What changed in this filing

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Item 1. Business

2021-03-08 compared with 2020-03-25 · 164 added, 220 removed, 286 unchanged (57% of the section changed)

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.

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).

Certain prior year financial statements are not comparable to our current year financial statements due to the adoption of fresh-start accounting upon our emergence from chapter 11 bankruptcy on October 8, 2019.

References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019, the convenience date applied for fresh-start accounting.

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

Refer to Item 8.

Consolidated Financial Statements and Supplementary Data – Note 2, “Reorganization” and Note 3, “Fresh-start Accounting,” for further details.

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States.

During 2017 (Predecessor), we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota (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.

During 2017 (Predecessor), we acquired certain properties in the Delaware Basin and divested our assets located in the Williston Basin in North Dakota and in the El Halcón area of East Texas.

As a result, our properties and drilling activities are currently focused in the Delaware Basin, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

At December 31, 2020 (Successor), our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

(Netherland, Sewell) using the Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on 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.

(Netherland, Sewell) using the Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average prices of West Texas Intermediate (WTI) crude oil spot price of $39.54 per Bbl and Henry Hub natural gas spot price of $1.99 per MMBtu, were approximately 63.4 MMBoe, consisting of 38.2 MMBbls of oil, 12.1 MMBbls of natural gas liquids, and 78.5 Bcf of natural gas.

Approximately 57% of our estimated proved reserves were classified as proved developed as of December 31, 2020 (Successor).

We maintain operational control of 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.

We maintain operational control of 99.9% of our estimated proved reserves.

Our total operating revenues for the year ended December 31, 2020 (Successor) were approximately $148.3 million, compared to total operating revenues for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) of approximately $65.6 million and $159.1 million, respectively, or $224.7 million combined.

Full year 2020 (Successor) production averaged 16,858 Boe/d.

The decrease in total operating revenues and average daily production year over year was driven by our temporary shut-in of a portion of producing wells across all our operating areas in May and June 2020 as a consequence of low oil prices as well as average realized prices that were lower by approximately $10.25 per Boe.

The estimated production decrease associated with these temporary shut-ins was approximately 1,300 Boe/d for 2020 (Successor).

In December 2020 (Successor), we divested properties that produced approximately 600 Boe/d during the nine months ended September 30, 2020 (Successor).

In 2020 (Successor), we drilled and cased 4.0 gross (4.0 net) operated wells, completed 5.0 gross (4.3 net) operated wells, and put online 7.0 gross (6.3 net) operated wells.

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.

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;

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.

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.

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;

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.

Risk and Uncertainties

We are continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on our business, including how it has and may continue to impact our operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including reducing capital expenditures, temporarily shutting-in producing wells, and implementing various measures to ensure the continued operation of our business in a safe and secure manner.

COVID-19 and governmental actions to contain the pandemic have contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war between the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels.

Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices has continued and could continue for the foreseeable future, particularly given concerns over the impacts of the current economic downturn on demand.

We are unable to predict the ongoing effects that these events will have on our business and financial condition due to numerous uncertainties, including the severity and duration of the COVID-19 outbreak and the impacts that governmental or other actions taken to limit the extent and duration of the outbreak, in conjunction with economic conditions, will have on our business, demand for oil and natural gas, and oil and natural gas prices.

The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions cannot be predicted, nor can the impact on our customers, vendors and contractors.

Any material effect on these parties could adversely impact us.

These and other factors could affect the Company’s operations, earnings and cash flows and could cause our results to not be comparable to those of the same period in previous years.

For example, we realized lower revenue as a result of commodity price declines, which began in March 2020 (Successor).

In response to low commodity prices, we temporarily shut-in producing wells in May and June 2020 (Successor), which further contributed to lower revenues in the current year.

Additionally, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing used in the valuation of our reserves.

The results presented in this Form 10-K are not necessarily indicative of future operating results.

For further information regarding the actual and potential impacts of COVID-19 on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.

Northern West Quito Assets Divestiture

On December 18, 2020 (Successor), we sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total sales price of $26.3 million in cash, subject to customary post-closing adjustments as provided in the Purchase and Sale Agreement.

The effective date of the transaction was October 1, 2020 (Successor).

Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool with no gain or loss recorded.

We used the net proceeds from the sale to repay amounts outstanding under our Senior Credit Agreement and for general corporate purposes.

Estimated proved reserves associated with the North West Quito Assets were approximately 2 MMBoe, or approximately 3% of our year-end 2019 proved reserves.

The North West Quito Assets generated net production of approximately 600 Boe/d, or approximately 4% of our average daily production for the nine months ended September 30, 2020 (Successor).

Successor Senior Revolving Credit Facility

On 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

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.

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;

dividends and distributions;

sale or discount of receivables;

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;

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.

On October 29, 2020 (Successor), we entered into the Third Amendment to Senior Secured Revolving Credit Agreement and Limited Waiver (the Third Amendment).

The Third Amendment, among other things, set the borrowing base to $190.0 million as of November 1, 2020, which eliminated the final monthly reduction of $5.0 million required under the Second Amendment (discussed below).

The Third Amendment also reduced the amount available for issuance of letters of credit to $25.0 million and amended certain covenants including, but not limited to, covenants relating to increasing the minimum mortgaged total value of proved borrowing base properties from 85% to 90%.

Additionally, the Third Amendment provided for new covenants that, among other things, require us to enter into swap agreements representing not less than 65% of our reasonably anticipated projected production from proved reserves classified as developed producing reserves for a period from the Third Amendment effective date through at least December 31, 2022 and prohibit no more than $3.0 million of our uncontested accounts payable or accrued expenses, liabilities or other obligations from remaining outstanding for longer than 90 days.

Pursuant to the Third Amendment, the administrative agent and the lenders consented to a waiver of the Current Ratio (as defined in the Senior Credit Agreement) for the

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

On July 31, 2020 (Successor), we entered into the Limited Waiver to Senior Secured Revolving Credit Agreement in which, the lenders consented to waive maintenance of a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00 for the fiscal quarter ended June 30, 2020.

Our failure to comply with the Current Ratio for the three months ended June 30, 2020 (Successor) was primarily the result of our decision to shut in certain production due to low oil prices coupled with capital spending required to maintain certain of our oil and gas leasehold interests.

On April 30, 2020 (Successor), we entered into the Second Amendment to the Senior Credit Agreement (Second Amendment) which, among other things, (i) reduced the borrowing base to $200.0 million effective from April 30, 2020, which was then reduced by $5.0 million monthly starting September 1, 2020 until November 1, 2020, so that the borrowing base was scheduled to be $185.0 million on November 1, 2020, provided the borrowing base redetermination scheduled for November 1, 2020 occurred pursuant to the terms of the Senior Credit Agreement, (ii) increased interest margins to 1.50% to 2.50% for ABR-based loans and 2.50% to 3.50% for Eurodollar-based loans, (iii) provided that should our Consolidated Cash Balance (as defined pursuant to the Second Amendment) exceed $10.0 million, such amounts shall be used to prepay any borrowings under the Senior Credit Agreement and thereafter, to the extent of any uncollateralized letters of credit exposure, shall be cash collateralized in accordance with the Senior Credit Agreement and (iv) allowed for a replacement benchmark rate to the London Interbank Offered Rate (which may include SOFR, Compounded SOFR or Term SOFR).

The Second Amendment also added provisions related to a loan incurred by us under the Paycheck Protection Program of the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act).

We used, and the Second Amendment required us to use, the loan proceeds for CARES Forgivable Uses under the CARES Act.

Additionally, the Second Amendment waived, for the fiscal quarter ended June 30, 2020, that we comply with the requirement under the Senior Credit Agreement that we unwind certain swap agreements for which settlement payments were calculated in such fiscal quarter to exceed 100% of actual production.

Paycheck Protection Program Loan

On April 16, 2020 (Successor), we entered into a promissory note (the PPP Loan) for a principal amount of approximately $2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S.

Small Business Administration (SBA).

Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs.

The PPP Loan bears interest at a rate of 1.0% per annum and, if not forgiven, has a maturity date of April 16, 2022.

As long as we make a timely application of forgiveness to the SBA, we are not required to make any payments under the PPP Loan until the forgiveness amount is communicated to us by the SBA.

Under the terms of the CARES Act, we can apply for and be granted forgiveness for all or a portion of the PPP Loan.

Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds in accordance with the terms of the CARES Act during the covered period after loan origination and the maintenance or achievement of certain employee levels.

We believe we are eligible for, and intend to pursue, forgiveness of the PPP Loan in accordance with the requirements and limitations under the CARES Act;

however, no assurance can be provided that forgiveness of any portion of the PPP Loan will be obtained.

Acid Gas Injection Well Permits

During the year ended December 31, 2020 (Successor), we received permits from the Texas Railroad Commission and the Texas Commission on Environmental Quality to construct and operate an acid gas injection well (AGI) by converting an existing producing gas well.

AGI can provide a more cost effective alternative to sour gas treating.

We are currently evaluating options for development of an AGI facility, including, but not limited to, divestiture of the assets with an associated third party treating arrangement for our sour gas production.

Listing of our Common Stock on NYSE American

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

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

2021 Capital Budget

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.

We expect to spend approximately $40.0 million to $50.0 million on capital expenditures during 2021.

Overall, we currently plan to drill two gross operated wells during the year, complete six gross operated wells, and bring six gross operated wells on production.

Our 2021 capital budget currently contemplates running one operated rig in the Delaware Basin at the beginning of the year.

We continuously monitor changes in market conditions and adapt our operational plans as necessary in order to maintain financial flexibility, preserve core acreage and meet contractual obligations, and therefore our capital budget is subject to change.

We expect to fund our budgeted 2021 capital expenditures with cash and cash equivalents on hand, cash flows from operations and, if necessary, borrowings under our Senior Credit Agreement.

In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production.

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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 have no material near-term debt maturities.

We also employ a hedging program to reduce the variability of our cash flows used to support our capital spending.

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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.

We believe our management team’s geologic and engineering expertise, particularly in the Permian Basin, provides a competitive advantage in the identification of acquisition targets and evaluation of resource potential.

Oil and Natural Gas Reserves

The proved reserves estimates reported herein for the years ended December 31, 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.

The proved reserves estimates reported herein for the years ended December 31, 2020 (Successor), 2019 (Successor) and 2018 (Predecessor) have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.

Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.

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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.

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.

Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No.

2364), has been practicing consulting petroleum geoscience at Netherland, Sewell since 2008 and has over 11 years of prior industry experience.

He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology.

Netherland, Sewell has reported to us that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers;

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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) .”

Consolidated Financial Statements and Supplementary Data —“ Supplemental Oil and Gas Information (Unaudited) .”

Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2020 (Successor).

Average prices for the 12-month period were as follows:

WTI crude oil spot price of $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.

WTI crude oil spot price of $39.54 per Bbl, adjusted by lease or field for quality, transportation fees, and market

differentials and a Henry Hub natural gas spot price of $1.99 per MMBtu, 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.

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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).

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2020 and 2019 (Successor).

Shut-in wells currently not capable of production are excluded from the well information below.

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Oil and Natural Gas Production

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.

Core Resource Play—Delaware Basin

We have working interests in 41,676 net acres in the Delaware Basin as of December 31, 2020 (Successor) in Pecos, Reeves, Ward and Winkler Counties, Texas.

This core resource play is characterized by high oil and liquids-rich natural gas content in thick, continuous sections of source rock that can provide repeatable drilling opportunities and significant initial production rates.

Our primary targets in this area are the Wolfcamp and Bone Spring formations.

As of December 31, 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, 2020 (Successor), we had 113 operated wells producing in this area in addition to minor working interests in 8 non-operated wells.

Our average daily net production from this area for the year ended December 31, 2020 (Successor) was 16,790 Boe/d.

As of December 31, 2020 (Successor), estimated proved reserves for the Delaware Basin were approximately 63.3 MMBoe, of which approximately 57% were classified as proved developed and approximately 43% as proved undeveloped.

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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 objective generally is to hedge 65-85% of our anticipated oil and natural gas production for up to 30 months.

However, our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions, provided, however, that under our Senior Credit Agreement we are contractually obligated to hedge no less than 65% of our anticipated production under swap contracts through at least December 31, 2022.

Our hedge policies and objectives change as our operational profile changes.

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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.

As of December 31, 2020 (Successor), we did not post collateral under any of our derivative contracts as they are secured under our Senior Credit Agreement.

We will continue to evaluate the benefit of employing derivatives in the future.

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.

Consolidated Financial Statements and Supplementary Data— Note 10 , “Derivative and Hedging Activities,” for additional information.

Oil and Natural Gas Operations

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2024 & beyond

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.

Of the acreage with 2021 and 2022 expiration dates, approximately 450 and zero net acres, respectively, relate to our core area of operations.

We continually review our near-term lease expirations to preserve acreage in our core area of operations, either through our drilling program or through lease extensions or renewals, if necessary.

We have no current plans to drill on acreage in areas outside of our core area of operations.

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

The following table sets forth, at December 31, 2019 (Successor), these reserves:

The following table sets forth these reserves:

Natural Gas Liquids (MBbls)

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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.

At December 31, 2020 (Successor), total estimated proved reserves were approximately 63.4 MMBoe, a 1.3 MMBoe net increase from the previous year’s estimate of 62.1 MMBoe.

The net increase in total proved reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by production of 6.2 MMBoe, sales of 2.0 MMBoe, and negative revisions of 2.9 MMBoe due primarily to decreases in SEC pricing.

At December 31, 2020 (Successor), our estimated proved undeveloped (PUD) reserves were approximately 27.1 MMBoe, a 3.0 MMBoe net increase from the previous year’s estimate of 24.1 MMBoe.

The net increase in total PUD reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by development of 6.5 MMBoe and negative revisions of 2.8 MMBoe due primarily to decreases in SEC pricing.

As of December 31, 2020 (Successor), all of our PUD reserves are planned to be developed within five years from the date they were initially recorded.

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We relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves.

No other alternative methods or technologies were used to estimate

proved reserves.

Out of total 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.

No other alternative methods or technologies were used to estimate proved reserves.

Out of total PUD reserves of 27.1 MMBoe at December 31, 2020 (Successor), 13.7 MMBoe were associated with 15 gross PUD locations that were more than one offset location from a producing well.

The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No.

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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.

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.

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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):

Consolidated Financial Statements and Supplementary Data —Note 7, “Oil and Natural Gas Properties.”

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

December 31, 2020

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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:

October 2, 2019

January 1, 2019

Years Ended December 31,

December 31, 2020

December 31, 2019

October 1, 2019

December 31, 2018

Crude oil - MBbl

Bakken / Three Forks

Natural gas - MMcf

Bakken / Three Forks

Natural gas liquids - MBbl

Bakken / Three Forks

Total MBoe (1)

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The price for a barrel of oil equivalent for natural gas is substantially lower than the price for a barrel of oil.

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.

(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

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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.

The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers, transporters and take-away capacity for the oil and natural gas we produce and hiring and retaining key employees.

There is also competition between oil and natural gas producers and other industries producing energy and fuel.

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Historically, we have not experienced any significant losses from uncollectible accounts.

In 2020 (Successor), two individual purchasers of our production, Western Refining Inc.

and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 57% of our total sales for the year.

For the combined periods of October 2, 2019 through December 31, 2019 (Successor), and January 1, 2019 through October 1, 2019 (Predecessor), two individual purchasers of our production, Western Refining Inc.

and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 80% of our total sales for the period.

In 2018 (Predecessor), two individual purchasers of our production, 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.

In 2018 (Predecessor), two individual purchasers of our production, Western Refining Inc.

and Sunoco, Inc., each accounted for more than 10% of total sales, collectively representing 77% of our total sales for the year.

Seasonality of Business

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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.

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 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.

Periodically, however, there are proposals to reclassify oil and gas wastes as hazardous wastes or to subject them to enhanced solid waste regulation.

If such proposals were to be enacted, they could have a significant impact on our operating costs and on those of all the industry in general.

In the ordinary course of our operations, moreover 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.

In the ordinary course of our operations, moreover, we do handle materials that may be subject to extensive existing RCRA regulations or that may be classified as hazardous substances under CERCLA.

From time to time, releases of those materials have occurred at locations we own or at which we have operations.

Under CERCLA, RCRA and analogous state laws, we have been and may be required to remove or remediate such materials.

Water Discharges

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Hydraulic Fracturing

Our completion operations are subject to regulation, which may increase in the short‑ or long‑term.

Our completion operations are subject to regulations that may become more stringent in either the short- or long-term.

In particular, the well completion technique known as hydraulic fracturing, which is used to stimulate production of oil and natural gas, has come under increased scrutiny by the environmental community, and many local, state and federal regulators.

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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.

Although the EPA later made technical amendments to reduce the regulatory burden of the 2012 and 2016 rules, compliance has imposed additional requirements and costs on our operations.

In October 2015, the EPA announced that it was lowering the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion.

Implementation 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.

Implementation has been ongoing and has resulted in expansion of ozone nonattainment areas across the United States, including areas in which we operate.

Oil and natural gas operations in ozone nonattainment areas could be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

Climate Change

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere.

In response, governments increasingly have been adopting domestic and international climate change regulations that require reporting and reductions of the emission of such greenhouse gases.

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

At the federal level, the 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.

At the federal level, the Obama Administration took a variety of steps to address climate change.

For example, the EPA issued regulations requiring us and other companies to annually report certain greenhouse gas emissions from oil and natural gas facilities.

Beyond its measuring and reporting rules, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations.

The finding served as the first step in issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

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

The Trump Administration 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.

The Trump Administration tried to roll back many of the Obama-era climate change policies and rules.

But shortly after his inauguration, President Biden accepted the Paris Agreement on behalf of the United States, declared climate considerations an essential part of the United States’ foreign policy, issued a moratorium on new oil and gas leases on federal lands, and directed federal agencies to incorporate climate change considerations in their operations.

Thus, new federal programs relating to climate change appear to be likely over at least the next four years.

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

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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

Human Capital

At Battalion, our success is delivered through our highly capable and diverse workforce.

Our team is comprised of individuals with extensive technical, industry and other professional experience.

By recruiting, hiring and retaining an experienced and diverse team, we are able to leverage years of experience, new ideas and problem solving in a collaborative environment.

As of December 31, 2020 (Successor), we had 60 full-time employees.

We hire independent contractors on an as needed basis.

We also engage the services of independent contractors and consultants along with certain professional service firms to support our work in specific areas.

We have no collective bargaining agreements with our employees.

We believe that we have good relations with our employees.

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

Driving and Supporting a Safety First Culture

The safety of our employees, contractors and the communities in which we operate is one of our most critical responsibilities.

We believe that driving a safety culture requires daily prioritization and includes a multi-faceted approach to provide our employees with the tools, support, education and incentives to operate safely.

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

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

● Policies and procedures implemented to support a safe working environment

● Environmental and safety metrics measuring performance linked to compensation

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

COVID-19 Response

In response to the COVID-19 pandemic, we implemented changes to ensure the health and safety of our employees and the communities where we operate.

We complied with the guidelines published by the Centers for Disease Control or mandated by local authorities.

We implemented work from home arrangements for our staff employees and additional safety measures for those continuing critical on-site work in the field including social distancing, masks, testing, self-reporting and procedures for those testing positive.

Compensation and Benefits

We have designed our compensation program to attract and retain talented employees with the requisite knowledge and experience.

We offer market-competitive compensation programs, as well as strong health and welfare benefits along with a competitive 401(k) program.

We have designed paid time off policies to allow our employees time off for family and other priorities.

We have operational and financial metrics tied to our short-term incentives that align with our business strategy and the interests of our stockholders.

Diversity and Inclusion

We believe all employees should be treated fairly and valued in our organization.

Diversity of thoughts and experiences allows us to identify the best solutions within our company.

All Battalion employees must act in accordance with our Employee Handbook, which is inclusive of our Code of Conduct.

The Employee Handbook covers various topics including, among others, policies prohibiting harassment, discrimination and retaliation and policies covering workplace anti-violence, cybersecurity, confidential information and conduct.

On an annual basis, employees are required to acknowledge and agree to abide by these policies.

Principal Office

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

Access to Company Reports

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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”.

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business