aluminum from a number of countries. Steel is extensively used by us and those in oil and gas industry generally, including for such items as tubulars, flanges, fittings and tanks, among many other items. As a result of the imposition of such tariffs, we will be paying significantly more for most or all of these items in the near term. 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.

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:

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

| · |  | make loans to others;

| · |  | make investments;

| · |  | incur additional indebtedness;

| · |  | create certain liens;

| · |  | sell assets;

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

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

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| · |  | engage in transactions with affiliates;

| · |  | enter into hedging contracts;

| · |  | create unrestricted subsidiaries; and

| · |  | enter into sale and leaseback transactions.

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

Our business is highly competitive.

The oil and natural gas industry is highly competitive, including identification of attractive oil and natural gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large oil and natural gas companies and other independent operators with greater financial resources, larger numbers of personnel and facilities, and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.

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:

| · |  | water discharge and disposal permits for drilling operations;

| · |  | drilling bonds;

| · |  | drilling permits;

| · |  | reports concerning operations;

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

| · |  | spacing of wells;

| · |  | rights‑of‑way and easements;

| · |  | unitization and pooling of properties;

| · |  | pipeline construction;

| · |  | gathering, transportation and marketing of oil and natural gas;

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| · |  | taxation; and

| · |  | waste transport and disposal permits and requirements.

Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase our costs of doing business. 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, 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 will take place over several years; however, the new standard eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

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

The results of our drilling in shale formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history; consequently our predictions of drilling results in these areas are more uncertain. In addition, the use of horizontal drilling and completion techniques used in shale formations involve certain risks and complexities that do not exist in conventional wells. 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.

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

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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, 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 begun 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 has been trying to roll back many of the Obama‑era climate change policies and rules, but those efforts have resulted in court challenges. At this point, the long‑term direction of federal climate regulation is uncertain.

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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.

The direction of future U.S. climate change regulation is difficult to predict given the current uncertainties surrounding the policies of the Trump Administration. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and gas industry. Even in the absence of federal efforts in this area, states may continue pursuing climate regulations. 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 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.

The ongoing implementation of federal legislation enacted in 2010 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.

We have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, then President Obama signed into law the Dodd‑Frank Wall Street Reform and Consumer Protection Act, or the Dodd‑Frank Act, which requires the SEC and the Commodity Futures Trading Commission (or CFTC), along with other federal agencies, to promulgate regulations implementing the new legislation.

The CFTC has finalized many regulations implementing the Dodd‑Frank Act’s provisions regarding trade reporting, margin, clearing, and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re‑proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible under margin rules that are being phased in between 2016 and 2020, some registered swap dealers may require us to post margin in connection with certain swaps not subject to central clearing.

The Dodd‑Frank Act and any additional implementing 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. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd‑Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments

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related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

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:

| · |  | personal injury;

| · |  | bodily injury;

| · |  | third party property damage;

| · |  | medical expenses;

| · |  | legal defense costs;

| · |  | pollution in some cases;

| · |  | well blowouts in some cases; and

| · |  | workers compensation.

As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our financial position, results of operations and cash flows. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover claims made against us in the future.

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.

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).

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An ownership change was experienced in December 2018 due to the aggregate stock ownership of certain stockholders increasing by more than 50 percentage points over their lowest percentage ownership during the testing period (see discussion above).

We experienced an ownership change in October 2019 as a result of the consummation of our plan of reorganization under chapter 11 of the U.S. Bankruptcy Code 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.

As of December 31, 2019 (Successor), our net book value of oil and natural gas properties did not exceed our ceiling amount using the WTI unweighted 12-month average spot price $55.85 per Bbl for oil and natural gas liquids and the Henry Hub unweighted 12-month average spot price of $2.578 per MMBtu for natural gas. As ceiling test 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 $105.0 million at December 31, 2019 (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, 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

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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:

| · |  | our production is less than expected;

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

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

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.

We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.

We have completed in the past and may complete in the future significant acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy, which may include the acquisition of asset packages of producing properties, undeveloped acreage or existing companies or businesses operating in our industry. The successful acquisition of assets in our industry requires an assessment of several factors, including:

| · |  | recoverable reserves;

| · |  | future oil, natural gas and natural gas liquids prices and their appropriate differentials;

| · |  | development and operating costs; and

| · |  | potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not

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reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well or well site, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are generally not able to obtain contractual indemnification for environmental liabilities and normally acquire properties on an “as is” basis.

Significant acquisitions of existing companies or businesses and other strategic transactions may involve additional risks, including:

| · |  | diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

| · |  | the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with our own while carrying on our ongoing business;

| · |  | difficulty associated with coordinating geographically separate organizations;

| · |  | the challenge of integrating environmental compliance systems to meet requirements of rapidly changing regulations;

| · |  | the challenge of attracting and retaining personnel associated with acquired operations; and

| · |  | failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within our expected time frame.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could be materially and adversely affected.

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.

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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 $100,000 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 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. Effective February 20, 2020, we commenced trading on the NYSE American exchange under the symbol “BATL.”

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.

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

The following table sets forth certain information with respect to the surrender of our common stock by employees in exchange for the payment of certain tax withholding obligations during the three months ended December 31, 2019 (Successor).

|  | Total Number of Shares Purchased(1) |  | Average Price Paid Per Share |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |  | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 2019 |  | 53,663 |  | $ | 0.08 |  | — |  | —
November 2019 |  | — |  |  | — |  | — |  | —
December 2019 |  | — |  |  | — |  | — |  | —

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

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

Statements in this discussion may be forward‑looking. These forward‑looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

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 (the Williston Divestiture) and in the El Halcón area of East Texas (the El Halcón Divestiture). 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, 2019 (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 the West Texas Intermediate (WTI) crude oil spot price of $55.85 per Bbl and Henry Hub natural gas spot price of $2.578 per MMBtu, were approximately 62.1 MMBoe, consisting of 39.2 MMBbls of oil, 10.8 MMBbls of natural gas liquids, and 72.3 Bcf of natural gas. Approximately 61% of our proved reserves were classified as proved developed as of December 31, 2019 (Successor). We maintain operational control of approximately 99% of our proved reserves. Substantially all of our proved reserves and production at December 31, 2019 (Successor) are associated with our Delaware Basin properties.

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, compared to total operating revenues for 2018 (Predecessor) of $226.6 million. 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, compared to average daily production of 13,904 Boe/d during 2018 (Predecessor). Our average daily oil and natural gas production increased year over year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

In 2019 (for the combined Successor and Predecessor periods), we spent approximately $187.8 million on capital expenditures for drilling and completions. In 2019 (for the combined Successor and Predecessor periods), we ran an average of one to two operated rigs in the Delaware Basin and we drilled and cased 14 gross (12.5 net) operated wells, completed 17 gross (15.9 net) operated wells, and put online 17 gross (15.9 net) operated wells.

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Our 2020 drilling and completion budget, approved by our board in December 2019, contemplated running one operated rig in the Delaware Basin during the year. That budget contemplated spending approximately $123 million to $138 million in capital expenditures, including drilling, completion, support infrastructure and other costs, to drill seven to ten gross operated wells and to put online 12 to 14 gross operated wells during the year. We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve acreage, and meet our contractual obligations. As a result of recent changes in market conditions and commodity prices, we are considering revisions to our 2020 capital budget which would lower anticipated capital expenditures to approximately $60 million to $76 million and include drilling four to six gross operated wells and putting online six to seven gross operated wells during the year.

We expect to fund our budgeted 2020 capital expenditures with cash and cash equivalents on hand, cash flows from operations and borrowings under our Senior Credit Agreement. In the event our cash flows are materially less 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, 2020 of the WTI crude oil spot price of $55.96 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, 2020 of the Henry Hub natural gas price of $2.298 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling amount related to the net book value of our oil and natural gas properties would not have generated a full cost ceiling impairment, holding all other inputs and factors constant. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Recent Developments

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.”

Reorganization

On August 2, 2019, we entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of our 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, we filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to effect a prepackaged plan of reorganization (the Plan) as contemplated in the Restructuring Support Agreement. Our chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019 (the Effective Date), we emerged from chapter 11 bankruptcy.

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

| · |  | borrowings outstanding under the Predecessor Credit Agreement, plus unpaid interest and fees, were repaid in full, in cash, including by a refinancing (see below for further details regarding the credit agreement);

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

| · |  | our general unsecured claims were unimpaired and paid in full in the ordinary course; and

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

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

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

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

Fresh-start Accounting

Upon emergence from chapter 11 bankruptcy, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification (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 the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

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

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated financial statements subsequent to October 1, 2019 are not comparable to our consolidated financial statements prior to October 1, 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. 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, and as such, “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.

Common Stock

On the Effective Date, pursuant to the terms of the Plan, all shares of our Predecessor Company were cancelled and we filed an amended and restated certificate of incorporation with the Delaware Secretary of State and adopted amended and restated bylaws. Pursuant to the amended and restated certificate of incorporation, the number of authorized shares of common stock which we have the authority to issue was reduced from 1,001,000,000 to 101,000,000. Of the 101,000,000 authorized shares, 100,000,000 are common stock, par value $0.0001 per share and 1,000,000 are preferred stock, par value $0.0001 per share.

On the Effective Date, pursuant to the terms of the Plan and the confirmation order, we issued:

| · |  | 421,827 shares of New Common Shares pursuant to the Existing Equity Interests Rights Offering; 8,059,111 shares of New Common Shares pursuant to the Senior Noteholder Rights Offering; and 3,558,334 shares of New Common Shares in connection with the backstop commitment, which includes 657,590 shares of New Common Shares issued as the Backstop Commitment Premium;

| · |  | 3,790,247 shares of New Common Shares to the Senior Noteholders pursuant to a mandatory exchange; and

| · |  | 374,421 shares of New Common Shares, 1,798,322 Series A Warrants (defined below), 2,247,985 Series B Warrants (defined below) and 2,890,271 Series C Warrants (defined below), to pre-emergence holders of our Existing Equity Interests pursuant to a mandatory exchange.

Warrant Agreement

On the Effective Date, by operation of the Plan and the confirmation order, all warrants of our Predecessor Company were cancelled and we entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which we issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of our Existing Equity Interests pursuant to the Plan.

Each Warrant represents the right to purchase one share of New Common Shares at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On the Effective Date, we issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of New Common Stock, with an initial exercise price

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of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of New Common Stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of New Common Stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75%, compounding monthly, as provided in the Warrant Agreement.

The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of our business.

Registration Rights Agreement

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

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

Successor Senior Revolving Credit Facility

On the Effective Date, we entered into a senior secured revolving credit agreement, as amended on November 21, 2019, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, discussed below. The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $240.0 million. A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, 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 the 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 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process. 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 our assets and the assets of our subsidiaries.

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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 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, both commencing with the fiscal quarter ending March 31, 2020.

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

Debtor-in-Possession Financing

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

Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019 (Predecessor). The DIP Facility was refinanced with the Senior Credit Agreement on October 8, 2019 (Successor).

We used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with our budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

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

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secured the Predecessor Credit Agreement and (ii) a senior secured perfected security interest on all our unencumbered assets and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

The DIP Credit Agreement contained certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

Predecessor Senior Revolving Credit Facility

On October 8, 2019 (Successor), borrowings outstanding under the Predecessor Company’s Amended and Restated Senior Secured Revolving Credit Agreement (Predecessor Credit Agreement) were repaid and refinanced with proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

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On May 9, 2019 (Predecessor), we entered into the Eighth Amendment, Consent and Waiver to Amended and Restated Senior Secured Credit Agreement (the Eighth Amendment) which, among other things, (i) temporarily waived any default or event of default directly resulting from the potential Leverage Ratio Default (as defined in the Eighth Amendment) for the fiscal quarter ended March 31, 2019, (ii) increased interest margins to 1.75% to 2.75% for ABR-based loans and 2.75% to 3.75% for Eurodollar-based loans, (iii) reduced our Consolidated Cash Balance (as defined in the Eighth Amendment) to $5.0 million, and (iv) provided for periodic reporting of projected cash flows and accounts payable agings to the lenders. Under the Eighth Amendment, the waiver would have terminated and an Event of Default (as defined in the Predecessor Credit Agreement) would have occurred on August 1, 2019. On July 31, 2019 (Predecessor), we entered into the Waiver to Amended and Restated Senior Secured Credit Agreement, pursuant to which the termination date for the waiver granted by the Eighth Amendment was extended to August 8, 2019.

Capital Resources and Liquidity

We expect to spend approximately $60 million to $76 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs, during 2020. 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. On the Effective Date, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement. The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility, with a current borrowing base of $240.0 million. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The effect of these and other factors may result in an increase or a decrease in the amount of our borrowing base. A reduction in our borrowing base would reduce our ability to borrow under the Senior Credit Agreement and could require us to repay borrowings, if any, in excess of the borrowing base and may negatively impact our liquidity and our ability to fund our operations.

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, both commencing with the fiscal quarter ending March 31, 2020. As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement. At December 31, 2019 (Successor), we had $144 million of indebtedness outstanding, $2.3 million letters of credit outstanding and approximately $93.7 million of borrowing capacity available under our Senior Credit Agreement.

We have in the past obtained amendments to the covenants under our Predecessor Credit Agreements under circumstances where we anticipated that it might be challenging for us to comply with our financial covenants for a particular period of time. As part of our plan to manage liquidity risks, we scaled back our capital expenditures budget, focused our drilling program on our highest return projects, continued to explore opportunities to divest non-core properties, entered into a Restructuring Support Agreement to restructure our indebtedness and, on August 7, 2019, filed a voluntary petition for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas to pursue a prepackaged plan of reorganization. On September 24, 2019, the Bankruptcy Court entered an order confirming our plan of reorganization and on October 8, 2019, we emerged from chapter 11 bankruptcy. 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 since acquiring the assets required significant capital expenditure outlays to replenish production and related EBITDA. 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 challenges that impacted our ability to comply, including, elevated levels of hydrogen sulfide in the natural gas produced from our Monument Draw wells,

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limited and expensive treatment and transportation options. Severance payments to executives in 2019 also impacted our ability to comply with our financial covenants.

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 cause our EBITDA to change significantly and 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. 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.

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 therefore continuously monitor our liquidity and evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources, acquisition opportunities and drilling successes.

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.

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 36 months. This variation in hedged volumes may result in our liquidity being more susceptible to commodity price declines. As of October 8, 2019, the Senior Credit Agreement contained minimum hedging requirements. Specifically, for the first twelve months and for months 13 to 24 following October 8, 2019, that 75% and 50%, respectively, of anticipated production from proved developed producing reserves be covered by hedges. While production volumes naturally decrease over time, we currently have approximately 90%, 84%, and 88% of 2020, 2021, and 2022 anticipated production from proved developed producing reserves hedged at weighted average prices of $56.11, $53.44 and $52.38 per barrel, respectively. 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.

Cash Flow

For the period of October 2, 2019 through December 31, 2019 (Successor), cash generated by operating activities and borrowing under our Senior Credit Agreement were used to fund our drilling and completion program. For the period of January 1, 2019 through October 1, 2019 (Predecessor), cash on hand supplemented with borrowings under our Predecessor Credit Agreement and the DIP Facility 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. 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 emergence from chapter 11 bankruptcy and are not comparable to prior periods.

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

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Cash flows provided by (used in) operating activities |  | $ | 13,654 |  |  | $ | (39,731) |  | $ | 67,155 |  | $ | 114,591
Cash flows provided by (used in) investing activities |  |  | (42,790) |  |  |  | (254,417) |  |  | (706,485) |  |  | 598,592
Cash flows provided by (used in) financing activities |  |  | 10,026 |  |  |  | 276,667 |  |  | 262,125 |  |  | (289,136)
Net increase (decrease) in cash, cash equivalents and restricted cash |  | $ | (19,110) |  |  | $ | (17,481) |  | $ | (377,205) |  | $ | 424,047

Operating Activities. 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 were $67.2 million and $114.6 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively.

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.

The $114.6 million of operating cash flows for the year ended December 31, 2017 (Predecessor) were lower than the prior year primarily due to a decrease in realized settlements on derivatives. Realized settlements on derivative contracts decreased $312.7 million over the prior year period. Our oil and natural gas revenues also decreased approximately $42.2 million over the prior year period due to a decrease in our average daily production. Average realized prices (excluding the effects of hedging arrangements) were $37.58 per Boe, $35.87 per Boe and $28.53 per Boe for the year ended December 31, 2017, for the period September 10, 2016 through December 31, 2016 and the period of January 1, 2016 through September 9, 2016, respectively.

Investing Activities. 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. Net cash flows provided by investing activities for the year ended December 31, 2017 (Predecessor) were approximately $598.6 million.

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

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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.

In 2017 (Predecessor), we incurred cash expenditures of $700.1 million to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets) of which $674.6 million related to the oil and natural gas properties acquired and $25.5 million related to the other operating property and equipment acquired. In addition to the acquisition of the Pecos County Assets, we spent approximately $344.0 million on other acquisitions, primarily in the Delaware Basin to increase our position in the area. We spent $331.3 million on oil and natural gas capital expenditures, of which $309.6 million related to drilling and completion costs. These cash outflows for acquisitions and our drilling and completion activities were more than offset by cash inflows from our non-core asset sales. Approximately $1.39 billion of the proceeds from Williston Divestiture were allocated to the oil and natural gas properties divested and $10.9 million of the proceeds were allocated to the other operating property and equipment divested. Proceeds from the El Halcón Divestiture were $494.3 million, of which $484.1 million related to the oil and natural gas properties divested and $10.2 million related to the other operating property and equipment divested. In November 2017 (Predecessor), proceeds from the sale of our non-operated oil and natural gas properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) totaled approximately $105.2 million.

Financing Activities. 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. Net cash flows used in financing activities for the year ended December 31, 2017 (Predecessor) were $289.1 million.

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 our Senior Noteholders Rights Offering and $5.8 million from our Existing Equity Interest Rights Offering. 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 (the Additional 2025 Notes). 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.

In 2017 (Predecessor), we issued $850.0 million aggregate principal amount of our new 6.75% senior notes due 2025 (the 2025 Notes). Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers’ discounts and commissions and offering expenses. We utilized the majority of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes due 2020 (the 2020 Second Lien Notes). The net cash to make these repurchases and redemptions was approximately $736.8 million and we recognized a loss on the extinguishment of debt, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. During 2017 (Predecessor), we also utilized a portion of the proceeds from the Williston Divestiture to repay borrowings outstanding under our Predecessor Credit Agreement, repurchase approximately $425.0 million principal amount of our 2025 Notes and redeem all of our then outstanding 12.0% senior secured second lien notes due 2022 (the 2022 Second Lien Notes). The net cash used to make the repurchase of the 2025 Notes was approximately $437.8 million and we

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recognized a loss on the extinguishment of debt, representing a $12.8 million loss on the repurchase for the tender premium paid, an $8.3 million loss on the write-off of the discount on the notes, and a $7.8 million loss on the write-off of the debt issuances costs on the notes. The net cash used to make the redemption of the 2022 Second Lien Notes was approximately $137.8 million and we recognized a loss on the extinguishment of debt, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the notes. We also paid a consent fee of approximately $16.9 million to the holders of our 2025 Notes. Additionally, we issued 5,518 shares of preferred stock at $72,500 per share. Gross proceeds from this issuance were approximately $400.1 million.

Successor Senior Revolving Credit Facility

On the Effective Date, we entered into the Senior Credit Agreement with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, discussed above. The Senior Credit Agreement provides for a $750.0 million senior secured reserve-based revolving credit facility with a current borrowing base of $240.0 million. A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and us each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of our oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process. 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, both commencing with the fiscal quarter ending March 31, 2020.

On November 21, 2019 (Successor), we entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00. As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement.

Off-Balance Sheet Arrangements

At December 31, 2019 (Successor), we did not have any material off-balance sheet arrangements.

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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.

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

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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.

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, 2019 (Successor), 2018 (Predecessor) and 2017 (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, 2019 (Successor), a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.49 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.53 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

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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, 2019 (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 $128.9 million and would have generated a full cost ceiling impairment.

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, 2019 (Successor), a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.19 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.20 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 $1.5 million and $186.9 million for the

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period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively, to our valuation allowance as a result of increases to deferred tax assets for deferred deductions, capital losses and oil and gas properties offset by the write-off of deferred tax assets for net operating loss carryforwards and other tax attributes. A valuation allowance of $478.7 million has been applied against our deferred tax assets as of December 31, 2019.

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 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, 2019 (Successor) Compared to Year Ended December 31, 2018 (Predecessor)

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

|  | Successor |  |  | Predecessor |
|  | Period from |  |  | Period from |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |
|  | through |  |  | through |  | Year Ended |
In thousands (except per unit and per Boe amounts) |  | December 31, 2019 |  |  | October 1, 2019 |  | December 31, 2018 |
Net income (loss) |  | $ | (10,460) |  |  | $ | (1,156,053) |  | $ | 45,959 |
Operating revenues: |  |  |  |  |  |  |  |  |  |  |
Oil |  |  | 58,325 |  |  |  | 145,024 |  |  | 199,601 |
Natural gas |  |  | 1,719 |  |  |  | 107 |  |  | 6,791 |
Natural gas liquids |  |  | 5,071 |  |  |  | 13,229 |  |  | 19,137 |
Other |  |  | 467 |  |  |  | 743 |  |  | 1,080 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |
Production: |  |  |  |  |  |  |  |  |  |  |
Lease operating |  |  | 12,804 |  |  |  | 39,617 |  |  | 25,075 |
Workover and other |  |  | 1,655 |  |  |  | 5,580 |  |  | 8,574 |
Taxes other than income |  |  | 3,730 |  |  |  | 9,213 |  |  | 12,787 |
Gathering and other |  |  | 10,812 |  |  |  | 36,057 |  |  | 60,090 |
Restructuring |  |  | 1,175 |  |  |  | 15,148 |  |  | 128 |
General and administrative: |  |  |  |  |  |  |  |  |  |  |
General and administrative |  |  | 5,111 |  |  |  | 44,585 |  |  | 46,790 |
Stock-based compensation |  |  | — |  |  |  | (8,035) |  |  | 15,266 |
Depletion, depreciation and accretion: |  |  |  |  |  |  |  |  |  |  |
Depletion – Full cost |  |  | 19,476 |  |  |  | 84,579 |  |  | 69,796 |
Depreciation – Other |  |  | 376 |  |  |  | 6,026 |  |  | 7,402 |
Accretion expense |  |  | 144 |  |  |  | 307 |  |  | 329 |
Full cost ceiling impairment |  |  | — |  |  |  | 985,190 |  |  | — |
(Gain) loss on sale of oil and natural gas properties |  |  | — |  |  |  | — |  |  | 7,235 |
(Gain) loss on sale of Water Assets |  |  | (506) |  |  |  | 3,618 |  |  | (119,003) |
Other income (expenses): |  |  |  |  |  |  |  |  |  |  |
Net gain (loss) on derivative contracts |  |  | (16,692) |  |  |  | (34,332) |  |  | 92,625 |
Interest expense and other |  |  | (1,275) |  |  |  | (37,606) |  |  | (43,015) |
Reorganization items, net |  |  | (3,298) |  |  |  | (117,124) |  |  | — |
Gain (loss) on extinguishment of debt |  |  | — |  |  |  | — |  |  | — |
Income tax benefit (provision) |  |  | — |  |  |  | 95,791 |  |  | (95,791) |
Production: |  |  |  |  |  |  |  |  |  |  |
Crude oil – MBbls |  |  | 1,057 |  |  |  | 2,723 |  |  | 3,558 |
Natural gas – MMcf |  |  | 2,755 |  |  |  | 6,381 |  |  | 4,607 |
Natural gas liquids – MBbls |  |  | 351 |  |  |  | 911 |  |  | 749 |
Total MBoe(1) |  |  | 1,867 |  |  |  | 4,698 |  |  | 5,075 |
Average daily production – Boe(1) |  |  | 20,293 |  |  |  | 17,209 |  |  | 13,904 |
Average price per unit (2): |  |  |  |  |  |  |  |  |  |  |
Crude oil price - Bbl |  | $ | 55.18 |  |  | $ | 53.26 |  | $ | 56.10 |
Natural gas price - Mcf |  |  | 0.62 |  |  |  | 0.02 |  |  | 1.47 |
Natural gas liquids price - Bbl |  |  | 14.45 |  |  |  | 14.52 |  |  | 25.55 |
Total per Boe(1) |  |  | 34.88 |  |  |  | 33.71 |  |  | 44.44 |
Average cost per Boe: |  |  |  |  |  |  |  |  |  |  |
Production: |  |  |  |  |  |  |  |  |  |  |
Lease operating |  | $ | 6.86 |  |  | $ | 8.43 |  | $ | 4.94 |
Workover and other |  |  | 0.89 |  |  |  | 1.19 |  |  | 1.69 |
Taxes other than income |  |  | 2.00 |  |  |  | 1.96 |  |  | 2.52 |
Gathering and other |  |  | 5.79 |  |  |  | 7.67 |  |  | 11.84 |
Restructuring |  |  | 0.63 |  |  |  | 3.22 |  |  | 0.03 |
General and administrative: |  |  |  |  |  |  |  |  |  |  |
General and administrative |  |  | 2.74 |  |  |  | 9.49 |  |  | 9.22 |
Stock-based compensation |  |  | — |  |  |  | (1.71) |  |  | 3.01 |
Depletion |  |  | 10.43 |  |  |  | 18.00 |  |  | 13.75 |

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

| (2) |  | Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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Oil, natural gas and natural gas liquids revenues were $65.1 million, $158.4 million and $225.5 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. 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, compared to average daily production of 13,904 Boe/d during 2018 (Predecessor). Our average daily oil, natural gas and natural gas liquids production increased year over year due to the acquisition of properties in West Quito Draw and our drilling activities in Monument Draw and West Quito Draw. Average realized prices (excluding the effects of hedging arrangements) were $34.88 per Boe, $33.71 per Boe and $44.44 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Lease operating expenses were $12.8 million, $39.6 million and $25.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. On a per unit basis, lease operating expenses were $6.86 per Boe, $8.43 per Boe and $4.94 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The increase in lease operating expenses from 2018 levels results from higher third party water hauling and disposal costs resulting from our divestiture of the Water Assets and an increase in our inventory of wells due to our drilling and acquisition activities.

Workover and other expenses were $1.7 million, $5.6 million and $8.6 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. On a per unit basis, workover and other expenses were $0.89 per Boe, $1.19 per Boe and $1.69 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The decreased costs in 2019 relate to recent strides in improving well and completion designs and fewer workovers performed in 2019 due to our focus on spending on our most economic projects.

Taxes other than income were $3.7 million, $9.2 million and $12.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. Most production taxes are based on realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease. On a per unit basis, taxes other than income were $2.00 per Boe, $1.96 per Boe and $2.52 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively

Gathering and other expenses were $10.8 million, $36.1 million and $60.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. Gathering and other expenses include gathering fees paid to third parties on our oil and natural gas production, operating expenses of our oil and gas gathering infrastructure, gas treating fees, rig stacking charges and other. Approximately $2.7 million, $9.6 million and $7.3 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively, relate to gathering and marketing fees paid to third parties on our oil and natural gas production. Approximately $8.1 million, $24.8 million and $51.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively, relate to operating expenses on our treating equipment and gathering support facilities and in the 2018 period, on our water recycling and disposal facilities. Included in the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 are $10.9 million and $32.5 million, respectively, of wellhead-level costs to remove hydrogen sulfide from natural gas produced from our Monument Draw properties. In April 2019 (Predecessor), we installed an H2S treating plant that more efficiently removes hydrogen sulfide from our produced natural gas and reduces our reliance on expensive wellhead-level treating. Also included are $0.8 million and $1.9 million of rig stacking charges for

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the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Restructuring expense was approximately $1.2 million, $15.1 million and $0.1 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. During 2019 (for both the Successor and Predecessor periods), senior executives resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally, during the third quarter of 2019 (Predecessor), we made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions.

General and administrative expense was $5.1 million, $44.6 million and $46.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The increase in general and administrative expenses results from prepetition costs incurred associated with our chapter 11 bankruptcy, partially offset by a reduction in our payroll and employee related benefits due to a reduction in our workforce and other administrative cost reductions as part of our continued focus on efficiencies and cost savings. On a per unit basis, general and administrative expenses were $2.74 per Boe, $9.49 per Boe and $9.22 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively.

Stock-based compensation expense was a credit of $8.0 million for the period of January 1, 2019 through October 1, 2019 (Predecessor) and an expense of $15.3 million for the year ended December 31, 2018 (Predecessor). During 2019 (for both the Successor and Predecessor periods), senior executives resigned from their positions. In accordance with the terms of these senior executives’ employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination. For the period of January 1, 2019 through October 1, 2019 (Predecessor), we recognized an incremental reduction to stock-based compensation expense of $9.5 million associated with these modifications. There was no stock-based compensation in the Successor period because all outstanding awards under the Predecessor incentive plan were cancelled or vested on the Effective Date and no new awards were issued in 2019 under the Successor incentive plan.

Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $19.5 million, $84.6 million and $69.8 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. On a per unit basis, depletion expense was $10.43 per Boe, $18.00 per Boe and $13.75 per Boe for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. The lower depletion rate in the Successor period is attributable to the change in our depletable base as a result of the adoption of fresh-start accounting.

Under the full cost method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling”, based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. During 2019, the net book value of our oil and gas properties at March 31, June 30 and September 30 (Predecessor) exceeded the respective ceiling amounts for each period. We recorded a full cost ceiling test impairment charge of $45.6 million for the three months ended September 30, 2019 (Predecessor). The ceiling test impairment at September 30, 2019 (Predecessor) was driven by decreases in the first-day-of-the-month 12-month average price for crude oil used in the ceiling test calculation since June 30, 2019 (Predecessor), when the first-day-of-month 12-month average price for crude oil was $61.45 per barrel. At June 30, 2019 (Predecessor), we recorded a full cost ceiling impairment of $664.4 million. The ceiling test impairment at June 30, 2019 (Predecessor) was primarily driven by our focus on our most economic area, Monument Draw. Accordingly, we transferred approximately $481.7 million of unevaluated property costs to the full cost pool as of June 30, 2019 (Predecessor), the majority of which was

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associated with our Hackberry Draw area. At March 31, 2019 (Predecessor), we recorded a full cost ceiling impairment of $275.2 million. The ceiling test impairment at March 31, 2019 (Predecessor) was driven by a decrease in the first-day-of-the-month average price for crude oil used in the ceiling test calculation and our intent to expend capital only on our most economic areas. As such, we identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool during the three months ended March 31, 2019 (Predecessor). Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and estimated proved reserves. Accordingly, we recognized a reduction to the gain on the sale of the oil and natural gas properties associated with the Williston Divestiture of $7.2 million during the year ended December 31, 2018 (Predecessor), as a result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

On December 20, 2018 (Predecessor), we sold our water infrastructure assets located in the Delaware Basin for a total adjusted purchase price of $210.9 million. We recognized a cumulative $115.9 million gain on the sale which includes the $0.5 million addition and $3.6 million reduction in the period of October 2, 2019 through December 31, 2019 (Successor) and January 1, 2019 through October 1, 2019 (Predecessor), respectively, due to customary closing adjustments.

We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil, natural gas and natural gas liquids production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. At December 31, 2019 (Successor), we had a $5.2 million derivative asset, $5.0 million of which was classified as current, and we had a $12.9 million derivative liability, $8.1 million of which was classified as current. We recorded a net derivative loss of $16.7 million ($18.7 million net unrealized loss and $2.0 million net realized gain on settled and early terminated contracts) and a net derivative loss of $34.3 million ($45.8 million net unrealized loss and $11.5 million net realized gain on settled and early terminated contracts) for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively, compared to a net derivative gain of $92.6 million ($84.3 million net unrealized gain and $8.3 million net realized gain on settled and early terminated contracts) for the year ended December 31, 2018 (Predecessor).

Interest expense and other was $1.3 million, $37.6 million and $43.0 million for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), respectively. Interest expense for the Successor period represents interest associated with borrowings under the Senior Credit Agreement. Interest expense in the Predecessor periods represents interest associated with the Predecessor Credit Agreement, the DIP Facility and the 6.75% senior notes for the respective periods in which borrowings were outstanding under each type of credit facility or senior notes. In addition to interest expense, in the period from January 1, 2019 through October 1, 2019 (Predecessor), we paid fees associated with consents and amendments to our Predecessor Credit Agreement.

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

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

We recorded an income tax benefit of $95.8 million using the discrete effective rate method for the period of January 1, 2019 through October 1, 2019 (Predecessor), resulting from the reduction to the deferred tax liability generated by the impact of the full cost ceiling impairment on oil and natural gas properties and the deferred tax asset created by the tax loss from operations. The 7.7% effective tax rate for the period from January 1, 2019 through October 1, 2019 (Predecessor) differs from the 21% statutory rate because of non-deductible executive compensation, non-deductible realized built in losses, and valuation allowances on deferred tax assets.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, “Summary of Significant Events and Accounting Policies.”

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil, natural gas and natural gas liquids prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include fixed-price swaps, costless collars, basis swaps and WTI NYMEX rolls. The total volumes that we hedge through the use of our derivative instruments varies from period to period, however, generally our objective is to hedge approximately 75% to 85% of our anticipated production for the next 24 to 36 months, when derivative contracts are available at terms (or prices) acceptable to us. Our hedge policies and objectives may change significantly as our operational profile changes. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of December 31, 2019 (Successor), we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement or are uncollateralized trades. The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in in Item 1. Consolidated Financial Statements—Note 2, “Reorganization,” constituted an event of default under our derivatives contracts that gave the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 (Predecessor) and we received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, were secured on a super-priority pari passu basis with our Predecessor Credit Agreement during the bankruptcy process and remained in place following our chapter 11 proceedings. We account for our derivative

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activities under the provisions of ASC 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 10, “Derivative and Hedging Activities,” for more details.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short‑term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 9, “Fair Value Measurements,” for additional information.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and ABR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At December 31, 2019 (Successor), the principal amount of our debt was $144.0 million, all of which bears interest at floating and variable interest rates that, at our option, are tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2019 (Successor), the weighted average interest rate on our variable rate debt was 4.22% per year. If the balance of our variable interest rate at December 31, 2019 (Successor) were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $0.6 million per year.

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ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

|  | Page
Management’s report on internal control over financial reporting |  | 67
Reports of independent registered public accounting firm |  | 68
Consolidated statements of operations |  | 70
Consolidated balance sheets |  | 71
Consolidated statements of stockholders’ equity |  | 72
Consolidated statements of cash flows |  | 73
Notes to the consolidated financial statements |  | 74
Supplemental oil and gas information (unaudited) |  | 120
Selected quarterly financial data (unaudited) |  | 126

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, management concluded that Battalion Oil Corporation’s internal control over financial reporting was effective as of December 31, 2019.

Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019 which is included herein.

/s/ RICHARD H. LITTLE |  | /s/ RAGAN T. ALTIZER
Richard H. Little |  | Ragan T. Altizer
Chief Executive Officer |  | Executive Vice President,
|  | Chief Financial Officer and Treasurer
Houston, Texas |  |
March 25, 2020 |  |

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Battalion Oil Corporation and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 (Successor Company balance sheet) and 2018 (Predecessor Company balance sheet), and the related consolidated statement of operations, stockholders’ equity, and cash flows for the period of October 2, 2019 to December 31, 2019 (Successor Company operations), the period of January 1, 2019 to October 1, 2019, and for the years ended December 31, 2018 and 2017 (Predecessor Company operations) and for our report dated March 25, 2020, expressed an unqualified opinion on those financial statements and includes an explanatory paragraph relating to the Company’s reorganization under the bankruptcy code.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Houston, Texas

March 25, 2020

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Battalion Oil Corporation and subsidiaries (the “Company”) as of December 31, 2019 (Successor Company balance sheet) and 2018 (Predecessor Company balance sheet) and the related consolidated statements of operations, stockholders’ equity, and cash flows for the period of October 2, 2019 to December 31, 2019 (Successor Company operations) and January 1, 2019 to October 1, 2019, and for the years ended December 31, 2018 and 2017 (Predecessor Company operations) and the related notes (collectively referred to as the “financial statements”). In our opinion, the Successor Company’s financial statements present fairly, in all material respects, the financial position of Battalion Oil Corporation and subsidiaries as of December 31, 2019, and the results of its operations and its cash flows for the period of October 2, 2019 to December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor Company financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor Company as of December 31, 2018, and the result of its operations and its cash flows for the period of January 1, 2019 to October 1, 2019 and for the years ended December 31, 2018 and 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 25, 2020 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Fresh-Start Reporting

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

Basis for Opinion

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

/s/ DELOITTE & TOUCHE LLP |
Houston, Texas |
March 25, 2020 |
We have served as the Company’s auditor since 2012. |

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Operating revenues: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, natural gas and natural gas liquids sales: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil |  | $ | 58,325 |  |  | $ | 145,024 |  | $ | 199,601 |  | $ | 340,674
Natural gas |  |  | 1,719 |  |  |  | 107 |  |  | 6,791 |  |  | 16,194
Natural gas liquids |  |  | 5,071 |  |  |  | 13,229 |  |  | 19,137 |  |  | 18,969
Total oil, natural gas and natural gas liquids sales |  |  | 65,115 |  |  |  | 158,360 |  |  | 225,529 |  |  | 375,837
Other |  |  | 467 |  |  |  | 743 |  |  | 1,080 |  |  | 2,128
Total operating revenues |  |  | 65,582 |  |  |  | 159,103 |  |  | 226,609 |  |  | 377,965
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |  |
Production: |  |  |  |  |  |  |  |  |  |  |  |  |
Lease operating |  |  | 12,804 |  |  |  | 39,617 |  |  | 25,075 |  |  | 61,743
Workover and other |  |  | 1,655 |  |  |  | 5,580 |  |  | 8,574 |  |  | 21,739
Taxes other than income |  |  | 3,730 |  |  |  | 9,213 |  |  | 12,787 |  |  | 30,757
Gathering and other |  |  | 10,812 |  |  |  | 36,057 |  |  | 60,090 |  |  | 40,783
Restructuring |  |  | 1,175 |  |  |  | 15,148 |  |  | 128 |  |  | 7,535
General and administrative |  |  | 5,111 |  |  |  | 36,550 |  |  | 62,056 |  |  | 111,351
Depletion, depreciation and accretion |  |  | 19,996 |  |  |  | 90,912 |  |  | 77,527 |  |  | 110,207
Full cost ceiling impairment |  |  | — |  |  |  | 985,190 |  |  | — |  |  | —
(Gain) loss on sale of oil and natural gas properties |  |  | — |  |  |  | — |  |  | 7,235 |  |  | (721,573)
(Gain) loss on sale of Water Assets |  |  | (506) |  |  |  | 3,618 |  |  | (119,003) |  |  | —
Total operating expenses |  |  | 54,777 |  |  |  | 1,221,885 |  |  | 134,469 |  |  | (337,458)
Income (loss) from operations |  |  | 10,805 |  |  |  | (1,062,782) |  |  | 92,140 |  |  | 715,423
Other income (expenses): |  |  |  |  |  |  |  |  |  |  |  |  |
Net gain (loss) on derivative contracts |  |  | (16,692) |  |  |  | (34,332) |  |  | 92,625 |  |  | 1,291
Interest expense and other |  |  | (1,275) |  |  |  | (37,606) |  |  | (43,015) |  |  | (71,097)
Reorganization items, net |  |  | (3,298) |  |  |  | (117,124) |  |  | — |  |  | —
Gain (loss) on extinguishment of debt |  |  | — |  |  |  | — |  |  | — |  |  | (114,931)
Total other income (expenses) |  |  | (21,265) |  |  |  | (189,062) |  |  | 49,610 |  |  | (184,737)
Income (loss) before income taxes |  |  | (10,460) |  |  |  | (1,251,844) |  |  | 141,750 |  |  | 530,686
Income tax benefit (provision) |  |  | — |  |  |  | 95,791 |  |  | (95,791) |  |  | 5,000
Net income (loss) |  |  | (10,460) |  |  |  | (1,156,053) |  |  | 45,959 |  |  | 535,686
Non-cash preferred dividend |  |  | — |  |  |  | — |  |  | — |  |  | (48,007)
Net income (loss) available to common stockholders |  | $ | (10,460) |  |  | $ | (1,156,053) |  | $ | 45,959 |  | $ | 487,679
Net income (loss) per share of common stock: |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (0.65) |  |  | $ | (7.27) |  | $ | 0.29 |  | $ | 3.67
Diluted |  | $ | (0.65) |  |  | $ | (7.27) |  | $ | 0.29 |  | $ | 3.65
Weighted average common shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 16,204 |  |  |  | 158,925 |  |  | 157,011 |  |  | 132,763
Diluted |  |  | 16,204 |  |  |  | 158,925 |  |  | 157,295 |  |  | 133,576

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

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BATTALION OIL CORPORATION
CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 5,701 |  |  | $ | 46,866
Accounts receivable, net |  |  | 48,504 |  |  |  | 35,718
Assets from derivative contracts |  |  | 4,995 |  |  |  | 57,280
Restricted cash |  |  | 4,574 |  |  |  | —
Prepaids and other |  |  | 7,379 |  |  |  | 4,788
Total current assets |  |  | 71,153 |  |  |  | 144,652
Oil and natural gas properties (full cost method): |  |  |  |  |  |  |
Evaluated |  |  | 420,609 |  |  |  | 1,470,509
Unevaluated |  |  | 105,009 |  |  |  | 971,918
Gross oil and natural gas properties |  |  | 525,618 |  |  |  | 2,442,427
Less - accumulated depletion |  |  | (19,474) |  |  |  | (639,951)
Net oil and natural gas properties |  |  | 506,144 |  |  |  | 1,802,476
Other operating property and equipment: |  |  |  |  |  |  |
Other operating property and equipment |  |  | 3,655 |  |  |  | 130,251
Less - accumulated depreciation |  |  | (378) |  |  |  | (8,388)
Net other operating property and equipment |  |  | 3,277 |  |  |  | 121,863
Other noncurrent assets: |  |  |  |  |  |  |
Assets from derivative contracts |  |  | 224 |  |  |  | 12,437
Operating lease right of use assets |  |  | 3,165 |  |  |  | —
Funds in escrow and other |  |  | 703 |  |  |  | 2,181
Total assets |  | $ | 584,666 |  |  | $ | 2,083,609
Current liabilities: |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | $ | 97,333 |  |  | $ | 157,848
Liabilities from derivative contracts |  |  | 8,069 |  |  |  | 3,768
Operating lease liabilities |  |  | 923 |  |  |  | —
Asset retirement obligations |  |  | 109 |  |  |  | 126
Total current liabilities |  |  | 106,434 |  |  |  | 161,742
Long-term debt, net |  |  | 144,000 |  |  |  | 613,105
Other noncurrent liabilities: |  |  |  |  |  |  |
Liabilities from derivative contracts |  |  | 4,854 |  |  |  | 9,139
Asset retirement obligations |  |  | 10,481 |  |  |  | 6,788
Operating lease liabilities |  |  | 2,247 |  |  |  | —
Deferred income taxes |  |  | — |  |  |  | 95,791
Commitments and contingencies (Note 12) |  |  |  |  |  |  |
Stockholders' equity: |  |  |  |  |  |  |
Predecessor Common stock: 1,000,000,000 shares of $0.0001 par value |  |  |  |  |  |  |
authorized;160,612,852 shares issued and outstanding |  |  | — |  |  |  | 16
Predecessor Additional paid-in capital |  |  | — |  |  |  | 1,095,367
Common stock: 100,000,000 shares of $0.0001 par value |  |  |  |  |  |  |
authorized; 16,203,940 shares issued and outstanding |  |  | 2 |  |  |  | —
Successor Additional paid-in capital |  |  | 327,108 |  |  |  | —
Retained earnings (accumulated deficit) |  |  | (10,460) |  |  |  | 101,661
Total stockholders' equity |  |  | 316,650 |  |  |  | 1,197,044
Total liabilities and stockholders' equity |  | $ | 584,666 |  |  | $ | 2,083,609

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

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

|  |  |  |  |  |  |  |  |  |  |  |  |  |  | Retained |  |  |
|  |  |  |  |  |  |  |  |  |  |  | Additional |  | Earnings |  |  |
|  | Preferred Stock |  | Common Stock |  | Paid-In |  | (Accumulated |  | Stockholders'
|  | Shares |  | Amount |  | Shares |  | Amount |  | Capital |  | Deficit) |  | Equity
Balances at December 31, 2016 (Predecessor) |  | — |  | $ | — |  | 92,991 |  | $ | 9 |  | $ | 592,663 |  | $ | (479,984) |  | $ | 112,688
Net income (loss) |  | — |  |  | — |  | — |  |  | — |  |  | — |  |  | 535,686 |  |  | 535,686
Sale of preferred stock |  | 6 |  |  | — |  | — |  |  | — |  |  | 352,048 |  |  | — |  |  | 352,048
Preferred beneficial conversion feature |  | — |  |  | — |  | — |  |  | — |  |  | 48,007 |  |  | — |  |  | 48,007
Conversion of preferred stock |  | (6) |  |  | — |  | 55,180 |  |  | 6 |  |  | (6) |  |  | — |  |  | —
Equity issuance costs |  | — |  |  | — |  | — |  |  | — |  |  | (11,919) |  |  | — |  |  | (11,919)
Long-term incentive plan grants |  | — |  |  | — |  | 2,022 |  |  | — |  |  | — |  |  | — |  |  | —
Long-term incentive plan forfeitures |  | — |  |  | — |  | (498) |  |  | — |  |  | — |  |  | — |  |  | —
Reduction in shares to cover |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
individuals' tax withholding |  | — |  |  | — |  | (316) |  |  | — |  |  | (1,995) |  |  | — |  |  | (1,995)
Stock-based compensation |  | — |  |  | — |  | — |  |  | — |  |  | 37,483 |  |  | — |  |  | 37,483
Balances at December 31, 2017 (Predecessor) |  | — |  |  | — |  | 149,379 |  |  | 15 |  |  | 1,016,281 |  |  | 55,702 |  |  | 1,071,998
Net income (loss) |  | — |  |  | — |  | — |  |  | — |  |  | — |  |  | 45,959 |  |  | 45,959
Common stock issuance |  | — |  |  | — |  | 9,200 |  |  | 1 |  |  | 63,479 |  |  | — |  |  | 63,480
Equity issuance costs |  | — |  |  | — |  | — |  |  | — |  |  | (3,044) |  |  | — |  |  | (3,044)
Stock option exercises |  | — |  |  | — |  | 42 |  |  | — |  |  | 323 |  |  | — |  |  | 323
Long-term incentive plan grants |  | — |  |  | — |  | 2,327 |  |  | — |  |  | — |  |  | — |  |  | —
Long-term incentive plan forfeitures |  | — |  |  | — |  | (262) |  |  | — |  |  | — |  |  | — |  |  | —
Reduction in shares to cover |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
individuals' tax withholding |  | — |  |  | — |  | (73) |  |  | — |  |  | (301) |  |  | — |  |  | (301)
Stock-based compensation |  | — |  |  | — |  | — |  |  | — |  |  | 18,629 |  |  | — |  |  | 18,629
Balances at December 31, 2018 (Predecessor) |  | — |  |  | — |  | 160,613 |  |  | 16 |  |  | 1,095,367 |  |  | 101,661 |  |  | 1,197,044
Net income (loss) |  | — |  |  | — |  | — |  |  | — |  |  | — |  |  | (1,156,053) |  |  | (1,156,053)
Long-term incentive plan grants |  | — |  |  | — |  | 4,164 |  |  | — |  |  | — |  |  | — |  |  | —
Long-term incentive plan forfeitures |  | — |  |  | — |  | (2,101) |  |  | — |  |  | — |  |  | — |  |  | —
Reduction in shares to cover |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
individuals' tax withholding |  | — |  |  | — |  | (1,174) |  |  | — |  |  | (494) |  |  | — |  |  | (494)
Stock-based compensation |  | — |  |  | — |  | — |  |  | — |  |  | (10,020) |  |  | — |  |  | (10,020)
Balances at October 1, 2019 (Predecessor) |  | — |  |  | — |  | 161,502 |  |  | 16 |  |  | 1,084,853 |  |  | (1,054,392) |  |  | 30,477
Cancellation of Predecessor equity |  | — |  | $ | — |  | (161,502) |  | $ | (16) |  | $ | (1,084,853) |  |  | 1,054,392 |  |  | (30,477)
Balances at October 1, 2019 (Predecessor) |  | — |  | $ | — |  | — |  | $ | — |  | $ | — |  |  | — |  |  | —
Issuance of Successor common stock |  | — |  | $ | — |  | 16,204 |  | $ | 2 |  | $ | 322,294 |  | $ | — |  | $ | 322,296
Issuance of Successor warrants |  | — |  |  | — |  | — |  |  | — |  |  | 7,336 |  |  | — |  |  | 7,336
Equity issuance costs |  | — |  |  | — |  | — |  |  | — |  |  | (2,503) |  |  | — |  |  | (2,503)
Balances at October 1, 2019 (Successor) |  | — |  | $ | — |  | 16,204 |  | $ | 2 |  | $ | 327,127 |  | $ | — |  | $ | 327,129
Net income (loss) |  | — |  |  | — |  | — |  |  | — |  |  | — |  |  | (10,460) |  |  | (10,460)
Equity issuance costs |  | — |  |  | — |  | — |  |  | — |  |  | (19) |  |  | — |  |  | (19)
Balances at December 31, 2019 (Successor) |  | — |  | $ | — |  | 16,204 |  | $ | 2 |  | $ | 327,108 |  | $ | (10,460) |  | $ | 316,650

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

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) |  | $ | (10,460) |  |  | $ | (1,156,053) |  | $ | 45,959 |  | $ | 535,686
Adjustments to reconcile net income (loss) to net cash provided by (used |  |  |  |  |  |  |  |  |  |  |  |  |
in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |
Depletion, depreciation and accretion |  |  | 19,996 |  |  |  | 90,912 |  |  | 77,527 |  |  | 110,207
Full cost ceiling impairment |  |  | — |  |  |  | 985,190 |  |  | — |  |  | —
(Gain) loss on sale of oil and natural gas properties |  |  | — |  |  |  | — |  |  | 7,235 |  |  | (721,573)
(Gain) loss on sale of Water Assets |  |  | (506) |  |  |  | 3,618 |  |  | (119,003) |  |  | —
Deferred income tax provision (benefit) |  |  | — |  |  |  | (95,791) |  |  | 95,791 |  |  | —
Stock-based compensation, net |  |  | — |  |  |  | (8,035) |  |  | 15,266 |  |  | 36,757
Unrealized loss (gain) on derivative contracts |  |  | 18,681 |  |  |  | 45,834 |  |  | (84,274) |  |  | 16,468
Amortization and write-off of deferred loan costs |  |  | — |  |  |  | 1,859 |  |  | 1,405 |  |  | 1,795
Amortization of discount and premium |  |  | — |  |  |  | 134 |  |  | 288 |  |  | 2,597
Reorganization items, net |  |  | (3,615) |  |  |  | 108,887 |  |  | — |  |  | (739)
Loss (gain) on extinguishment of debt |  |  | — |  |  |  | — |  |  | — |  |  | 114,931
Other expense (income) |  |  | 253 |  |  |  | 535 |  |  | (1,608) |  |  | (3,331)
Change in assets and liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable |  |  | (10,571) |  |  |  | 3,781 |  |  | 378 |  |  | 103,166
Prepaids and other |  |  | 2,911 |  |  |  | (6,729) |  |  | 5,840 |  |  | (3,688)
Accounts payable and accrued liabilities |  |  | (3,035) |  |  |  | (13,873) |  |  | 22,351 |  |  | (77,685)
Net cash provided by (used in) operating activities |  |  | 13,654 |  |  |  | (39,731) |  |  | 67,155 |  |  | 114,591
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil and natural gas capital expenditures |  |  | (43,230) |  |  |  | (167,235) |  |  | (475,685) |  |  | (331,257)
Proceeds received from sales of oil and natural gas assets |  |  | — |  |  |  | 1,247 |  |  | 3,816 |  |  | 2,003,894
Acquisition of oil and natural gas properties |  |  | — |  |  |  | (2,809) |  |  | (333,857) |  |  | (1,018,546)
Acquisition of other operating property and equipment |  |  | — |  |  |  | — |  |  | — |  |  | (25,538)
Other operating property and equipment capital expenditures |  |  | — |  |  |  | (85,613) |  |  | (116,995) |  |  | (53,214)
Proceeds received from sale of other operating property and equipment |  |  | 6 |  |  |  | — |  |  | 216,083 |  |  | 21,798
Funds held in escrow and other |  |  | 434 |  |  |  | (7) |  |  | 153 |  |  | 1,455
Net cash provided by (used in) investing activities |  |  | (42,790) |  |  |  | (254,417) |  |  | (706,485) |  |  | 598,592
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from borrowings |  |  | 36,000 |  |  |  | 445,234 |  |  | 438,000 |  |  | 1,349,000
Repayments of borrowings |  |  | (22,000) |  |  |  | (315,234) |  |  | (232,000) |  |  | (1,922,826)
Cash payments to Common Holders, Noteholders and Preferred Holders |  |  | — |  |  |  | (4) |  |  | — |  |  | (83,653)
Debt issuance costs |  |  | (1,471) |  |  |  | (8,764) |  |  | (4,334) |  |  | (17,799)
Preferred stock issued |  |  | — |  |  |  | — |  |  | — |  |  | 400,055
Common stock issued |  |  | — |  |  |  | 155,929 |  |  | 63,480 |  |  | —
Equity issuance costs and other |  |  | (2,503) |  |  |  | (494) |  |  | (3,021) |  |  | (13,913)
Net cash provided by (used in) financing activities |  |  | 10,026 |  |  |  | 276,667 |  |  | 262,125 |  |  | (289,136)
Net increase (decrease) in cash, cash equivalents and restricted cash |  |  | (19,110) |  |  |  | (17,481) |  |  | (377,205) |  |  | 424,047
Cash, cash equivalents and restricted cash at beginning of period |  |  | 29,385 |  |  |  | 46,866 |  |  | 424,071 |  |  | 24
Cash, cash equivalents and restricted cash at end of period |  |  | 10,275 |  |  |  | 29,385 |  |  | 46,866 |  |  | 424,071
Supplemental cash flow information: |  |  |  |  |  |  |  |  |  |  |  |  |
Cash paid (received) for interest |  | $ | (197) |  |  | $ | 33,071 |  | $ | 37,526 |  | $ | 90,835
Cash paid (refunded) for income taxes |  |  | — |  |  |  | — |  |  | (5,000) |  |  | 1,250
Cash paid for reorganization items |  |  | 6,913 |  |  |  | 8,237 |  |  | — |  |  | 739
Disclosure of non-cash investing and financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |
Asset retirement obligations |  | $ | 293 |  |  | $ | 2,932 |  | $ | 2,217 |  | $ | (29,313)
Accretion of non-cash preferred dividend |  |  | — |  |  |  | — |  |  | — |  |  | 48,007
Accrued equity issuance costs |  |  | (2,484) |  |  |  | 2,503 |  |  | — |  |  | —
Accrued debt issuance costs |  |  | (1,471) |  |  |  | 1,471 |  |  | (90) |  |  | 90

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

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

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

Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids‑rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority‑owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.

Emergence From Voluntary Reorganization Under Chapter 11

On August 7, 2019 (the Petition Date), the Company and its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Company’s chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective (the Effective Date) and the Company emerged from chapter 11 bankruptcy. See Note 2, “Reorganization,” for further details on the Company’s chapter 11 bankruptcy and the Plan.

Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. The Company elected to apply fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor).

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

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

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Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 6, “Acquisitions and Divestitures,” for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.

Cash, Cash Equivalents and Restricted Cash

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

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Cash and cash equivalents |  | $ | 5,701 |  |  | $ | 46,866
Restricted cash |  |  | 4,574 |  |  |  | —
Total cash, cash equivalents and restricted cash |  | $ | 10,275 |  |  | $ | 46,866

Restricted Cash consists of funds related to payments prescribed under the Plan that are held in an interest-bearing escrow account.

Accounts Receivable and Allowance for Doubtful Accounts

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of December 31, 2019 (Successor) and 2018 (Predecessor), allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as

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incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations.

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

Other Operating Property and Equipment

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

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

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

Concentrations of Credit Risk

The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. 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. For the year ended December 31, 2018 (Predecessor), two individual purchasers of the Company’s production, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 77% of the Company’s total sales for the year. In 2017 (Predecessor), two individual purchasers of the Company’s production, Crestwood Midstream Partners and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% of the Company’s total sales for the year.

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The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

Risk Management Activities

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

Income Taxes

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

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

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

The Company has no liability for unrecognized tax benefits as of December 31, 2019 (Successor) and 2018 (Predecessor). Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor). In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

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

Generally, the Company’s income tax years 2016 through 2019 remain open for federal purposes and are subject to examination by Federal tax authorities. No claims were filed with respect to any historical income tax periods that caused any challenge to the Plan. The Company’s income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions

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where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes.

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

Asset Retirement Obligations

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

Leases

Effective January 1, 2019 (Predecessor), the Company accounts for leases in accordance with ASC 842, Leases (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset.

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

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

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

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

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

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

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

The Company elected not to recognize right of use assets and lease liabilities for all short‑term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short‑term leases as an expense on a straight‑line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.

Restructuring

During 2019 (both in Successor and Predecessor periods), senior executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the third quarter of 2019 (Predecessor), the Company made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. Consequently, for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred approximately $1.2 million and $15.1 million, respectively, in costs which were recorded in “Restructuring” on the consolidated statements of operations.

401(k) Plan

The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $0.2 million and $1.1 million for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. The Company provided matching contributions of $1.5 million and $2.2 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively. The Company matches employee contributions dollar-for-dollar on the first 10% of an employee’s pre‑tax earnings, subject to individual IRS limitations.

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Related Party Transactions

Crude Oil Gathering Agreement

On July 27, 2018 (Predecessor), a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired, acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue $101.6 million and $13.0 million, respectively, from SCM under the crude oil gathering agreement. As of December 31, 2018 (Predecessor), the Company recorded a $10.9 million receivable from SCM for its crude oil sales.

Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which owned in excess of ten percent (10%) of the common stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in SCM but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. As of the Effective Date, SCM is no longer a related party to the Successor Company.

Gas Purchase and Processing Agreement

On November 16, 2017 (Predecessor), a subsidiary of the Company entered into a gas purchase and processing agreement with Salt Creek Midstream, LLC (Salt Creek) pursuant to which the Company agreed to dedicate for a term of 15 years, all production from its acreage in Ward County, Texas (that is not otherwise previously dedicated) and certain sections in Winkler County, Texas to a natural gas gathering pipeline and processing facilities to be constructed by Salt Creek. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue of $6.0 million and $0.4 million, respectively, from Salt Creek under the gas purchase and processing agreement. As of December 31, 2018 (Predecessor), the Company had no receivables outstanding from Salt Creek.

Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which owned in excess of ten percent (10%) of the stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in Salt Creek but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of Salt Creek. As of the Effective Date, Salt Creek is no longer a related party to the Successor Company.

Pipeline Testing Services

In February 2019 (Predecessor), the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's former directors (as of the Effective Date of the Plan) owns a minority interest in Cima and serves as its chief executive officer. For the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred charges of approximately $0.9 million for services provided by Cima. As of the Effective Date, Cima is no longer a related party to the Successor Company.

Charter of Aircraft

In the ordinary course of business, the Company occasionally chartered a private aircraft for business use. The Company’s former Chairman, Chief Executive Officer and President indirectly owns an aircraft that the Company chartered from time to time. During 2018 and a portion of 2017 (Predecessor), fees for the use of the Company’s former Chairman, Chief Executive Officer and President’s aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. In the first quarter of 2019 (Predecessor), the Company terminated all charter arrangements with the Company’s former Chairman, Chief Executive Officer and

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President relating to the use of his aircraft. During the period of January 1, 2019 to October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company paid approximately $0.2 million and $0.9 million, respectively, related to use of the aircraft indirectly owned by the Company’s former Chairman, Chief Executive Officer and President during 2018. As of December 31, 2018 (Predecessor), the Company recorded a $0.2 million payable to the Company’s former Chairman, Chief Executive Officer and President.

Recently Issued Accounting Pronouncements

In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See “Leases” above and Note 4, “Leases,” below for further details.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (ASU 2016-13), which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. ASU 2016-13 will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted. The Company adopted ASU 2016-13 effective January 1, 2020 using the modified retrospective approach as of the adoption date. The adoption will not have a material impact on the Company’s operating results, financial position or disclosures.

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

2. REORGANIZATION

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

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

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

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

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

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

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

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

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

Registration Rights Agreement

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

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

3. FRESH-START ACCOUNTING

Upon the Company’s emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company’s

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

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

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

The Company elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying consolidated statement of operations in “Reorganization items, net” for the period from January 1, 2019 through October 1, 2019 (Predecessor).

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

Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of October 1, 2019 (in thousands):

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

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

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

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Condensed Consolidated Balance Sheet

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

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

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Reorganization adjustments

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

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

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

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

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

| 5) |  | On the Emergence Date, in accordance with the Plan, the Company repaid the principal outstanding on the Predecessor Credit Agreement of $223.2 million and the DIP Facility of $35.0 million using proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement.

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

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

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

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

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

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

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

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

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

Fresh-start accounting adjustments

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

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

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

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

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

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

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

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

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

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Reorganization Items

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

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

4. LEASES

Adoption of Accounting Standards Codification 842, Leases

On January 1, 2019 (Predecessor), the Company adopted ASC 842 using the modified retrospective approach as of the adoption date. Reporting periods beginning after January 1, 2019 are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The table below details the impact of adoption on the Company’s unaudited condensed consolidated balance sheet as of January 1, 2019 (Predecessor) (in thousands):

|  | Predecessor
|  | December 31, 2018 |  | Impact of adoption of ASC 842 |  | January 1, 2019
Other noncurrent assets: |  |  |  |  |  |  |  |  |
Operating lease right of use assets |  | $ | — |  | $ | 5,462 |  | $ | 5,462
Current liabilities: |  |  |  |  |  |  |  |  |
Accounts payable and accrued liabilities |  | $ | 157,848 |  | $ | (85) |  | $ | 157,763
Operating lease liabilities |  |  | — |  |  | 2,103 |  |  | 2,103
Other noncurrent liabilities: |  |  |  |  |  |  |  |  |
Operating lease liabilities |  |  | — |  |  | 3,444 |  |  | 3,444

Practical Expedients

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

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Leases

The Company leases equipment and office space under operating leases. The Company has no leases that meet the criteria for classification as a finance lease. The operating leases have initial lease terms ranging from 2 to 5 years for the period from October 2, 2019 through December 31, 2019 (Successor) and 1 to 4 years for the period from January 1, 2019 through October 1, 2019 (Predecessor). Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company’s leases for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) (in thousands, except years and discount rate):

|  | Successor |  |  | Predecessor |
|  | Period from |  |  | Period from |
|  | October 2, 2019 |  |  | January 1, 2019 |
|  | through |  |  | through |
|  | December 31, 2019 |  |  | October 1, 2019 |
Lease cost |  |  |  |  |  |  |  |
Operating lease costs |  | $ | 260 |  |  | $ | 1,932 |
Short-term lease costs |  |  | 4,408 |  |  |  | 12,262 |
Variable lease costs |  |  | 215 |  |  |  | 1,210 |
Total lease costs |  | $ | 4,883 |  |  | $ | 15,404 |
Other information |  |  |  |  |  |  |  |
Cash paid for amounts included in the measurement of lease liabilities |  |  |  |  |  |  |  |
Operating cash flows from operating leases |  | $ | 254 |  |  | $ | 1,936 |
Right-of-use assets obtained in exchange for new operating lease liabilities |  |  | 3,394 |  |  |  | 5,462 |
Weighted-average remaining lease term - operating leases |  |  | 3.5 | years |  |  | 3.7 | years
Weighted-average discount rate - operating leases |  |  | 3.70 | % |  |  | 4.83 | %

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

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

|  | Successor
|  | December 31, 2019
2020 |  | $ | 1,022
2021 |  |  | 876
2022 |  |  | 574
2023 |  |  | 585
2024 |  |  | 345
Thereafter |  |  | —
Total operating lease payments |  |  | 3,402
Less: discount to present value |  |  | 232
Total operating lease liabilities |  |  | 3,170
Less: current operating lease liabilities |  |  | 923
Noncurrent operating lease liabilities |  | $ | 2,247

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Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2018 (Predecessor), are presented in the table below (in thousands):

|  | Predecessor
|  | December 31, 2018
2019 |  | $ | 3,792
2020 |  |  | 2,350
2021 |  |  | 1,899
2022 |  |  | 968
2023 |  |  | 999
Thereafter |  |  | 599
Total operating lease payments |  | $ | 10,607

5. OPERATING REVENUES

Revenue Recognition

Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $36.4 million and $26.4 million as of December 31, 2019 (Successor) and 2018 (Predecessor), respectively, as “Accounts receivable” on the consolidated balance sheets.

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

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Operating revenues: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, natural gas and natural gas liquids sales: |  |  |  |  |  |  |  |  |  |  |  |  |
Oil |  | $ | 58,325 |  |  | $ | 145,024 |  | $ | 199,601 |  | $ | 340,674
Natural gas |  |  | 1,719 |  |  |  | 107 |  |  | 6,791 |  |  | 16,194
Natural gas liquids |  |  | 5,071 |  |  |  | 13,229 |  |  | 19,137 |  |  | 18,969
Total oil, natural gas and natural gas liquids sales |  |  | 65,115 |  |  |  | 158,360 |  |  | 225,529 |  |  | 375,837
Other |  |  | 467 |  |  |  | 743 |  |  | 1,080 |  |  | 2,128
Total operating revenues |  | $ | 65,582 |  |  | $ | 159,103 |  | $ | 226,609 |  | $ | 377,965

| (1) |  | The Company adopted ASC 606, “Revenue from Contracts with Customers” effective January 1, 2018 (Predecessor) using the modified retrospective approach under which prior period amounts have not been adjusted.

Oil Sales

The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price adjusted for pricing differentials and other deductions.

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Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, net of applicable market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received.

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

Natural Gas and Natural Gas Liquids Sales

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

Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “Gathering and other " on the consolidated statement of operations.

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

Practical Expedients

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

6. ACQUISITIONS AND DIVESTITURES

Acquisitions

West Quito Draw Properties

On February 6, 2018 (Predecessor), a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018 (Predecessor), and the Company closed the transaction on April 4, 2018 (Predecessor). The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of

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additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 8, “Long-term Debt,” and Note 13, “Stockholders’ Equity,” respectively.

Monument Draw Assets (Ward and Winkler Counties, Texas)

On June 15, 2017 (Predecessor) and January 9, 2018 (Predecessor), the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $87.4 million and $108.2 million in cash, respectively.

Acquisition of Additional Properties in Monument Draw (Ward and Winkler Counties, Texas)

On December 13, 2017 (Predecessor), the Company acquired undeveloped acreage and related assets in the Delaware Basin, in an area contiguous to the western and southern areas of the Company’s existing Monument Draw properties in Ward County, Texas from a private company, for a total adjusted cash purchase price of $101.8 million. The effective date of the acquisition was September 1, 2017 (Predecessor).

Hackberry Draw Assets (Pecos and Reeves Counties, Texas)

On January 18, 2017 (Predecessor), a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it agreed to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin, located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total adjusted purchase price of $699.2 million (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017 (Predecessor). The transaction had an effective date of November 1, 2016 (Predecessor). The Company funded the Pecos County Acquisition with the net proceeds from the private placement of new 8% automatically convertible preferred stock and borrowings under its Predecessor Credit Agreement. Refer to Note 13, “Stockholders’ Equity,” for further discussion of the Company’s issuance of the preferred stock.

The Pecos County Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The estimated fair value of the properties acquired approximates the fair value of consideration and as a result no goodwill was recognized.

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The following table summarizes the consideration paid to acquire the Pecos County Assets, as well as the estimated values of assets acquired and liabilities assumed as of the acquisition date (in thousands):

Cash consideration paid to Samson at closing (1) |  | $ | 703,865
Less: Post-effective closing date adjustments (2) |  |  | (4,677)
Final consideration transferred |  | $ | 699,188
Plus: Estimated Fair Value of Liabilities Assumed: |  |  |
Current liabilities |  | $ | 839
Asset retirement obligations |  |  | 2,116
Amount attributable to liabilities assumed |  |  | 2,955
Total purchase price plus liabilities assumed |  | $ | 702,143
Estimated Fair Value of Assets Acquired: |  |  |
Evaluated oil and natural gas properties (3)(4) |  | $ | 188,275
Unevaluated oil and natural gas properties (3)(4) |  |  | 487,489
Gas gathering and other operating assets (5) |  |  | 26,379
Amount attributable to assets acquired |  | $ | 702,143

| (1) |  | Represents amount of cash consideration, adjusted for customary closing items, for the purchase of the Pecos County Assets funded by the issuance of approximately $400.1 million of new 8% automatically convertible preferred stock and borrowings under the Predecessor Credit Agreement.

| (2) |  | In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 (Predecessor) and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017 (Predecessor), the closing date of the Pecos County Acquisition, have been reflected as adjustments to the purchase price consideration.

| (3) |  | In estimating the fair value of the Pecos County Assets’ oil and natural gas properties, the Company used an income approach. For purposes of estimating the fair value of the proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Pecos County Assets’ estimated reserves risked by reserve category and discounted using a weighted average cost of capital rate of 10.0% for proved reserves and 12.0% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company’s five-year development plan. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate of the Pecos County Assets being classified as Level 3.

| (4) |  | Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $76.10 per barrel of oil, $4.14 per Mcf of natural gas and $29.48 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and research analysts’ estimated prices.

| (5) |  | In estimating the fair value of the Pecos County Assets’ other operating property and equipment, the Company used a combination of the cost and market approaches. A market approach was relied upon to value the land, heavy equipment and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.

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The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2017 (Predecessor) as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016 (Predecessor). The pro forma combined results of operations for the year ended December 31, 2017 (Predecessor) have been prepared by adjusting the historical results of the Company to include the historical results of the Pecos County Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined Company for the periods presented or that may be achieved by the combined Company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Pecos County Acquisition or any estimated costs that will be incurred to integrate the Pecos County Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors. Amounts included in the table below are rounded to thousands, except per share amounts.

|  | Predecessor
|  | Year Ended
|  | December 31, 2017
|  | (Unaudited)
Revenue |  | $ | 385,867
Net income (loss) |  |  | 542,724
Net income (loss) available to common stockholders |  |  | 494,717
Pro forma net income (loss) per share of common stock: |  |  |
Basic |  | $ | 3.73
Diluted |  | $ | 3.70

The Company’s historical financial information was adjusted to give effect to the pro forma events that are directly attributable to the Pecos County Assets and are factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of assets acquired and liabilities assumed, with the following adjustments:

Adjustment to recognize incremental depletion expense under the full cost method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties at acquisition;

Adjustment to recognize incremental depreciation expense of the other operating property and equipment and incremental accretion expense based on the asset retirement costs of the other operating property and equipment at acquisition; and

Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for the Company in the amount of approximately $1.0 million. Transaction costs directly related to the transaction that do not have a continuing impact on the combined Company’s operating results have been excluded from the pro forma earnings.

For the year ended December 31, 2017 (Predecessor), the Company recognized $46.2 million of oil, natural gas and natural gas liquids and other revenue related to the Pecos County Assets and $5.9 million of net field operating income (oil, natural gas and natural gas liquids and other revenues less lease operating expense, workover expense, production taxes, gathering and other expense, and depletion, depreciation and accretion expense) related to the Pecos County Assets. Additionally, non-recurring transaction costs of approximately $1.0 million related to the Pecos County Acquisition for the year ended December 31, 2017 (Predecessor) are included in the consolidated statements of operations in “General and administrative” expenses; these non-recurring transaction costs have been excluded from the pro forma results in the above table.

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Divestitures

Water Infrastructure Assets

On December 20, 2018 (Predecessor), the Company sold its water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for a total adjusted purchase price of $210.9 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018 (Predecessor). Additional incentive payments of up to $25.0 million per year for the years from 2019 to 2023 were available based on the Company’s ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. In August 2019 (Predecessor), the Company and the Purchaser agreed to terminate the incentive payments provision.

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

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

Williston Basin Non-Operated Assets

On September 19, 2017 (Predecessor), certain wholly owned subsidiaries of the Company entered into an agreement with a privately-owned company pursuant to which the Company sold its non-operated properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) for a total adjusted sales price of approximately $103.4 million. The effective date of the transaction was April 1, 2017 (Predecessor) and the transaction closed on November 9, 2017 (Predecessor). Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded.

Williston Basin Operated Assets

On July 10, 2017 (Predecessor), the Company and certain of its subsidiaries entered into an agreement with Bruin Williston Holdings, LLC for the sale of all of the Company’s operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion (the Williston Divestiture). The effective date of the sale was June 1, 2017 (Predecessor) and the transaction closed on September 7, 2017 (Predecessor). The Company used the net proceeds from the sale to repay borrowings outstanding under its Predecessor Credit Agreement, repurchase approximately $425.0 million principal amount of the then outstanding $850 million principal amount of its 6.75% senior notes (refer to Note 8, “Long-term Debt”), redeem all of its then outstanding 12% senior secured second lien notes due 2022 (the 2022 second lien notes) and for general corporate purposes.

The Company recognized a loss on the extinguishment of the 2022 Second Lien Notes of approximately $29.2 million, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the 2022 Second Lien Notes. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statements of operations.

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

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Company’s oil and natural gas properties and approximately $10.9 million was allocated to other operating property and equipment.

As discussed further in Note 7, “Oil and Natural Gas Properties,” the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017 (Predecessor). This gain was reduced by $7.2 million during the year ended December 31, 2018 (Predecessor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on the sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

East Texas Eagle Ford Assets

On January 24, 2017 (Predecessor), certain of the Company’s subsidiaries entered into an agreement with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of the Company’s oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 (Predecessor) and the transaction closed on March 9, 2017 (Predecessor). The Company used the net proceeds from the sale to repay borrowings outstanding under its Predecessor Credit Agreement and for general corporate purposes.

The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $484.1 million was allocated to the Company’s oil and natural gas properties and $10.2 million was allocated to other operating property and equipment.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale in connection with this transaction of $235.7 million during the year ended December 31, 2017 (Predecessor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

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7. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands):

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Subject to depletion |  | $ | 420,609 |  |  | $ | 1,470,509
Not subject to depletion: |  |  |  |  |  |  |
Exploration and extension wells in progress |  |  | — |  |  |  | 23,536
Other capital costs: |  |  |  |  |  |  |
Incurred in 2019(1) |  |  | 105,009 |  |  |  | —
Incurred in 2018 |  |  | — |  |  |  | 310,113
Incurred in 2017 |  |  | — |  |  |  | 638,269
Incurred in 2016 and prior |  |  | — |  |  |  | —
Total not subject to depletion |  |  | 105,009 |  |  |  | 971,918
Gross oil and natural gas properties |  |  | 525,618 |  |  |  | 2,442,427
Less accumulated depletion |  |  | (19,474) |  |  |  | (639,951)
Net oil and natural gas properties |  | $ | 506,144 |  |  | $ | 1,802,476

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

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

With the adoption of fresh-start accounting, the Company recorded its oil and natural gas properties at fair value as of the Emergence Date. The Company’s evaluated and unevaluated properties were assigned fair values of $380.4 million and $109.0 million, respectively. Refer to Note 3, “Fresh-start Accounting,” for a discussion of the valuation approaches used.

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

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. For the three months ended June 30, 2019 (Predecessor), the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool, the majority of which were associated with the Company’s Hackberry Draw area. For the three months ended March 31, 2019 (Predecessor), the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0

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million of associated unevaluated property costs to the full cost pool. These transfers of unevaluated property to the full cost pool in 2019 were the result of the Company’s focus on its most economic area, Monument Draw.

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

|  | West Texas Intermediate (per barrel) (1) |  | Henry Hub (per MMBtu) (1)
December 31, 2019 |  | $ | 55.85 |  | $ | 2.578
December 31, 2018 |  |  | 65.56 |  |  | 3.100
December 31, 2017 |  |  | 51.34 |  |  | 2.976

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

The Company’s net book value of oil and natural gas properties at March 31, June 30, and September 30, 2019 (Predecessor) exceeded the ceiling amount and the Company recorded full cost ceiling test impairments before income taxes of $275.2 million, $664.4 million and $45.6 million, respectively, for the periods. The ceiling test impairments during 2019 (Predecessor) were driven by the transfers of unevaluated property to the full cost pool that occurred during the year, as discussed above, and decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations. The Company’s net book value of oil and natural gas properties in 2018 and 2017 (Predecessor) did not exceed the ceiling amount.

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

Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón and Williston Divestitures were accounted for as adjustments of capitalized costs with no gain or loss recognized, the adjustments would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the oil and natural gas properties associated with the El Halcón Divestiture of $235.7 million for the year ended December 31, 2017 (Predecessor). The Company recognized an initial gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017 (Predecessor). This gain was reduced by $7.2 million during the year ended December 31, 2018 (Predecessor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain (loss) was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

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8. LONG‑TERM DEBT

Long‑term debt as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands):

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Successor senior revolving credit facility |  | $ | 144,000 |  |  | $ | —
6.75% senior notes due 2025 (1) |  |  | — |  |  |  | 613,105
|  | $ | 144,000 |  |  | $ | 613,105

| (1) |  | The Company’s 6.75% senior notes due 2025 were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy. Amount includes a $7.2 million unamortized discount at December 31, 2018 (Predecessor) associated with the 2025 Notes. Amount includes a $5.4 million unamortized premium at December 31, 2018 (Predecessor) associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.1 million unamortized debt issuance costs at December 31, 2018 (Predecessor).

Successor Senior Revolving Credit Facility

On the Effective Date, the Company entered into a senior secured revolving credit agreement, as amended on November 21, 2019, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, both discussed below. The Senior Credit Agreement provides for a $750.0 million senior secured reserve‑based revolving credit facility with a current borrowing base of $240.0 million. A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process. These margins fluctuate based on the Company’s utilization of the facility.

The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement. The Company may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. Amounts outstanding under the Senior Credit Agreement are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries.

The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00, both commencing with the fiscal quarter ending March 31, 2020. As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement.

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At December 31, 2019 (Successor), the Company had $144.0 million indebtedness outstanding, approximately $2.3 million letters of credit outstanding and approximately $93.7 million of borrowing capacity available under the Senior Credit Agreement.

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

Debtor-in-Possession Financing

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

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

The Predecessor Company used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with the Predecessor Company’s budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit.

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

The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secured the Predecessor Credit Agreement (defined below) and (ii) a senior secured perfected security interest on all unencumbered assets of the Company and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement.

The DIP Credit Agreement contained certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones.

Predecessor Senior Revolving Credit Facility

On September 7, 2017, the Predecessor Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Predecessor Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Predecessor Credit Agreement, the lenders party thereto agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a borrowing base of $225.0 million as of October 1, 2019 (Predecessor). The maturity date of the Predecessor Credit Agreement was September 7, 2022. The borrowing base was redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled

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redetermination between any two consecutive semi-annual redeterminations. The borrowing base took into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Predecessor Credit Agreement bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the Company’s utilization of the facility. The Predecessor Credit Agreement was refinanced by the Senior Credit Agreement upon emergence from chapter 11 bankruptcy.

6.75% Senior Notes

On February 16, 2017, the Predecessor Company issued $850.0 million aggregate principal amount of 6.75% senior notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bore interest at a rate of 6.75% per annum, payable semi‑annually on February 15 and August 15 of each year. The maturity date of the 2025 Notes was February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers’ discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes (the 2020 Second Lien Notes), and for general corporate purposes. Upon repurchase and redemption of the 2020 Second Lien Notes during the three months ended March 31, 2017, the Predecessor Company recorded a loss on extinguishment of debt of approximately $56.9 million, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statement of operations.

On July 25, 2017, the Predecessor Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the indenture governing the 2025 Notes from approximately 99% of the holders of the 2025 Notes. As supplemented, the indenture governing the 2025 Notes exempted, among other things, the Williston Divestiture from certain provisions triggered upon a sale of “all or substantially all of the assets” of the Company. Consenting holders of the 2025 Notes received a consent fee of 2.0% of principal, or $16.9 million. The Company recorded the $16.9 million consent fees paid as a discount on the 2025 Notes.

On September 7, 2017, the Predecessor Company commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of its 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a “Williston Sale” under the indenture governing the 2025 Notes, and the Company was required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the 2025 Notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, the Predecessor Company repurchased approximately $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest of approximately $4.1 million.

The Company recognized a loss on the extinguishment of debt of approximately $28.9 million, representing a $12.8 million loss on the repurchase for the tender premium paid, an $8.3 million loss on the write-off of the discount, and a $7.8 million loss on the write-off of the debt issuance costs on the notes repurchased. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statements of operations.

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

On the Petition Date, the 2025 Notes represented "Liabilities subject to compromise" and the corresponding discount of $6.6 million and premium of $4.9 million were written-off to "Reorganization items, net" on the

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consolidated statements of operations. On October 8, 2019, upon emergence from chapter 11 bankruptcy, the 2025 Notes were cancelled. The Company discontinued recording interest on the 2025 Notes as of the Petition Date. The contractual interest expense not accrued or recorded in the consolidated statement of operations was approximately $7.1 million, representing interest expense from the Petition Date through the Effective Date. Refer to Note 2, “Reorganization” for further details.

Debt Maturities

Aggregate maturities required on long-term debt at December 31, 2019 (Successor) due in future years are as follows (in thousands, excluding discounts, premiums and debt issuance costs):

2020 |  | $ | —
2021 |  |  | —
2022 |  |  | —
2023 |  |  | —
2024 |  |  | 144,000
Thereafter |  |  | —
Total |  | $ | 144,000

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company expensed to “Reorganization items, net” $9.3 million of debt issuance costs associated with its 2025 Notes, which were cancelled upon emergence from chapter 11 bankruptcy. During the period, the Company also expensed to “Interest expense and other” $0.7 million of debt issuance costs associated with its Predecessor Credit Agreement. At December 31, 2019 (Successor) and 2018 (Predecessor), the Company had zero and $11.1 million of unamortized debt issuance costs, respectively. The debt issuance costs for the Company’s Predecessor Credit Agreement were presented in “Funds in escrow and other” within total assets on the consolidated balance sheet, and the debt issuance costs for the Predecessor Company’s senior unsecured debt were presented in “Long-term debt, net” within total liabilities on the consolidated balance sheet.

9. FAIR VALUE MEASUREMENTS

Pursuant to ASC 820, Fair Value Measurement (ASC 820), the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company’s financial

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assets and liabilities that were accounted for at fair value as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands):

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

|  | Predecessor
|  | December 31, 2018
|  | Level 1 |  | Level 2 |  | Level 3 |  | Total
Assets |  |  |  |  |  |  |  |  |  |  |  |
Assets from derivative contracts |  | $ | — |  | $ | 69,717 |  | $ | — |  | $ | 69,717
Liabilities |  |  |  |  |  |  |  |  |  |  |  |
Liabilities from derivative contracts |  | $ | — |  | $ | 12,907 |  | $ | — |  | $ | 12,907

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 10, “Derivative and Hedging Activities,” for additional discussion of derivatives.

The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short‑term nature. The estimated fair value of the Company’s Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company’s fixed interest rate, long‑term debt instruments as of December 31, 2019 (Successor) and 2018 (Predecessor) (excluding discounts, premiums and debt issuance costs) (in thousands):

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
|  | Principal |  | Estimated |  |  | Principal |  | Estimated
Debt |  | Amount |  | Fair Value |  |  | Amount |  | Fair Value
6.75% senior notes(1) |  | $ | — |  | $ | — |  |  | $ | 625,005 |  | $ | 458,210

| (1) |  | The 6.75% senior notes were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy.

The fair value of the Company’s fixed interest debt instruments was calculated using Level 1 criteria. The fair value of the Company’s senior notes is based on quoted market prices from trades of such debt.

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

On February 28, 2017 (Predecessor), the Company closed the Pecos County Acquisition and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 6, "Acquisitions and Divestitures,” for a discussion of the fair value approaches used by the Company and the classification of the estimates within the fair value hierarchy.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non‑recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 11, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

10. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy, it generally hedges a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2019 (Successor), the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Credit Agreement or are uncollateralized trades.

The Company’s crude oil, natural gas and natural gas liquids derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing). WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value

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amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands):

Derivatives not designated |  |  |  |  | Asset derivative contracts |  |  |  |  | Liability derivative contracts
as hedging contracts under |  |  |  |  | Successor |  |  |  | Predecessor |  |  |  |  | Successor |  |  |  | Predecessor
ASC 815 |  | Balance sheet location |  |  | December 31, 2019 |  |  |  | December 31, 2018 |  | Balance sheet location |  |  | December 31, 2019 |  |  |  | December 31, 2018
Commodity contracts |  | Current assets - assets from derivative contracts |  | $ | 4,995 |  |  | $ | 57,280 |  | Current liabilities - liabilities from derivative contracts |  | $ | (8,069) |  |  | $ | (3,768)
Commodity contracts |  | Other noncurrent assets - assets from derivative contracts |  |  | 224 |  |  |  | 12,437 |  | Other noncurrent liabilities - liabilities from derivative contracts |  |  | (4,854) |  |  |  | (9,139)
Total derivatives not designated as hedging contracts under ASC 815 |  | $ | 5,219 |  |  | $ | 69,717 |  |  |  | $ | (12,923) |  |  | $ | (12,907)

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands):

|  |  |  |  | Amount of gain or (loss) recognized in income on derivative contracts for the
|  |  |  |  | Successor |  |  |  | Predecessor
|  |  |  |  | Period from |  |  |  | Period from |  |  |  |  |  |
|  |  |  |  | October 2, 2019 |  |  |  | January 1, 2019 |  |  |  |  |  |
Derivatives not designated as hedging |  | Location of gain or (loss) recognized in |  |  | through |  |  |  | through |  |  | Years Ended December 31,
contracts under ASC 815 |  | income on derivative contracts |  |  | December 31, 2019 |  |  |  | October 1, 2019 |  |  | 2018 |  | 2017
Commodity contracts: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Unrealized gain (loss) on commodity contracts |  | Other income (expenses) - net gain (loss) on derivative contracts |  | $ | (18,681) |  |  | $ | (45,834) |  | $ | 84,274 |  | $ | (16,468)
Realized gain (loss) on commodity contracts |  | Other income (expenses) - net gain (loss) on derivative contracts |  |  | 1,989 |  |  |  | 11,502 |  |  | 8,351 |  |  | 17,759
Total net gain (loss) on derivative contracts |  | $ | (16,692) |  |  | $ | (34,332) |  | $ | 92,625 |  | $ | 1,291

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At December 31, 2019 (Successor) and 2018 (Predecessor), the Company had the following open crude oil and natural gas derivative contracts:

|  |  |  |  |  | Successor
|  |  |  |  |  | December 31, 2019
|  |  |  |  |  |  |  | Floors |  | Ceilings |  |  | Basis Differential
|  |  |  |  |  | Volume in |  |  |  |  | Weighted |  |  |  | Weighted |  |  |  |  | Weighted
|  |  |  |  |  | Mmbtu's/ |  | Price / |  | Average |  | Price / |  | Average |  |  | Price / |  | Average
Period |  | Instrument |  | Commodity |  | Bbl's |  | Price Range |  | Price |  | Price Range |  | Price |  |  | Price Range |  | Price
January 2020 - June 2020 |  | Fixed-Price Swap |  | Crude Oil |  | 182,000 |  | $ | 55.74 |  | $ | 55.74 |  | $ | — |  | $ | — |  | $ | — |  | $ | —
January 2020 - September 2020 |  | Fixed-Price Swap |  | Natural Gas |  | 1,186,000 |  |  | 2.61 |  |  | 2.61 |  |  |  |  |  |  |  |  |  |  |  |
January 2020 - December 2020 |  | Fixed-Price Swap |  | Crude Oil |  | 732,000 |  |  | 55.68 - 60.00 |  |  | 57.84 |  |  |  |  |  |  |  |  |  |  |  |
January 2020 - December 2020 |  | Fixed-Price Swap |  | Natural Gas |  | 2,928,000 |  |  | 2.55 - 2.57 |  |  | 2.56 |  |  |  |  |  |  |  |  |  |  |  |
January 2020 - December 2020 |  | Collar |  | Crude Oil |  | 549,000 |  |  | 50.00 |  |  | 50.00 |  |  | 70.00 |  |  | 70.00 |  |  |  |  |  |
January 2020 - December 2020 |  | Call |  | Crude Oil |  | 2,342,400 |  |  |  |  |  |  |  |  | 70.00 |  |  | 70.00 |  |  |  |  |  |
January 2020 - December 2020 |  | Put |  | Crude Oil |  | 915,000 |  |  | 55.00 |  |  | 55.00 |  |  |  |  |  |  |  |  |  |  |  |
January 2020 - December 2020 |  | Basis Swap |  | Crude Oil |  | 1,464,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 0.67 - 0.85 |  |  | 0.72
January 2020 - December 2020 |  | WTI NYMEX Roll |  | Crude Oil |  | 366,000 |  |  | 0.37 |  |  | 0.37 |  |  |  |  |  |  |  |  |  |  |  |
February 2020 - December 2020 |  | WTI NYMEX Roll |  | Crude Oil |  | 1,340,000 |  |  | 0.41 - 0.54 |  |  | 0.44 |  |  |  |  |  |  |  |  |  |  |  |
April 2020 - December 2020 |  | Basis Swap |  | Crude Oil |  | 275,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 0.75 |  |  | 0.75
January 2021 - December 2021 |  | Fixed-Price Swap |  | Crude Oil |  | 1,460,000 |  |  | 50.70 - 52.80 |  |  | 51.91 |  |  |  |  |  |  |  |  |  |  |  |
January 2021 - December 2021 |  | Fixed-Price Swap |  | Natural Gas |  | 2,190,000 |  |  | 2.47 - 2.48 |  |  | 2.47 |  |  |  |  |  |  |  |  |  |  |  |
January 2021 - December 2021 |  | Basis Swap |  | Crude Oil |  | 1,460,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 0.82 - 0.95 |  |  | 0.85
January 2021 - December 2021 |  | WTI NYMEX Roll |  | Crude Oil |  | 1,460,000 |  |  | 0.13 - 0.14 |  |  | 0.14 |  |  |  |  |  |  |  |  |  |  |  |
January 2022 - December 2022 |  | Fixed-Price Swap |  | Crude Oil |  | 1,460,000 |  |  | 51.50 |  |  | 51.50 |  |  |  |  |  |  |  |  |  |  |  |
January 2022 - December 2022 |  | Basis Swap |  | Crude Oil |  | 1,460,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 0.85 - 0.95 |  |  | 0.88
January 2022 - December 2022 |  | WTI NYMEX Roll |  | Crude Oil |  | 2,555,000 |  |  | (0.02) - 0.00 |  |  | (0.01) |  |  |  |  |  |  |  |  |  |  |  |

|  |  |  |  |  | Predecessor
|  |  |  |  |  | December 31, 2018
|  |  |  |  |  |  |  | Floors |  | Ceilings |  | Basis Differential
|  |  |  |  |  | Volume in |  |  |  |  | Weighted |  |  |  |  | Weighted |  |  |  |  | Weighted
|  |  |  |  |  | Mmbtu's/ |  | Price / |  | Average |  | Price / |  | Average |  | Price / |  | Average
Period |  | Instrument |  | Commodity |  | Bbl's |  | Price Range |  | Price |  | Price Range |  | Price |  | Price Range |  | Price
January 2019 - March 2019 |  | Calls |  | Crude Oil |  | 1,350,000 |  | $ | — |  | $ | — |  | $ | 62.64 |  | $ | 62.64 |  | $ | — |  | $ | —
January 2019 - March 2019 |  | Calls |  | Crude Oil |  | (1,350,000) |  |  |  |  |  |  |  |  | 58.64 |  |  | 58.64 |  |  |  |  |  |
January 2019 - March 2019 |  | Collars |  | Crude Oil |  | 90,000 |  |  | 46.75 |  |  | 46.75 |  |  | 51.75 |  |  | 51.75 |  |  |  |  |  |
January 2019 - June 2019 |  | Collars |  | Crude Oil |  | 181,000 |  |  | 51.00 |  |  | 51.00 |  |  | 56.00 |  |  | 56.00 |  |  |  |  |  |
January 2019 - September 2019 |  | Basis Swap |  | Crude Oil |  | 546,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (6.20) - (7.60) |  |  | (6.90)
January 2019 - December 2019 |  | Fixed-Price Swap |  | Natural Gas Liquids |  | 1,460,000 |  |  | 29.08 - 30.15 |  |  | 29.33 |  |  |  |  |  |  |  |  |  |  |  |
January 2019 - December 2019 |  | Collars |  | Crude Oil |  | 3,650,000 |  |  | 50.00 - 58.00 |  |  | 53.87 |  |  | 55.20 - 63.00 |  |  | 60.07 |  |  |  |  |  |
January 2019 - December 2019 |  | Collars |  | Natural Gas |  | 8,760,000 |  |  | 2.52 - 2.70 |  |  | 2.60 |  |  | 3.00 - 3.10 |  |  | 3.01 |  |  |  |  |  |
January 2019 - December 2019 |  | Basis Swap |  | Crude Oil |  | 2,448,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (0.98) - (6.50) |  |  | (2.80)
January 2019 - December 2019 |  | Basis Swap |  | Natural Gas |  | 9,307,500 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (1.05) - (1.40) |  |  | (1.18)
January 2019 - December 2019 |  | WTI NYMEX Roll |  | Crude Oil |  | 1,825,000 |  |  | 0.35 |  |  | 0.35 |  |  |  |  |  |  |  |  |  |  |  |
April 2019 - June 2019 |  | Collars |  | Crude Oil |  | 91,000 |  |  | 50.00 |  |  | 50.00 |  |  | 55.00 |  |  | 55.00 |  |  |  |  |  |
April 2019 - December 2019 |  | Collars |  | Crude Oil |  | 275,000 |  |  | 55.00 |  |  | 55.00 |  |  | 62.85 |  |  | 62.85 |  |  |  |  |  |
July 2019 - December 2019 |  | Collars |  | Crude Oil |  | 552,000 |  |  | 50.00 - 55.00 |  |  | 53.00 |  |  | 55.00 - 69.00 |  |  | 61.00 |  |  |  |  |  |
July 2019 - December 2019 |  | Basis Swap |  | Crude Oil |  | 460,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (2.40) - (6.50) |  |  | (5.68)
October 2019 - December 2019 |  | Fixed-Price Swap |  | Natural Gas Liquids |  | 92,000 |  |  | 32.50 |  |  | 32.50 |  |  |  |  |  |  |  |  |  |  |  |
October 2019 - December 2019 |  | Collars |  | Crude Oil |  | 92,000 |  |  | 51.00 |  |  | 51.00 |  |  | 56.00 |  |  | 56.00 |  |  |  |  |  |
October 2019 - December 2019 |  | Basis Swap |  | Crude Oil |  | 460,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3.45 - 4.00 |  |  | 3.72
January 2020 - December 2020 |  | Collars |  | Crude Oil |  | 549,000 |  |  | 50.00 |  |  | 50.00 |  |  | 70.00 |  |  | 70.00 |  |  |  |  |  |
January 2020 - December 2020 |  | Calls |  | Crude Oil |  | 2,342,400 |  |  |  |  |  |  |  |  | 70.00 |  |  | 70.00 |  |  |  |  |  |
January 2020 - December 2020 |  | Puts |  | Crude Oil |  | 915,000 |  |  | 55.00 |  |  | 55.00 |  |  |  |  |  |  |  |  |  |  |  |
January 2020 - December 2020 |  | Basis Swap |  | Crude Oil |  | 3,294,000 |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2.00 - 4.00 |  |  | 2.95

The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands):

|  | Derivative Assets |  | Derivative Liabilities
|  | Successor |  |  | Predecessor |  | Successor |  |  | Predecessor
Offsetting of Derivative Assets and Liabilities |  | December 31, 2019 |  |  | December 31, 2018 |  | December 31, 2019 |  |  | December 31, 2018
Gross amounts presented in the consolidated balance sheet |  | $ | 5,219 |  |  | $ | 69,717 |  | $ | (12,923) |  |  | $ | (12,907)
Amounts not offset in the consolidated balance sheet |  |  | (4,557) |  |  |  | (10,263) |  |  | 4,557 |  |  |  | 10,263
Net amount |  | $ | 662 |  |  | $ | 59,454 |  | $ | (8,366) |  |  | $ | (2,644)

The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all

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derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

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

11. ASSET RETIREMENT OBLIGATIONS

The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.

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

Liability for asset retirement obligations as of December 31, 2017 (Predecessor) |  | $ | 4,368
Liabilities settled and divested (1) |  |  | (590)
Additions |  |  | 988
Acquisitions (1) |  |  | 2,465
Accretion expense |  |  | 329
Revisions in estimated cash flows |  |  | (646)
Liability for asset retirement obligations as of December 31, 2018 (Predecessor) |  | $ | 6,914
Liabilities settled and divested (1) |  |  | (229)
Additions |  |  | 354
Accretion expense |  |  | 307
Revisions in estimated cash flows |  |  | 2,807
Liability for asset retirement obligations as of October 1, 2019 (Predecessor) |  | $ | 10,153
Fair Value Adjustment |  | $ | —
Liability for asset retirement obligations as of October 1, 2019 (Successor) |  | $ | 10,153
Additions |  |  | 293
Accretion expense |  |  | 144
Liability for asset retirement obligations as of December 31, 2019 (Successor) |  | $ | 10,590

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

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12. COMMITMENTS AND CONTINGENCIES

Commitments

As of December 31, 2019 (Successor), the Company has an active drilling rig commitment of approximately $3.2 million that will be incurred during 2020. Termination of the active drilling rig commitment would require an early termination penalty of $2.6 million, which would be in lieu of paying the active drilling rig commitment of $3.2 million.

As of December 31, 2019 (Successor), the Company has purchase commitments related to equipment of approximately $8.2 million that will be incurred during 2020.

The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of December 31, 2019 (Successor), the Company had in place three long-term crude oil contracts and 14 long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production.

Contingencies

On February 26, 2019 (Predecessor), a subsidiary of the Company was ordered to pay $9,107,054 in a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013‑0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage. The Court of Common Pleas of Mercer County, Pennsylvania marked the judgment as satisfied on February 3, 2020 (Successor) and the Company considers this contingency resolved.

In addition to the matter described above, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s consolidated operating results, financial position or cash flows.

13. STOCKHOLDERS’ EQUITY

Common Stock

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

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

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

Warrants

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

Each Warrant represents the right to purchase one share of common stock at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On the Effective Date, the Company issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of common stock, with an initial exercise price of $40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of common stock, with an initial exercise price of $48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of common stock, with an initial exercise price of $60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75%, compounding monthly, as provided in the Warrant Agreement. As of December 31, 2019, the exercise prices of the Series A, B and C Warrants were $40.51, $48.71 and $61.02, respectively.

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

On September 9, 2016, the Predecessor Company issued 4.7 million warrants. The warrants could be exercised to purchase 4.7 million shares of the Predecessor Company's common stock at an exercise price of $14.04 per share. The holders were entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020.

Preferred Stock and Non-Cash Preferred Stock Dividend

On January 24, 2017 (the Commitment Date), the Predecessor Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on January 24, 2017 (Predecessor), the Company received an executed written consent in lieu of a stockholders’ meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017 (Predecessor), the Company filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by the Company on that same date. The Company issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. The Company incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. On March 16, 2017 (Predecessor), the Company mailed a definitive information statement to its stockholders notifying them that a majority of its stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on April 6, 2017 (Predecessor) in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017 (Predecessor).

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In accordance with ASC Topic 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the Company’s common stock of $8.12 per share on the Commitment Date was greater than the conversion price of $7.25 per share of common stock, representing a beneficial conversion feature of $0.87 per share of common stock, or approximately $48.0 million in aggregate. Under ASC 470, $48.0 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to “Additional paid‑in capital,” creating a discount on the Preferred Stock (the Discount). The Discount is required to be amortized on a non‑cash basis over the approximate 65-month period between the issuance date and the required redemption date of July 28, 2022, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. The Discount was fully amortized and a non‑cash preferred dividend was recorded upon the conversion date of April 6, 2017 (Predecessor). The Discount amortization is reflected in “Non‑cash preferred dividend” in the consolidated statements of operations. The preferred dividend was charged against additional paid‑in capital since no retained earnings were available.

Incentive Plans

On September 9, 2016, the Predecessor Company’s board of directors adopted the 2016 Long‑Term Incentive Plan (the 2016 Plan). As of April 6, 2017 (Predecessor), an aggregate of 19.0 million shares of the Predecessor Company’s common stock were available for grant pursuant to awards under the 2016 Plan. As of December 31, 2018 (Predecessor), a maximum of 4.9 million shares of the Predecessor Company’s common stock remained reserved for issuance under the 2016 Plan. Immediately prior to emergence from chapter 11 bankruptcy, the 2016 Plan was cancelled and all outstanding stock-based compensation awards granted thereunder were either vested or cancelled.

On January 29, 2020, the Successor Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the 2020 Plan). An aggregate of approximately 1.5 million shares of the Successor Company’s common stock are available for grant pursuant to awards under the 2020 Plan.

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

For the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company recognized zero and a credit of $8.0 million, respectively, related to stock-based-compensation recorded as a component of "General and administrative" on the consolidated statement of operations. During 2019 (both in Successor and Predecessor periods), senior executives departed the Company. In accordance with the terms of these senior executives' employment agreements, unvested stock options and unvested shares of restricted stock were modified to vest immediately upon termination or approval by the Bankruptcy Court. For the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company recognized incremental reductions to stock-based compensation expense of $9.5 million, respectively, associated with these modifications.

For the years ended December 31, 2018 and 2017 (Predecessor), the Company recognized $15.3 million and $36.8 million of stock-based compensation expense, respectively, related to stock-based compensation recorded as a component of "General and administrative" on the consolidated statement of operations.

Stock Options

From time to time, the Company granted stock options under the 2016 Plan covering shares of common stock to employees of the Predecessor Company. Stock options, when exercised, were settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vested over a three year period at a rate of one-third on the annual anniversary date of the grant and expired ten years from the grant date.

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

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

The weighted average grant date fair value of options granted during the year ended December 31, 2017 (Predecessor) was $7.8 million. At December 31, 2017, the Predecessor Company had $13.0 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average vesting period of 1.2 years.

Immediately prior to emergence from chapter 11 bankruptcy, all outstanding stock options under the 2016 Plan were cancelled. Refer to Note 2, “Reorganization,” for further details.

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

|  | Number |  | Weighted Average Exercise Price Per Share |  | Aggregate Intrinsic Value(1) (In thousands) |  | Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2016 (Predecessor) |  | 5,319,400 |  | $ | 9.22 |  | $ | 631 |  | 9.7
Granted |  | 1,790,605 |  |  | 7.72 |  |  |  |  |
Exercised |  | — |  |  | — |  |  |  |  |
Forfeited |  | (374,102) |  |  | 8.82 |  |  |  |  |
Outstanding at December 31, 2017 (Predecessor) |  | 6,735,903 |  | $ | 8.84 |  | $ | 29 |  | 8.9
Granted |  | 1,206,800 |  |  | 5.65 |  |  |  |  |
Exercised |  | (41,667) |  |  | 7.75 |  |  | 29 |  |
Forfeited |  | (432,110) |  |  | 8.68 |  |  |  |  |
Outstanding at December 31, 2018 (Predecessor) |  | 7,468,926 |  | $ | 8.34 |  | $ | — |  | 8.1
Granted |  | — |  |  | — |  |  |  |  |
Exercised |  | — |  |  | — |  |  |  |  |
Forfeited |  | (5,182,238) |  |  | 8.38 |  |  |  |  |
Cancelled(2) |  | (2,286,688) |  |  | 8.26 |  |  |  |  |
Outstanding at October 1, 2019 (Predecessor) |  | — |  | $ | — |  | $ | — |  | —
Outstanding at October 1, 2019 (Successor) |  | — |  |  |  |  |  |  |  |
Granted |  | — |  |  |  |  |  |  |  |
Exercised |  | — |  |  |  |  |  |  |  |
Forfeited |  | — |  |  |  |  |  |  |  |
Outstanding at December 31, 2019 (Successor) |  | — |  | $ | — |  | $ | — |  | —

| (1) |  | The period end intrinsic value of stock options was calculated as the amount by which the closing market price on December 31, 2018, 2017 and 2016 (Predecessor) of the underlying stock exceeded the exercise price of the option. The intrinsic value of stock options exercised during the year ended December 31, 2018 (Predecessor) was calculated as the amount by which the market price at the time of exercise of the underlying stock exceeded the exercise price of the option.

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

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The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Company’s stock options for years ended December 31, 2018 and 2017 (Predecessor) are set forth in the following table:

|  | Predecessor |
|  | Years Ended December 31, |
|  | 2018 |  | 2017 |
Weighted average value per option granted during the period |  | $ | 2.92 |  | $ | 4.36 |
Assumptions: |  |  |  |  |  |  |
Stock price volatility(1) |  |  | 52.08 | % |  | 60.18 | %
Risk free rate of return |  |  | 2.63 | % |  | 1.94 | %
Expected term |  |  | 6 | years |  | 6 | years

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

Restricted Stock

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

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

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

The weighted average grant date fair value of shares granted during the year ended December 31, 2017 (Predecessor) was $14.3 million. At December 31, 2017, the Predecessor Company had $3.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average vesting period of 1.4 years.

Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock granted under the 2016 Plan was vested. Refer to Note 2, "Reorganization," for further details.

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

|  | Number of Shares |  | Weighted Average Grant Date Fair Value Per Share |  | Aggregate Intrinsic Value(1) (In thousands)
Unvested outstanding shares at December 31, 2016 (Predecessor) |  | 1,738,077 |  | $ | 9.06 |  | $ | 16,234
Granted |  | 2,022,432 |  |  | 7.07 |  |  |
Vested |  | (2,516,647) |  |  | 8.39 |  |  |
Forfeited |  | (498,355) |  |  | 7.41 |  |  |
Unvested outstanding shares at December 31, 2017 (Predecessor) |  | 745,507 |  | $ | 7.05 |  | $ | 5,643
Granted |  | 2,326,961 |  |  | 5.47 |  |  |
Vested |  | (537,411) |  |  | 5.89 |  |  |
Forfeited |  | (262,164) |  |  | 6.29 |  |  |
Unvested outstanding shares at December 31, 2018 (Predecessor) |  | 2,272,893 |  | $ | 5.80 |  | $ | 3,864
Granted |  | 4,163,348 |  |  | 1.29 |  |  |
Vested |  | (1,611,465) |  |  | 4.65 |  |  |
Accelerated vesting(2) |  | (2,724,086) |  |  | 2.07 |  |  |
Forfeited |  | (2,100,690) |  |  | 2.58 |  |  |
Unvested outstanding shares at October 1, 2019 (Predecessor) |  | — |  | $ | — |  | $ | —
Unvested outstanding shares at October 1, 2019 (Successor) |  | — |  |  |  |  |  |
Granted |  | — |  |  |  |  |  |
Vested |  | — |  |  |  |  |  |
Forfeited |  | — |  |  |  |  |  |
Unvested outstanding shares at December 31, 2019 (Successor) |  | — |  | $ | — |  | $ | —

| (1) |  | The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2018, 2017 and 2016 (Predecessor) of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $1.8 million, $2.0 million and $16.1 million for the period of January 1, 2019 through October 1, 2019 (Predecessor), the years ended December 31, 2018 and 2017 (Predecessor), respectively.

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

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14. INCOME TAXES

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

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Current: |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | — |  | $ | — |  | $ | 5,000
State |  |  | — |  |  |  | — |  |  | — |  |  | —
|  |  | — |  |  |  | — |  |  | — |  |  | 5,000
Deferred: |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  |  | — |  |  |  | 95,791 |  |  | (95,791) |  |  | —
State |  |  | — |  |  |  | — |  |  | — |  |  | —
|  |  | — |  |  |  | 95,791 |  |  | (95,791) |  |  | —
Total income tax benefit (provision) |  | $ | — |  |  | $ | 95,791 |  | $ | (95,791) |  | $ | 5,000

The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the period from October 2, 2019 through December 31, 2019 (Successor), the period from January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor) and 35% for the year ended December 31, 2017 (Predecessor), as follows (in thousands):

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Expected tax benefit (provision) |  | $ | 2,196 |  |  | $ | 262,888 |  | $ | (29,767) |  | $ | (185,740)
State income tax expense, net of federal benefit |  |  | — |  |  |  | — |  |  | — |  |  | (2,587)
Stock-based compensation |  |  | — |  |  |  | (6,093) |  |  | (350) |  |  | —
Change in state rate |  |  | — |  |  |  | — |  |  | — |  |  | (10,121)
Capital loss |  |  | — |  |  |  | 271,248 |  |  | — |  |  | —
Increase (reduction) in deferred tax asset |  |  | — |  |  |  | (9,287) |  |  | (201,903) |  |  | 95,907
Change in valuation allowance and related items |  |  | (1,506) |  |  |  | (186,851) |  |  | 136,432 |  |  | 392,846
Attribute reduction |  |  |  |  |  |  | (229,385) |  |  | — |  |  | —
Tax Cuts and Jobs Act of 2017 |  |  | — |  |  |  | — |  |  | — |  |  | (280,874)
Permanent adjustments |  |  | (690) |  |  |  | (7,241) |  |  | (203) |  |  | —
Other |  |  | — |  |  |  | 512 |  |  | — |  |  | (4,431)
Total income tax benefit (provision) |  | $ | — |  |  | $ | 95,791 |  | $ | (95,791) |  | $ | 5,000

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

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Deferred noncurrent income tax assets: |  |  |  |  |  |  |
Net operating loss carry-forwards |  | $ | 46,382 |  |  | $ | 204,751
Built in loss adjustment Section 382 |  |  | 142,285 |  |  |  | 88,835
Capital loss carryforward |  |  | 74,848 |  |  |  | —
Stock-based compensation expense |  |  | — |  |  |  | 8,509
Asset retirement obligations |  |  | 2,224 |  |  |  | 1,011
Book-tax differences in property basis |  |  | 200,478 |  |  |  | —
Unrealized hedging transactions |  |  | 1,618 |  |  |  | —
Disallowed interest Section 163(j) |  |  | 7,722 |  |  |  | 3,370
Basis difference in debt |  |  | 2,142 |  |  |  | —
Operating lease liability |  |  | 666 |  |  |  | —
Other |  |  | 991 |  |  |  | 1,917
Gross deferred noncurrent income tax assets |  |  | 479,356 |  |  |  | 308,393
Valuation allowance |  |  | (478,690) |  |  |  | (290,333)
Deferred noncurrent income tax assets |  | $ | 666 |  |  | $ | 18,060
Deferred noncurrent income tax liabilities: |  |  |  |  |  |  |
Basis difference in debt |  | $ | — |  |  | $ | (5,507)
Book-tax differences in property basis |  |  | — |  |  |  | (96,414)
Unrealized hedging transactions |  |  | — |  |  |  | (11,930)
Lease right of use |  |  | (666) |  |  |  | —
Deferred noncurrent income tax liabilities |  | $ | (666) |  |  | $ | (113,851)
Net noncurrent deferred income tax assets (liabilities) |  | $ | — |  |  | $ | (95,791)

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

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

The amount of U.S. consolidated NOLs available as of December 31, 2019 (Successor) after attribute reduction is estimated to be approximately $675.1 million, but the amount after attribute reduction and the Section 382 limitation is

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$220.0 million.. Of this amount, $103.2 million is subject to the 20 year carryforward period and will expire in 2037. The remaining $117.7 million may be carried forward indefinitely but in part subject to a Section 382 limitation.

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2019 (Successor), a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2019 (Successor) of $478.7 million, an increase of $188.4 million from December 31, 2018 (Predecessor). The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized.

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

Generally, the Company’s income tax years 2016 through 2019 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes.

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

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15. EARNINGS PER SHARE

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

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

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Basic: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) available to common stockholders |  | $ | (10,460) |  |  | $ | (1,156,053) |  | $ | 45,959 |  | $ | 487,679
Weighted average basic number of common shares outstanding |  |  | 16,204 |  |  |  | 158,925 |  |  | 157,011 |  |  | 132,763
Basic net income (loss) per common share |  | $ | (0.65) |  |  | $ | (7.27) |  | $ | 0.29 |  | $ | 3.67
Diluted: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) available to common stockholders |  | $ | (10,460) |  |  | $ | (1,156,053) |  | $ | 45,959 |  | $ | 487,679
Weighted average basic number of common shares outstanding |  |  | 16,204 |  |  |  | 158,925 |  |  | 157,011 |  |  | 132,763
Common stock equivalent shares representing shares issuable upon: |  |  |  |  |  |  |  |  |  |  |  |  |
Exercise of Predecessor stock options |  |  | — |  |  |  | Anti-dilutive |  |  | Anti-dilutive |  |  | Anti-dilutive
Exercise of Predecessor warrants |  |  | — |  |  |  | Anti-dilutive |  |  | Anti-dilutive |  |  | Anti-dilutive
Conversion of Predecessor preferred stock |  |  | — |  |  |  | — |  |  | — |  |  | Anti-dilutive
Vesting of Predecessor restricted shares |  |  | — |  |  |  | Anti-dilutive |  |  | 284 |  |  | 813
Exercise of Successor Series A Warrants |  |  | Anti-dilutive |  |  |  | — |  |  | — |  |  | —
Exercise of Successor Series B Warrants |  |  | Anti-dilutive |  |  |  | — |  |  | — |  |  | —
Exercise of Successor Series C Warrants |  |  | Anti-dilutive |  |  |  | — |  |  | — |  |  | —
Weighted average diluted number of common shares outstanding |  |  | 16,204 |  |  |  | 158,925 |  |  | 157,295 |  |  | 133,576
Diluted net income (loss) per common share |  | $ | (0.65) |  |  | $ | (7.27) |  | $ | 0.29 |  | $ | 3.65

Common stock equivalents, including warrants, totaling 6.9 million shares for the period of October 2, 2019 through December 31, 2019 (Successor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, restricted shares and warrants totaling 14.1 million shares for the period of January 1, 2019 through October 1, 2019 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss.

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

Common stock equivalents, including stock options, restricted shares, warrants, and preferred stock totaling 17.1 million shares for the year ended December 31, 2017 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive.

On February 20, 2020 the Successor Company granted under the 2020 Plan stock options and restricted stock units to purchase or receive an aggregate of 1.3 million shares of common stock.

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16. ADDITIONAL FINANCIAL STATEMENT INFORMATION

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

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018
Accounts receivable, net: |  |  |  |  |  |  |
Oil, natural gas and natural gas liquids revenues |  | $ | 36,367 |  |  | $ | 26,432
Joint interest accounts |  |  | 10,145 |  |  |  | 7,369
Other |  |  | 1,992 |  |  |  | 1,917
|  | $ | 48,504 |  |  | $ | 35,718
Prepaids and other: |  |  |  |  |  |  |
Prepaids |  | $ | 2,093 |  |  | $ | 3,503
Income tax receivable |  |  | 1,250 |  |  |  | 1,250
Funds in escrow |  |  | 4,000 |  |  |  | —
Other |  |  | 36 |  |  |  | 35
|  | $ | 7,379 |  |  | $ | 4,788
Funds in escrow and other: |  |  |  |  |  |  |
Funds in escrow |  | $ | 580 |  |  | $ | 570
Other |  |  | 123 |  |  |  | 1,611
|  | $ | 703 |  |  | $ | 2,181
Accounts payable and accrued liabilities: |  |  |  |  |  |  |
Trade payables |  | $ | 36,038 |  |  | $ | 68,959
Accrued oil and natural gas capital costs |  |  | 22,781 |  |  |  | 41,461
Revenues and royalties payable |  |  | 25,457 |  |  |  | 20,526
Accrued interest expense |  |  | 604 |  |  |  | 16,971
Accrued employee compensation |  |  | 2,947 |  |  |  | 3,421
Accrued lease operating expenses |  |  | 9,230 |  |  |  | 6,292
Other |  |  | 276 |  |  |  | 218
|  | $ | 97,333 |  |  | $ | 157,848

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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

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

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

The proved reserves estimates reported herein for the years ended December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (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. Mike K. Norton. 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. Norton, a Licensed Professional Geoscientist in the State of Texas (No. 441), has been a practicing petroleum geoscience consultant at Netherland, Sewell since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Netherland, Sewell has reported to the Company that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are both proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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

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

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recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following tables illustrate changes in the Company’s estimated net proved developed and proved undeveloped reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor) are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $55.85 per barrel, $65.56 per barrel and $51.34 per barrel, respectively. The natural gas prices as of December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor) are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $2.578 per MMBtu, $3.100 per MMBtu and $2.976 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.

|  | Total Proved Reserves
|  |  |  |  |  | Natural Gas |  |
|  |  |  | Natural Gas |  | Liquids |  | Equivalent
|  | Oil (MBbls) |  | (MMcf) |  | (MBbls) |  | (MBoe)
Proved reserves, December 31, 2016 (Predecessor) |  | 119,600 |  | 80,238 |  | 15,641 |  | 148,614
Extensions and discoveries |  | 19,105 |  | 18,423 |  | 3,483 |  | 25,659
Purchase of minerals in place |  | 20,934 |  | 15,635 |  | 3,220 |  | 26,760
Production |  | (7,511) |  | (7,439) |  | (1,249) |  | (10,000)
Sale of minerals in place |  | (126,427) |  | (92,465) |  | (18,490) |  | (160,328)
Revision of previous estimates |  | 8,432 |  | 32,346 |  | 6,591 |  | 20,414
Proved reserves, December 31, 2017 (Predecessor) |  | 34,133 |  | 46,738 |  | 9,196 |  | 51,119
Extensions and discoveries |  | 31,104 |  | 68,772 |  | 10,602 |  | 53,168
Purchase of minerals in place |  | 2,201 |  | 4,770 |  | 669 |  | 3,665
Production |  | (3,558) |  | (4,607) |  | (749) |  | (5,075)
Sale of minerals in place |  | (14) |  | (20) |  | (4) |  | (21)
Revision of previous estimates |  | (13,212) |  | (10,904) |  | (2,614) |  | (17,644)
Proved reserves, December 31, 2018 (Predecessor |  | 50,654 |  | 104,749 |  | 17,100 |  | 85,212
Extensions and discoveries |  | 9,161 |  | 12,372 |  | 1,952 |  | 13,175
Production |  | (3,780) |  | (9,136) |  | (1,262) |  | (6,565)
Revision of previous estimates |  | (16,801) |  | (35,724) |  | (7,015) |  | (29,769)
Proved reserves, December 31, 2019 (Successor) |  | 39,234 |  | 72,261 |  | 10,775 |  | 62,053

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|  | Equivalent (Mboe)
|  | Proved |  | Proved |  |
|  | Developed |  | Undeveloped |  | Total Proved
|  | Reserves |  | Reserves |  | Reserves
Proved reserves, December 31, 2016 (Predecessor) |  | 85,908 |  | 62,706 |  | 148,614
Extensions and discoveries |  | 8,269 |  | 17,390 |  | 25,659
Purchase of minerals in place |  | 9,123 |  | 17,637 |  | 26,760
Production |  | (10,000) |  | — |  | (10,000)
Sale of minerals in place |  | (100,537) |  | (59,791) |  | (160,328)
Transfers |  | 7,432 |  | (7,432) |  | —
Revision of previous estimates |  | 15,823 |  | 4,591 |  | 20,414
Proved reserves, December 31, 2017 (Predecessor) |  | 16,018 |  | 35,101 |  | 51,119
Extensions and discoveries |  | 13,091 |  | 40,077 |  | 53,168
Purchase of minerals in place |  | 3,665 |  | — |  | 3,665
Production |  | (5,075) |  | — |  | (5,075)
Sale of minerals in place |  | (21) |  | — |  | (21)
Transfers |  | 11,964 |  | (11,964) |  | —
Revision of previous estimates |  | 227 |  | (17,871) |  | (17,644)
Proved reserves, December 31, 2018 (Predecessor) |  | 39,869 |  | 45,343 |  | 85,212
Extensions and discoveries |  | 2,813 |  | 10,362 |  | 13,175
Production |  | (6,565) |  | — |  | (6,565)
Transfers |  | 10,213 |  | (10,213) |  | —
Revision of previous estimates |  | (8,395) |  | (21,374) |  | (29,769)
Proved reserves, December 31, 2019 (Successor) |  | 37,935 |  | 24,118 |  | 62,053

|  | Proved Developed Reserves
|  |  |  |  |  | Natural Gas |  |
|  |  |  | Natural Gas |  | Liquids |  | Equivalent
|  | Oil (MBbls) |  | (MMcf) |  | (MBbls) |  | (MBoe)
December 31, 2019 (Successor) |  | 22,821 |  | 48,558 |  | 7,021 |  | 37,935
December 31, 2018 (Predecessor) |  | 24,672 |  | 44,743 |  | 7,740 |  | 39,869
December 31, 2017 (Predecessor) |  | 10,150 |  | 16,303 |  | 3,151 |  | 16,018

|  | Proved Undeveloped Reserves
|  |  |  |  |  | Natural Gas |  |
|  |  |  | Natural Gas |  | Liquids |  | Equivalent
|  | Oil (MBbls) |  | (MMcf) |  | (MBbls) |  | (MBoe)
December 31, 2019 (Successor) |  | 16,413 |  | 23,703 |  | 3,754 |  | 24,118
December 31, 2018 (Predecessor) |  | 25,982 |  | 60,006 |  | 9,360 |  | 45,343
December 31, 2017 (Predecessor) |  | 23,983 |  | 30,435 |  | 6,045 |  | 35,101

The Company’s proved reserves have been estimated using deterministic methods. At December 31, 2019 (Successor), total proved reserves were approximately 62.1 MMBoe, a 23.1 MMBoe net decrease over the previous year’s estimate of 85.2 MMBoe. The net decrease in total proved reserves was the result of net negatives revisions of 29.7 MMBoe and production of 6.6 MMBoe, partially offset by additions and extensions of 13.2 MMBoe. Negative revisions of 29.7 MMBoe primarily relate to changes in our development plans to focus on our most economic area, Monument Draw and due to the effect of lower prices.

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

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

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

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

During 2017 (Predecessor), net negative revisions of 69.9 MMBoe in proved developed reserves were the result of divestitures of 100.5 MMBoe and production of 10.0 MMBoe, partially offset by additions and extensions of 8.3 MMBoe, acquisitions of 9.1 MMBoe, development of 7.4 MMBoe (transferred from PUD), and net positive revisions of 15.8 MMBoe. Of the 8.3 MMBoe of extensions and discoveries in proved developed reserves, approximately 3.1 MMBoe are associated with infill drilling activity and 2.5 MMBoe are associated with drilling extensions in the Delaware Basin. The Company did not separately track infill drilling activities as a subset of additions to extensions and discoveries for the properties it disposed of during 2017. Net positive revisions of 15.8 MMBoe in proved developed reserves include 12.5 MMBoe in net positive performance revisions and 3.3 MMBoe in positive revisions due to increase in prices.

As of December 31, 2019 (Successor) all of the Company’s PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2019 (Successor), approximately $76.1 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

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

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

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reservoir characteristics in addition to significant quantities of economic EURs from individual producing wells. The Company relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves. Out of total proved undeveloped reserves of 24.1 MMBoe at December 31, 2019 (Successor), 4.9 MMBoe were associated with five gross PUD locations that were more than one offset location from a producing well.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

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

|  | Successor |  |  | Predecessor
|  | December 31, 2019 |  |  | December 31, 2018 |  | December 31, 2017
Evaluated oil and natural gas properties |  | $ | 420,609 |  |  | $ | 1,470,509 |  | $ | 877,316
Unevaluated oil and natural gas properties |  |  | 105,009 |  |  |  | 971,918 |  |  | 765,786
|  |  | 525,618 |  |  |  | 2,442,427 |  |  | 1,643,102
Accumulated depletion |  |  | (19,474) |  |  |  | (639,951) |  |  | (570,155)
|  | $ | 506,144 |  |  | $ | 1,802,476 |  | $ | 1,072,947

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

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

|  | Successor |  |  | Predecessor
|  | Period from |  |  | Period from |  |  |  |  |  |
|  | October 2, 2019 |  |  | January 1, 2019 |  |  |  |  |  |
|  | through |  |  | through |  | Years Ended December 31,
|  | December 31, 2019 |  |  | October 1, 2019 |  | 2018 |  | 2017
Property acquisition costs, proved |  | $ | — |  |  | $ | — |  | $ | 36,505 |  | $ | 219,308
Property acquisition costs, unproved |  |  | — |  |  |  | 2,809 |  |  | 297,537 |  |  | 794,239
Exploration and extension well costs |  |  | 9,209 |  |  |  | 89,389 |  |  | 293,115 |  |  | 183,798
Development costs |  |  | 15,839 |  |  |  | 60,275 |  |  | 181,987 |  |  | 143,323
Total costs |  | $ | 25,048 |  |  | $ | 152,473 |  | $ | 809,144 |  | $ | 1,340,668

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

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

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

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

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

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

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

At December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor), as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure is as follows:

|  | Years Ended December 31,
|  | 2019 |  | 2018 |  | 2017
|  | (In thousands)
Future cash inflows |  | $ | 2,257,083 |  | $ | 3,602,719 |  | $ | 2,033,110
Future production costs |  |  | (1,207,370) |  |  | (1,441,754) |  |  | (769,894)
Future development costs |  |  | (261,747) |  |  | (412,961) |  |  | (421,748)
Future income tax expense |  |  | (1,577) |  |  | (34,956) |  |  | (12,463)
Future net cash flows before 10% discount |  |  | 786,389 |  |  | 1,713,048 |  |  | 829,005
10% annual discount for estimated timing of cash flows |  |  | (377,514) |  |  | (859,481) |  |  | (492,972)
Standardized measure of discounted future net cash flows |  | $ | 408,875 |  | $ | 853,567 |  | $ | 336,033

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

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2019:

|  | Years Ended December 31,
|  | 2019 |  | 2018 |  | 2017
|  | (In thousands)
Beginning of year |  | $ | 853,567 |  | $ | 336,033 |  | $ | 803,517
Sale of oil and natural gas produced, net of production costs |  |  | (104,007) |  |  | (119,003) |  |  | (220,815)
Purchase of minerals in place |  |  | — |  |  | 36,600 |  |  | 222,658
Sales of minerals in place |  |  | — |  |  | (119) |  |  | (1,368,383)
Extensions and discoveries |  |  | 71,585 |  |  | 510,492 |  |  | 200,807
Changes in income taxes, net |  |  | 5,845 |  |  | (5,155) |  |  | (952)
Changes in prices and costs |  |  | (306,466) |  |  | (12,954) |  |  | 330,130
Previously estimated development costs incurred |  |  | 85,538 |  |  | 115,213 |  |  | 58,605
Net changes in future development costs |  |  | 26,742 |  |  | 23,909 |  |  | —
Revisions of previous quantities |  |  | (266,538) |  |  | (53,580) |  |  | 206,425
Accretion of discount |  |  | 85,968 |  |  | 33,699 |  |  | 62,379
Changes in production rates and other |  |  | (43,359) |  |  | (11,568) |  |  | 41,662
End of year |  | $ | 408,875 |  | $ | 853,567 |  | $ | 336,033

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table presents selected quarterly financial data derived from the Company’s unaudited consolidated interim financial statements. The following data is only a summary and should be read with the Company’s historical consolidated financial statements and related notes contained in this document (in thousands, except per share amounts).

|  | Predecessor |  |  | Successor
|  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  |  | Fourth Quarter
2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Total operating revenues |  | $ | 51,916 |  | $ | 56,378 |  | $ | 50,809 |  | $ | - |  |  | $ | 65,582
Income (loss) from operations |  |  | (304,656) |  |  | (693,690) |  |  | (64,436) |  |  | - |  |  |  | 10,805
Reorganization items, net |  |  | - |  |  | - |  |  | (1,758) |  |  | (115,366) |  |  |  | (3,298)
Net income (loss) |  |  | (336,559) |  |  | (640,844) |  |  | (63,284) |  |  | (115,366) |  |  |  | (10,460)
Net income (loss) available to common stockholders (1) |  |  | (336,559) |  |  | (640,844) |  |  | (63,284) |  |  | (115,366) |  |  |  | (10,460)
Net income (loss) per share of common stock: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (2.12) |  | $ | (4.03) |  | $ | (0.40) |  | $ | (0.71) |  |  | $ | (0.65)
Diluted |  | $ | (2.12) |  | $ | (4.03) |  | $ | (0.40) |  | $ | (0.71) |  |  | $ | (0.65)

|  | Predecessor
|  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter
2018 |  |  |  |  |  |  |  |  |  |  |  |
Total operating revenues |  | $ | 49,255 |  | $ | 55,415 |  | $ | 61,595 |  | $ | 60,344
Income (loss) from operations |  |  | (1,453) |  |  | 6,360 |  |  | (8,491) |  |  | 95,724
Net income (loss) |  |  | (2,598) |  |  | (16,274) |  |  | (81,837) |  |  | 146,668
Net income (loss) available to common stockholders (2) |  |  | (2,598) |  |  | (16,274) |  |  | (81,837) |  |  | 146,668
Net income (loss) per share of common stock: |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (0.02) |  | $ | (0.10) |  | $ | (0.52) |  | $ | 0.93
Diluted |  | $ | (0.02) |  | $ | (0.10) |  | $ | (0.52) |  | $ | 0.93

| (1) |  | The volatility in “Net income (loss) available to common stockholders” results primarily from i) the Company’s full cost ceiling impairments and associated income tax effects and ii) the Company’s reorganization and associated fresh-start accounting.

| (2) |  | The volatility in “Net income (loss) available to common stockholders” is substantially due to the $119.0 million gain on the sale of Water Assets. See footnotes for additional information.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a‑15(f) and 15d‑15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2019 (Successor) to provide

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reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Management has assessed, and our independent registered public accounting firm, Deloitte & Touche LLP, has audited, our internal control over financial reporting as of December 31, 2019 (Successor). The unqualified reports of management and Deloitte & Touche LLP thereon are included in Item 8. Consolidated Financial Statements and Supplementary Data of this Annual Report on Form 10‑K and are incorporated by reference herein.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting, as defined in Rules 13a‑15(f) and 15d‑15(f) of the Exchange Act, during the three months ended December 31, 2019 (Successor) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

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

ITEM 11. EXECUTIVE COMPENSATION

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

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

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

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

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2020 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

| (1) |  | Consolidated Financial Statements:

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

| (2) |  | Consolidated Financial Statements Schedules:

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

| (3) |  | Exhibits:

2.1 |  | Order of the Bankruptcy Court, dated September 24 2019, confirming the Joint Prepackaged Plan of Reorganization of Halcón Resources Corporation, et al, under Chapter 11 of the Bankruptcy Code, together with such Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8‑K filed September 26, 2019).
2.2 |  | Purchase and Sale Agreement dated January 18, 2017, by and between Halcón Energy Properties, Inc. and Samson Exploration, LLC (Incorporated by reference to Exhibit 2.2 of our Annual Report on Form 10‑K filed March 1, 2017).
2.3 |  | Agreement of Sale and Purchase dated January 24, 2017, by and among Halcón Energy Properties, Inc., Halcón Holdings, Inc., HK Energy, LLC, HK Oil & Gas, LLC, HRC Energy, LLC, The 7711 Corporation, Halcón Operating Co., Inc. and Halcón Field Services, LLC and Hawkwood Energy East Texas, LLC (Incorporated by reference to Exhibit 2.3 of our Annual Report on Form 10‑K filed March 1, 2017).
2.4 |  | Agreement of Sale and Purchase, dated as of July 10, 2017, by and among Halcón Energy Properties, Inc., Halcón Operating Co., Inc., HRC Operating, LLC, and HRC Energy, LLC, as sellers, Halcón Williston I, LLC and Halcón Williston II, LLC, as the companies, Bruin Williston Holdings, LLC, as purchaser, and Halcón Resources Corporation, as guarantor (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8‑K filed July 11, 2017).
2.5 |  | Agreement of Sale and Purchase, dated September 19, 2017, by and among Halcón Energy Properties, Inc., HRC Energy, LLC, Halcón Holdings, Inc. and Halcón Operating Co., Inc., collectively as seller, and Riverbend Oil and Gas VI, LLC, as purchaser (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10‑Q filed November 9, 2017).
2.6 |  | Purchase and Sale Agreement dated February 6, 2018, by and between Halcón Energy Properties, Inc. and SWEPI LP (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8‑K filed February 8, 2018).
2.7 |  | Asset Purchase Agreement, dated October 31, 2018, by and among Halcón Field Services, LLC, Halcón Operating Co., Inc., Halcón Energy Properties, Inc. and Water Bridge Texas Midstream LLC (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10‑Q filed November 8, 2018).
3.1 | * | Amended and Restated Certificate of Incorporation of Halcón Resources Corporation dated October 8, 2019, as amended by the Certificate of Amendment, dated January 21, 2020.

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3.2 |  | Seventh Amended and Restated Bylaws of Battalion Oil Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8‑K filed January 27, 2020).
4.1 | * | Description of Battalion Oil Corporation’s securities registered under Section 12 of the Exchange Act.
10.1 |  | Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, by and among Halcón Resources Corporation, Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed October 8, 2019).
10.1.1 |  | First Amendment to the Senior Secured Revolving Credit Agreement, dated as of November 21, 2019, by and among Halcón Resources Corporation, as borrower, Bank of Montreal, as administrative agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed November 27, 2019).
10.2 |  | Warrant Agreement, dated as of October 8, 2016, by and between Halcón Resources Corporation and Broadridge Corporate Issuer Solutions, Inc., as warrant agent (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed October 8, 2019).
10.3 |  | Registration Rights Agreement, dated as of October 8, 2019, by and among Halcón Resources Corporation and each of the parties thereto, as investors (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed October 8, 2019).
10.4 | † | Battalion Oil Corporation 2020 Long‑Term Incentive Plan, effective as of January 1, 2020 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8‑K filed January 31, 2020).
10.5 | *† | Employment Agreement between Richard H. Little and Battalion Oil Corporation effective as of January 28, 2020.
10.6 | *† | Employment Agreement between Ragan T. Altizer and Battalion Oil Corporation effective as of January 28, 2020.
10.7 | *† | Employment Agreement between Daniel P. Rohling and Battalion Oil Corporation effective as of January 28, 2020.
10.8 | † | Employment Agreement between Floyd C. Wilson and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8‑K filed June 5, 2012).
10.9 | † | Employment Agreement between Mark J. Mize and Halcón Resources Corporation dated June 1, 2012 (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8‑K filed June 5, 2012).
10.10 | † | Amended and Restated Employment Agreement between David S. Elkouri and Halcón Resources Corporation dated September 3, 2019 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8‑K filed September 27, 2019).
10.11 | † | Amended and Restated Employment Agreement between Jon Wright and Halcón Resources Corporation dated September 3, 2019 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8‑K filed September 27, 2019).
10.22 | † | Form of Nonqualified Stock Option Award Agreement (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed January 31, 2020).
10.23 | † | Form of Base Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed January 31, 2020).
10.24 | † | Form of Performance-Based Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed January 31, 2020).
10.25 | † | Form of M&A Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed January 31, 2020).
21.1* |  | List of Subsidiaries of Halcón Resources Corporation
23.1* |  | Consent of Deloitte & Touche LLP
23.2* |  | Consent of Netherland, Sewell & Associates, Inc.
31.1* |  | Sarbanes‑Oxley Section 302 certification of Principal Executive Officer
31.2* |  | Sarbanes‑Oxley Section 302 certification of Principal Financial Officer
32* |  | Sarbanes‑Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
99.1* |  | Report of Netherland, Sewell & Associates, Inc.

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101.INS* |  | XBRL Instance Document
101.SCH* |  | XBRL Taxonomy Extension Schema Document
101.CAL* |  | XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* |  | XBRL Taxonomy Extension Definition Document
101.LAB* |  | XBRL Taxonomy Extension Label Linkbase Document
101.PRE* |  | XBRL Taxonomy Extension Presentation Linkbase Document

*Attached hereto.

†Indicates management contract or compensatory plan or arrangement.

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

ITEM 16. FORM 10‑K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

| BATTALION OIL CORPORATION
Date: March 25, 2020 | By: | /s/ RICHARD H. LITTLE
|  | Richard H. Little
|  | Chief Executive Officer

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

Signature |  | Title |  | Date
/s/ RICHARD H. LITTLE Richard H. Little |  | Director and Chief Executive Officer |  | March 25, 2020
/s/ RAGAN T. ALTIZER Ragan T. Altizer |  | Executive Vice President, Chief Financial Officer and Treasurer |  | March 25, 2020
/s/ WILLIAM TRANSIER William Transier |  | Chairman of the Board |  | March 25, 2020
/s/ WILLIAM CARAPUCCI William Carapucci |  | Director |  | March 25, 2020
/s/ DAVID CHANG David Chang |  | Director |  | March 25, 2020
/s/ SCOTT GERMANN Scott Germann |  | Director |  | March 25, 2020
/s/ GREGORY HINDS Gregory Hinds |  | Director |  | March 25, 2020
/s/ ALLEN LI Allen Li |  | Director |  | March 25, 2020

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