What changed in this filing

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Item 1. Business

2022-03-07 compared with 2021-03-08 · 120 added, 123 removed, 327 unchanged (43% of the section changed)

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

Refer to Item 8.

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

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

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

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

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

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

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

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

At December 31, 2021, our estimated total proved oil and natural gas reserves, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

(Netherland, Sewell) using the Securities and Exchange Commission (SEC) prices for crude oil and natural gas, which are based on preceding 12-month first day of the month average crude oil spot prices of West Texas Intermediate (WTI) of $66.55 per Bbl and Henry Hub natural gas spot price of $3.60 per MMBtu, were approximately 95.9 MMBoe, consisting of 58.7 MMBbls of oil, 16.3 MMBbls of natural gas liquids and 125.0 Bcf of natural gas.

Approximately 44% of our estimated proved reserves were classified as proved developed as of December 31, 2021.

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

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

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

During the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), production averaged 20,293 Boe/d and 17,209 Boe/d, respectively, or 17,986 Boe/d combined.

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

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

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

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

Our total operating revenues for the year ended December 31, 2021 were approximately $285.2 million compared to total operating revenues for the year ended December 31, 2020 of approximately $148.3 million.

The increase in revenues is primarily attributable to an approximate $24.14 per Boe increase in average realized prices (excluding the effects of hedging arrangements).

Full year 2021 production averaged 16,241 Boe/d compared to average daily production of 16,858 Boe/d for 2020.

Average daily oil and natural gas production was impacted by the temporary shut-in of production amounting to approximately 300 Boe/d and 1,300 Boe/d for the year ended December 31, 2021 and 2020, respectively.

In February 2021, we temporarily shut-in production due to inclement weather.

In May and June 2020, we temporarily shut-in production in response to historically low commodity prices.

Current year production was also impacted by third-party processing curtailments and downtime resulting from facility upgrades and repairs.

In 2021, we drilled and cased 2.0 gross (2.0 net) operated wells, completed 6.0 gross (6.0 net) operated wells, and put online 6.0 gross (6.0 net) operated wells.

Recent Developments

Risk and Uncertainties

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

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

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

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

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

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 implementing various measures to ensure the continued operation of our business in a safe and secure manner.

In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural

gas and, together with a price war involving 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 continued for several months, particularly given concerns over the impacts of the economic downturn on demand.

As a consequence, beginning in March 2020, we realized lower revenue as a result of commodity price declines, resulting in us temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year.

Additionally in 2020, we incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of our reserves for ceiling test purposes.

During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices.

Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions.

However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors.

As a consequence, we are unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020.

Furthermore, the health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and critical functions remain concerns and 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.

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

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

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

Northern West Quito Assets Divestiture

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

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

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

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

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

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

Successor Senior Revolving Credit Facility

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

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

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

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

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

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.

Term Loan Credit Facility

On November 24, 2021, we and our wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into an Amended and Restated Senior Secured Credit Agreement (Term Loan Agreement) with Macquarie Bank Limited, as administrative agent, and certain other financial institutions party thereto, as lenders.

The Term Loan Agreement amends and restates in its entirety our Senior Credit Agreement as discussed below.

Pursuant to the Term Loan Agreement, the lenders have agreed to loan us (i) $200.0 million, which funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement;

(ii) up to $20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions;

and (iii) up to $15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to 18 months after November 24, 2021, subject to the satisfaction of certain conditions.

An additional $5.0 million is available for the issuance of letters of credit.

The maturity date of the Term Loan Agreement is November 24, 2025.

Until such maturity date, borrowings under the Term Loan Agreement bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00%.

Consolidated Financial Statements and Supplementary Data —Note 6, “Debt” for additional information on the Term Loan Agreement.

Senior Revolving Credit Facility

On November 24, 2021, our Senior Secured Revolving Credit Agreement (Senior Credit Agreement) was amended and restated in its entirety by the Term Loan Agreement.

Borrowings outstanding under the Senior Credit Agreement were repaid with proceeds from the Term Loan Agreement resulting in a charge of $0.1 million presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.

On September 24, 2021, we entered into the Fifth Amendment to Senior Secured Revolving Credit Agreement (the Fifth Amendment) which, among other things, modified the limits on swap agreements so as not to exceed, (i) from the period of the Fifth Amendment effective date through December 31, 2021, the percentage of the reasonably anticipated hydrocarbon production from proved developed producing reserves during such period hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date;

(ii) for the fiscal year ending December 31, 2022, the

greater of (a) the proved developed producing reserves during such fiscal year hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date and (b) 85% of the proved developed producing reserves during such fiscal year;

and (iii) for the fiscal years ending December 31, 2023, December 31, 2024 and December 31, 2025, swap agreements not to exceed 85%, 70% and 60% of the proved developed producing reserves, respectively, during each fiscal year.

On May 10, 2021, we entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $185.0 million effective June 1, 2021 and further reduced the borrowing base to $175.0 million effective September 1, 2021.

The Fourth Amendment also, among other things, (i) increased interest margins to 2.00% to 3.00% for ABR-based loans and 3.00% to 4.00% for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90% to 95%, (iii) provided for direct reductions in the borrowing base in the event of asset dispositions in excess of $1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $7.5 million or 3.5% of the then effective borrowing base.

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.

Effective August 13, 2021, the principal amount of our promissory note (the PPP Loan) under the Paycheck Protection Program of the Coronavirus Aid, Relief and Economic Security Act (the CARES Act) was reduced from $2.2 million to $0.2 million 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.”

We applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act.

We recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $2.1 million.

The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021.

Employee Retention Credit

The CARES Act included, among other things, provisions relating to refundable payroll tax credits (the Employee Retention Credit or ERC).

As provided for in the CARES Act and subsequent legislation which modified and extended the provisions included therein, the ERC allows for a refundable tax credit against certain employment taxes equal to 50% of the first $10,000 in qualified wages paid to each employee after March 12, 2020 and through December 31, 2020 and 70% of the first $10,000 in qualified wages paid to each employee, per calendar quarter, after December 31, 2020 through September 30, 2021.

During the year ended December 31, 2021, we determined that the qualifications for the Employee Retention Credit were met and filed the corresponding applications for the applicable 2020 and 2021 periods.

We recognized an approximate $0.7 million Employee Retention Credit during the year ended December 31, 2021, with approximately $0.5 million recorded to “General and administrative” and approximately $0.2 million recorded to “Lease operating” in the consolidated statements of operations.

2022 Capital Budget

We expect to spend approximately $130.0 million to $150.0 million on capital expenditures during 2022.

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.

Overall, we currently plan to drill 12 gross operated wells during the year, complete 9 to 13 gross operated wells, and bring 8 to 12 gross operated wells on production.

Our 2022 capital budget currently contemplates running one operated rig in the Delaware Basin during 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.

We expect to fund our budgeted 2022 capital expenditures with cash and cash equivalents on hand from the funding of the Term Loan Agreement and cash flows from operations.

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.

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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:

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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.

In addition to operational efficiencies, we continue to focus on cost-saving measures to reduce corporate administrative expenses.

● Maintain Financial Flexibility.

Our management team is focused on maintaining adequate liquidity while pursuing our near-term development plans.

We believe our internally-generated cash flows and the funding from our Term Loan Agreement will provide us with sufficient liquidity to execute our current capital program and strategy.

We have no material near-term debt maturities.

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Oil and Natural Gas Reserves

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

The proved reserves estimates reported herein for the years ended December 31, 2021, 2020 and 2019, 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 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;

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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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.

He has approximately 15 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.

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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).

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, 2021.

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

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

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.

WTI crude oil spot price of $66.55 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $3.60 per MMBtu, as adjusted by lease or field for energy content, transportation fees, and market differentials.

All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.

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

The following table presents certain proved reserve information as of December 31, 2021:

Proved Reserves (MBoe) (1)

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil.

This ratio is based on energy equivalency, not price equivalency.

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

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

(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency.

This is an energy content correlation and does not reflect the value or price relationship between the commodities.

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2021 and 2020.

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

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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.

We have working interests in 40,372 net acres in the Delaware Basin as of December 31, 2021 in Pecos, Reeves, Ward and Winkler Counties, Texas.

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

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

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

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

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

As of December 31, 2021, we had 95 operated wells producing in this area in addition to minor working interests in 13 non-operated wells.

Our average daily net production from this area for the year ended December 31, 2021 was 16,219 Boe/d.

As of December 31, 2021, estimated proved reserves for the Delaware Basin were approximately 95.8 MMBoe, of which approximately 44% were classified as proved developed and approximately 56% 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.

We have designed a risk management policy for the use of derivative instruments to provide initial protection against certain risks relating to our ongoing business operations, such as commodity price declines and price differentials between the NYMEX commodity price and the index price at the location where our production is sold.

Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production.

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

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

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

Our requirement, under our Term Loan Agreement, is to hedge approximately 50% to 85% of our anticipated oil and natural gas production, in varying percentages by year, and on a rolling basis for the next four years.

However, our decision on the 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 but remain consistent with the requirements in effect under our Term Loan Agreement.

Our future performance is subject to commodity price risks and our future cash flows from operations may be volatile.

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

As of December 31, 2021, we did not post collateral under any of our derivative contracts as they are secured under our Term Loan Agreement.

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

Quantitative and Qualitative Disclosures about Market Risk and Item 8.

Quantitative and Qualitative Disclosures about

Market Risk and Item 8.

Consolidated Financial Statements and Supplementary Data— Note 8 , “Derivative and Hedging Activities,” for additional information.

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These ownership interests generally take the form of working interests in oil and natural gas leases that have varying provisions.

The following table presents a summary of our acreage interests as of December 31, 2020 (Successor):

The following table presents a summary of our acreage interests as of December 31, 2021:

Developed Acreage

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Total Acreage

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

The table below reflects the percentage of our total net undeveloped acreage as of December 31, 2021 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.

2025 & beyond

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

Of the acreage with 2022 expiration dates, approximately one net acre relates 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.

At December 31, 2021, we had estimated proved reserves of approximately 95.9 MMBoe comprised of 58.7 MMBbls of crude oil, 16.3 MMBbls of natural gas liquids, and 125.0 Bcf of natural gas.

The following table sets forth these reserves:

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Equivalent (MBoe) (1)

(1) Natural gas reserves are converted to oil reserves using a ratio of six Mcf to one Bbl of oil.

This ratio is based on energy equivalency, not price equivalency.

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

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

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

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

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

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.

(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency.

This is an energy content correlation and does not reflect the value or price relationship between the commodities.

At December 31, 2021, total estimated proved reserves were approximately 95.9 MMBoe, a 32.5 MMBoe net increase from the previous year’s estimate of 63.4 MMBoe.

The net increase in total proved reserves was the result of additions and extensions of 26.5 MMBoe and positive revisions of 11.9 MMBoe due primarily to increases in SEC pricing, partially offset by production of 5.9 MMBoe.

At December 31, 2021, our estimated proved undeveloped (PUD) reserves were approximately 53.5 MMBoe, a 26.4 MMBoe net increase from the previous year’s estimate of 27.1 MMBoe.

The net increase in total PUD reserves was the result of additions and extensions of 26.5 MMBoe and positive revisions of 1.9 MMBoe due primarily to increases in SEC pricing, partially offset by development of 2.1 MMBoe.

As of December 31, 2021, all of our PUD reserves are planned to be developed within five years from the date they were initially recorded.

During 2021, approximately $37.6 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.

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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 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.

No other alternative methods or technologies were used to estimate

proved reserves.

Out of total PUD reserves of 53.5 MMBoe at December 31, 2021, 37.7 MMBoe were associated with 39 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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Consolidated Financial Statements and Supplementary Data —Note 5, “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):

Capitalized costs of our evaluated and unevaluated properties at December 31, 2021, 2020 and 2019 are summarized as follows (in thousands):

December 31, 2021

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January 1, 2019

December 31, 2020

Years Ended December 31,

December 31, 2019

October 1, 2019

December 31, 2018

Crude oil - MBbl

Delaware Basin

Natural gas - MMcf

Delaware Basin

Natural gas liquids - MBbl

Delaware Basin

Total MBoe (1)

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Gathering and other

(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.

Total average cost

(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency.

This is an energy content correlation and does not reflect the value or price relationship between the commodities.

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

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

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

In 2021, three individual purchasers of our production, Western Refining Inc., Sunoco Inc.

and Salt Creek Midstream, LLC, each accounted for more than 10% of total sales, collectively representing 73% of our total sales for the year.

In 2020, 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.

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

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

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

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

Seasonality of Business

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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.

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 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.

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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.

These persons may include the current or former owner or operator of the site 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.

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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.

Thus, new federal programs relating to climate change appear to be likely through at least 2024.

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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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.

Threatened and endangered species, migratory birds, and other natural resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and other natural resources.

These statutes include the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Water Act.

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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.

Where takings of or harm to species or damages to wetlands, habitat, or other 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

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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.

As of December 31, 2021, we had 58 full-time employees.

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

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Principal Office

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

As of December 31, 2021, we leased corporate office space in Houston, Texas at 3505 West Sam Houston Parkway North.

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”.

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.

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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