What changed in this filing

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Item 1. Business

2023-03-30 compared with 2022-03-07 · 141 added, 231 removed, 216 unchanged (63% 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.

Unless the context otherwise requires, all references in this report to “Battalion,”, “the Company”, “our,” “us,” and “we” refer to Battalion Oil Corporation and its subsidiaries, as a common entity.

Battalion is the successor reporting company to Halcón Resources Corporation (Halcón).

On January 21, 2020, we filed a Certificate of Amendment to our Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of our corporate name from Halcón Resources Corporation to Battalion Oil Corporation.

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

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

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

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, 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, 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.

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets currently in the Delaware Basin in the United States, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

Our working interests in 40,375 net acres in the Delaware Basin as of December 31, 2022 are in Pecos, Reeves, Ward and Winkler Counties, Texas.

This 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, 2022, we had 103 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, 2022 was 15,438 Boe/d.

At December 31, 2022, our estimated total proved oil and natural gas reserves were approximately 92.0 MMBoe, consisting of 50.0 MMBbls of oil, 18.1 MMBbls of natural gas liquids and 143.7 Bcf of natural gas, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

(Netherland, Sewell).

Reserves were prepared using a crude oil price of West Texas Intermediate (WTI) of $94.14 per Bbl and a Henry Hub natural gas price of $6.36 per MMBtu, based on the preceding 12-month first day of the month average spot prices as required by the Securities and Exchange Commission (SEC).

Approximately 50% of our estimated proved reserves were classified as proved developed as of December 31, 2022.

We maintain operational control of 99.4% of our estimated proved reserves.

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 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 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.

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

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).

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 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 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.

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

Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production.

The amount we realize for our production depends predominately upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors.

Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Business Strategy

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We intend to drill and develop our multi-zone resource play to maximize value and resource potential.

Our near-term development plans are focused on production growth and acreage preservation in our liquids-rich Monument Draw area.

Our near-term development plans are focused on acreage preservation primarily in our liquids-rich Monument Draw area, maintaining production levels, and developing through the drilling and completion of new wells.

● Enhance Returns Through Continued Improvements in Operational and Cost Efficiencies.

We are the operator for the majority of our acreage, which gives us control over the timing of capital expenditures, execution and costs.

We are the operator for the majority of our acreage, which gives us control, to some extent, over the timing of capital expenditures, execution and costs.

It also allows us to adjust our capital spending based on drilling results and the economic environment.

As operator, we are able to evaluate industry drilling results and implement improved operating practices that may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital.

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

● Maintain Financial Flexibility.

We continue to focus on cost-saving measures including reducing corporate administrative expenses and pursuing operational efficiencies.

● Maintain Adequate Liquidity.

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.

We believe our internally-generated cash flows from operations, cash on hand, and recently completed preferred equity funding in March 2023 as further described below will provide us with sufficient liquidity to execute our capital and operating program over the next twelve months, address near-term debt maturities of approximately $35.0 million in 2023, and maintain compliance with our debt covenants.

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

As of December 31, 2022, we have no additional borrowing capacity under our current Amended Term Loan, and as such, we will continue to pursue additional sources of liquidity and cost-saving opportunities further described in Item 7, Management’s Discussion and Analysis, “Capital Resources and Liquidity”.

● Attain Growth Through Strategic Business Combinations.

We intend to pursue merger and acquisition opportunities to meet our strategic and financial targets, including the maintenance of a conservative leverage position.

Selective business combinations provide opportunities to acquire high quality assets complementary to our core acreage, expand our drilling inventory and gain operational scale.

From time to time, we may pursue merger and acquisition opportunities to meet our strategic and financial targets, including the maintenance of a conservative leverage position.

Selective business combinations provide opportunities to acquire high quality assets complementary to our acreage, expand our drilling inventory and gain operational scale.

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

Oil and Natural Gas Reserves

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

Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves reports incorporated herein are Mr.

Little and Mr.

Little, a Licensed Professional Engineer in the State of Texas (No.

117966), has been practicing consulting petroleum engineering at Netherland, Sewell since 2011 and has over nine years of prior industry experience.

He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from University of Houston in 2007 with a Master of Business Administration Degree.

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

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

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

Netherland, Sewell has reported to us that both technical principals meet or exceed the education, training, and experience

requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers;

they are both proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our board of directors has established a reserves committee composed of independent directors with experience in energy company reserve evaluations.

Our independent engineering firm reports jointly to the reserves committee and to our Executive Vice President and Chief Operating Officer.

The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to our board of directors as to whether to approve the report prepared by our independent engineering firm.

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 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.

Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.

The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

As a result, estimates of different engineers may vary significantly.

In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate.

Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based.

Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

For additional information regarding estimates of proved reserves, the preparation of such estimates by Netherland, Sewell and other information about our oil and natural gas reserves, see Item 8.

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

Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2021.

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

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, 2021:

Proved Reserves (MBoe) (1)

(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.

Years Ended December 31,

Oil and Natural Gas Production

Core Resource Play—Delaware Basin

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, 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.

Our ability to achieve our Business Strategy is subject to numerous risks and uncertainties, many of which are beyond our control.

Additional information regarding our risks can be found in Item 1A.

Risk Factors.

Recent Developments

● Preferred Stock Equity Issuance.

On March 28, 2023, we sold, in a private placement, an aggregate of 25,000 shares of Series A Convertible Preferred Stock (the “preferred stock”) to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing shareholders and received $24.4 million in proceeds.

Holders will have no voting rights with respect to the shares of preferred stock and will receive annual dividends, paid either in cash at a fixed rate of 14.5% annually or accrued (“PIK accrual”) at a fixed rate of 16.0% annually at the option of the Company.

Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends.

PIK dividends will be cumulative, compound and accrue quarterly in arrears and will be added to the Liquidation Preference.

For a further discussion of the redemption and conversion provisions associated with the preferred stock, refer to Item 7.

Management’s Discussion and Analysis, “Capital Resources and Liquidity” and Item 9B.

Other Information.

● H 2 S Treating Joint Venture.

In May 2022, we entered into a joint venture agreement with Caracara Services, LLC (“Caracara”) to develop a strategic acid gas treatment and carbon sequestration facility (the “Facility”) in Winkler County, Texas.

The joint venture, operating as Brazos Amine Treater, LLC (“BAT”), has also entered into a Gas Treating Agreement (“GTA”) with us for gas production from our Monument Draw area.

In exchange for contributing to the joint venture a wellbore with an approved permit for the injection of acid gas and surface land , we retained a 5% equity interest in BAT, an unconsolidated subsidiary.

We expect the AGI facility will be mechanically complete in early April 2023 and in service in the second quarter of 2023;

however, various operational and other risk factors, some of which are beyond our control, could impact the timing of these estimates.

For further details on the joint venture arrangement, see Item 7.

Management’s Discussion and Analysis on Financial Condition-“Recent Developments ”.

Risk Management

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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 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.

Our requirement, under our Amended Credit Agreement (Amended 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 hedge policies and objectives change as our operational profile changes but remain consistent with the requirements in effect under our Amended 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, 2021, we did not post collateral under any of our derivative contracts as they are secured under our Term Loan Agreement.

As of December 31, 2022, we did not post collateral under any of our derivative contracts as they are secured under our Amended 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 7 , “Derivative and Hedging Activities,” for additional information.

Oil and Natural Gas Operations

Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties.

Generally, our oil and natural gas leases remain in force as long as production in paying quantities is maintained.

Leases on undeveloped oil and natural gas properties are typically for a primary term of three to five years within which we are generally required to develop the property or the lease will expire.

In some cases, the primary term of leases on our undeveloped properties can be extended by option payments;

the amount of any payments and time extended vary by lease.

The table below sets forth the results of our drilling activities for the periods indicated:

Years Ended December 31,

Exploratory Wells:

Productive (1)

Total Exploratory

Extension Wells:

Productive (1)

Total Extension

Development Wells:

Productive (1)

Total Development

Productive (1)

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

We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below.

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

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

Developed Acreage

Undeveloped Acreage

Total Acreage

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 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.

Oil and Natural Gas Reserves

The proved reserves estimates reported herein for the years ended December 31, 2022, 2021 and 2020, have been independently evaluated by Netherland, Sewell, our independent reserve engineering firm.

Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in their reserves reports incorporated herein each have over 20 years of industry experience.

Each 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 and are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our board of directors has established a reserves committee composed of independent directors with experience in energy company reserve evaluations.

Our independent engineering firm reports jointly to the reserves committee and to our Director of Corporate Development and Reserves.

Our Director of Corporate Development and Reserves is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell.

He has approximately 13 years of oil and gas operations experience and has earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, an MBA from Rice University and is an active member of the Society of Petroleum Engineers.

The reserves information in this Annual Report on Form 10-K represents only estimates.

Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.

The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate.

Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based.

Except to the extent we acquire additional properties

containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

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, 2022.

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

WTI crude oil spot price of $94.14 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $6.36 per MMBtu, 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, 2022 (dollars in thousands):

Proved Reserves (MBoe) (1)

Discounted Future Income Taxes

Standardized measure of discounted future net cash flows

(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) PV-10 represents the discounted future net cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%.

PV-10 of our total year-end proved reserves is considered a non-U.S.

GAAP financial measure as defined by the SEC.

We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure.

We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies.

Refer to the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.

At December 31, 2022, we had estimated proved reserves of approximately 92.0 MMBoe comprised of 50.0 MMBbls of crude oil, 18.1 MMBbls of natural gas liquids, and 143.7 Bcf of natural gas.

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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.

At December 31, 2022, total estimated proved reserves were approximately 92.0 MMBoe, a 3.9 MMBoe net decrease from the previous year’s estimate of 95.9 MMBoe.

Proved developed reserves of 46.3 MMBoe increased approximately 3.9 MMBoe from December 31, 2021 as a result of PUD reserve development of 8.3 MMBoe and positive revisions of 1.2 MMBoe, offset by production of 5.6 MMBoe.

Proved undeveloped (PUD) reserves of 45.7 MMBoe decreased approximately 7.8 MMBoe from December 31, 2021 as the result of the transfer of 8.3 MMBoe to proved developed producing reserves and downward revisions of 6.4 MMBoe due primarily to increased capital and

operating costs , offset by extensions of 7.0 MMBoe primarily associated with infill drilling activity.

All of our PUD reserves are planned to be developed within five years from the date they were initially recorded.

During 2022, approximately $119.8 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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These technologies include seismic data, wire line openhole log data, core data, log cross-sections, performance data, and statistical analysis.

In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells.

In such areas, this data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic estimated ultimate recoveries from individual producing wells.

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

No other alternative methods or technologies were used to estimate

proved reserves.

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

Out of total PUD reserves of 45.7 MMBoe at December 31, 2022, 28.1 MMBoe were associated with 33 gross PUD locations that were more than one offset location from a producing well.

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33-8995, Modernization of Oil and Gas Reporting .

For additional information on our oil and natural gas reserves, including a table detailing the changes by year of our proved reserves, see Item 8.

Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).” We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations.

Accordingly, all costs incurred in the acquisition, exploration, and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, direct internal costs and annual lease rentals are capitalized.

All general and administrative corporate costs unrelated to drilling activities are expensed as incurred.

Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves.

The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test.

See further discussion in Item 8.

For additional information on our estimates of oil and natural gas reserves, the preparation of such estimates by Netherland, Sewell and other information about 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 —Note 4, “Oil and Natural Gas Properties.”

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

December 31, 2021

December 31, 2020

December 31, 2019

Oil and natural gas properties (full cost method):

Gross oil and natural gas properties

Less - accumulated depletion

Net oil and natural gas properties

Wells and Acreage

Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties.

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2022 and 2021.

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

Years Ended December 31,

The table below sets forth the results of our drilling activities for the periods indicated:

Years Ended December 31,

Development Wells:

Productive (1)

Total Development

Productive (1)

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

We had no exploratory or extension wells drilled for the year ended December 31, 2022 or 2021.

We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below.

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

The following table presents a summary of our acreage interests as of December 31, 2022:

Developed Acreage

Undeveloped Acreage

Total Acreage

Generally, our oil and natural gas leases remain in force as long as production in paying quantities is maintained.

Leases on our undeveloped oil and natural gas acreage are either categorized as “held by production” or perpetuated by continuous development clauses contained in our leases or tolling agreements.

Of our 9,696 net undeveloped acres at December 31, 2022, approximately 6,004 acres are subject to continuous development clauses and 3,692 acres are “held by production.” We continually review our acreage subject to these clauses or agreements when determining our drilling program.

Production Volumes, Sales Prices, and Average Costs

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

October 2, 2019

January 1, 2019

Years Ended December 31,

December 31, 2019

October 1, 2019

Crude oil - MBbl

Delaware Basin

Crude oil - MBbls

Natural gas - MMcf

Delaware Basin

Natural gas liquids - MBbl

Delaware Basin

Natural gas liquids - MBbls

Total MBoe (1)

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Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and the states in which our properties are located.

It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.

It is not possible to predict the nature

of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.

Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

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

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

In 2022, three individual purchasers of our productions, Western Refining Company L.P., Sunoco Inc.

and Targa Resources Inc., each accounted for more than 10% of total sales, collectively representing 82% of our total sales for the year.

In 2021, three individual purchasers of our production, Western Refining Company L.P., 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, 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.

Seasonality of Business

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There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities.

Oil and natural gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other events may cause accidental releases of toxic or hazardous materials, such as hydrogen sulfide, petroleum liquids, or drilling fluids into the environment, or cause significant injury to persons or property.

Oil and natural gas operations also involve the risk that well blowouts, fires, equipment failure, human error and other events may cause accidental releases of toxic or hazardous materials, such as hydrogen sulfide, petroleum liquids, or drilling fluids into the environment, or cause significant injury to persons or property.

In such event, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties.

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These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties.

In this regard, some states allow the forced pooling or integration of land and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of land and leases.

In areas where pooling is primarily or exclusively voluntary, it may be difficult to form spacing units and therefore difficult to develop a project if the operator owns less than 100% of the leasehold.

In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose 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.

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.

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Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities.

In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

In addition, laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.

Beyond existing requirements, new programs and changes in existing programs may address various aspects of our business, including naturally occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material.

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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 site 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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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.

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.

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waters, we could be liable under the Oil Pollution Act for cleanup costs, damages and economic losses.

Our oil and natural gas production also generates salt water, which we dispose of by underground injection.

Our oil and natural gas production also generates salt water, which is disposed of by underground injection.

The federal Safe Drinking Water Act (SDWA), the Underground Injection Control (UIC) regulations promulgated under the SDWA, and related state programs regulate the drilling and operation of salt water disposal wells.

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The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through permitting programs and the imposition of other requirements.

In addition, the EPA has developed and may continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas production.

In addition, the EPA has developed and may continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources, including oil and natural gas

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

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

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

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

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, but is reconsidering whether an even stricter standard is warranted.

Implementation of the 2015 standard 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.

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Internationally, the United Nations Framework Convention on Climate Change, the Kyoto Protocol and the Paris Agreement address greenhouse gas emissions, and several countries, including those comprising the European Union, have established greenhouse gas regulatory systems.

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

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, product bans, greenhouse gas cap and trade programs or incentives for renewable energy generation, while others have considered adopting such greenhouse gas programs.

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

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

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

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 (later vacated) for reducing venting and flaring on public lands.

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

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

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

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, limited new oil and gas leases on federal lands, and directed federal agencies to incorporate climate change considerations in their operations.

New federal programs relating to climate change appear to be likely through at least 2024.

For example, EPA has proposed to update, strengthen and revise the greenhouse gas and volatile organic compound emission standards for the oil and natural gas industries, while BLM has proposed new rules to reduce venting, flaring and leaks from oil and gas production on public lands.

Aside from new controls, the 2022 Inflation Reduction Act creates incentives designed to increase use of electric cars and fuels other than oil and natural gas.

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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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:

We believe that driving a safety first 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;

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● Environmental and safety metrics measuring performance linked to compensation.

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

COVID-19 Response

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

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

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

Our employees and contractors are educated on the risks inherent in our operations and are equipped with tools to help them operate safely.

Compensation and Benefits

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

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.

Principal Office

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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”.

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