What changed in this filing

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Item 1. Business

2025-03-31 compared with 2024-04-01 · 107 added, 76 removed, 296 unchanged (38% of the section changed)

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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.

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.

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 U.S.

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.

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As of December 31, 2024, we had 91 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, 2023 was 13,784 Boe/d.

Our average daily net production for the year ended December 31, 2024 was 12,667 Boe/d.

At December 31, 2024, our estimated total proved oil and natural gas reserves were approximately 64.9 MMBoe, consisting of 34.8 MMBbls of oil, 12.6 MMBbls of NGLs and 105.4 Bcf of natural gas, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

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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.

In December 2024, we entered into a drilling contract and have begun a six-well campaign scheduled to conclude before the end of the second quarter 2025 that will bring new production online across our assets.

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

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Recent Developments

● 2024 Amended Term Loan Agreement.

On December 26, 2024, we and our wholly-owned subsidiary Halcón Holdings, LLC (the “Borrower”) entered into the Second Amended and Restated Senior Secured Credit Agreement (the “2024 Term Loan Agreement”) with Fortress Credit Corp., as administrative agent, and certain other financial institutions party thereto, as lenders.

Pursuant to the 2024 Term Loan Agreement, the lenders agreed to provide us with (i) an initial term loan facility in the aggregate principal amount of $162.0 million, funded on December 26, 2024 and (ii) an incremental term loan facility in the aggregate principal amount of up to $63.0 million, of which such incremental borrowings in the amount of $63.0 million were incurred on January 9, 2025 pursuant to a first amendment (the “First Amendment”) to our 2024 Term Loan Agreement (as amended, the “2024 Amended Term Loan Agreement”).

The 2024 Amended Term Loan Agreement matures on December 26, 2028.

All obligations under the 2021 Amended Term Loan Agreement (as defined in Item 8.

Consolidated Financial Statements and Supplementary Data— Note 7 , “Debt” ) were refunded, refinanced and repaid in full by the loans under the 2024 Term Loan Agreement as the net proceeds of the 2024 Term Loan Agreement were used to repay all outstanding indebtedness under the 2021 Amended Term Loan Agreement, including accrued and unpaid interest, in an aggregate amount of approximately $152.1 million and to pay related fees and expenses.

Borrowings under the 2024 Amended Term Loan Agreement bear interest at a rate per annum equal to a forward-looking term rate based on the Secured Overnight Financing Rate (“SOFR”) for a tenor of three months (with a credit spread adjustment of 0.15% per annum) (or another applicable reference rate, as determined pursuant to the terms of the 2024 Amended Term Loan Agreement) plus an applicable margin of 7.75%.

The 2024 Amended Term Loan agreement contains certain financial covenants (as defined in the 2024 Term Loan Agreement), including maintenance of the following ratios.

● Asset Coverage Ratio not to fall below 1.70x as of March 31, 2025 through and including June 30, 2025, 1.85x as of September 30, 2025 through and including December 31, 2025 and 2.00x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

● Total Net Leverage Ratio not to exceed 2.75x as of March 31, 2025 through and including June 30, 2025 and 2.50x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

● Current Ratio not to fall below 1.00x, determined on the last day of each calendar month commencing with the calendar month ending March 31, 2025;

● Liquidity not to fall below the greater of (x) $10,000,000 and (y) the amount equal to the scheduled principal and interest payments for the immediately succeeding three-month period, determined as of the last day of any fiscal quarter.

Under the 2024 Amended Term Loan Agreement, we are required to hedge approximately 85% to 50% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years.

The 2024 Amended Term Loan Agreement also contains certain events of default, including non-payment;

breaches of representations and warranties;

non-compliance with covenants or other agreements;

cross-default to material indebtedness;

change of control;

and voluntary and involuntary bankruptcy.

For the year ended December 31, 2024, the Company recognized a loss on extinguishment of debt in the amount of $7.5 million resulting from the credit agreement refinancing on December 26, 2024 which includes a $3.6 million non-cash write-off of deferred financing costs, original issue discounts and embedded derivatives associated with the extinguished debt and $3.9 million in fees and debt issuance costs paid for the new debt.

For further details on the 2024 Amended Term Loan Agreement, see Item 7.

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

● Merger with Fury Resources.

On December 14, 2023, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Fury Resources, Inc.

(“Parent”) and San Jacinto Merger Sub, Inc (“Merger Sub”), a direct wholly-owned subsidiary of Parent, pursuant to which Parent will acquire all of the outstanding shares of common stock of the Company for $9.80 per share in cash, which represents a total transaction value of approximately $450.0 million (the “Merger”).

The preferred stock (as defined below) of the Company held by the Investors (as defined below) will be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at a valuation based on the conversion or redemption value of such preferred stock.

If the Merger is consummated, our shares of common stock will no longer trade on the NYSE American and will be deregistered under the Securities Exchange Act of 1934, as amended.

As a result, we will become a private company.

The Merger is expected to close in the second quarter of 2024, subject to various customary closing conditions, such as the approval of Battalion’s stockholders.

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

Management’s Discussion and Analysis, “Recent Developments.”

(“Parent”) and San Jacinto Merger Sub, Inc (“Merger Sub”), a direct wholly-owned subsidiary of Parent, pursuant to which Parent was to acquire all of the outstanding shares of common stock of the Company (the “Merger”).

In addition, the preferred stock (as defined below) of the Company held by the Investors (as defined below) would be contributed to Parent in exchange for new preferred shares of Parent, or sold to Parent for cash, in each case at a valuation based on the conversion or redemption value of such preferred stock.

The Merger Agreement was terminated on December 20, 2024.

Upon termination, we recognized $10.0 million of other income for the January 24, 2024 distribution from the escrow account.

● Preferred Stock Equity Issuances.

On November 8, 2023, we obtained an additional support letter from Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing shareholders (the “Investors”) to purchase additional preferred equity securities in an amount up to $55.00 million over the next 12 months.

An aggregate of 35,000 shares of preferred stock were sold on December 15, 2023 under such support letter to the Investors for proceeds of $34.1 million, net of $0.9 million of original issue discount.

At December 31, 2023, $20.0 million remained available for issuance under the support letter from the Investors.

On March 27, 2024, we sold, in a private placement, the remaining 20,000 shares of preferred stock under a commitment letter received during the third quarter of 2023 to certain funds managed by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC, who represent our largest three existing stockholders (the “Investors”).

We received $19.5 million in proceeds, net of $0.5 million in original issue discount.

On May 13, 2024, we sold, in a private placement, an aggregate of 20,000 shares of preferred stock to the Investors for $19.5 million in proceeds, net of $0.5 million in original issue discount.

The issuances of preferred stock were approved by our board of directors upon recommendation by a special committee of disinterested directors that was established to evaluate the proposed terms of the preferred stock.

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● 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 Wink Amine Treater, LLC (“WAT”) (previously Brazos Amine Treater, LLC (“BAT”)), has also entered into a Gas Treating Agreement (“GTA”) with us for natural 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 WAT, an unconsolidated subsidiary.

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 WAT, an equity investment.

Caracara provided the initial capital for the construction of the Facility, which is expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H 2 S and CO 2 .

During commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection.

We initially expected the AGI Facility to be

mechanically complete in early April 2023 and to be in service in the second quarter of 2023.

However, during commissioning and initial operations, it was determined that additional pressure was required to initiate gas injection.

To correct this issue, a positive displacement pump was ordered and installed.

The Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure.

We commenced workover operations to remediate this issue and such workover operations on the well and injection tests were completed.

During the third quarter of 2023, additional complications were encountered with the workover operation causing higher than expected costs.

To fund this workover operation, we advanced capital contributions totaling approximately $15.1 million during the year ended December 31, 2023 on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we believe we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance.

We advanced additional capital contributions on behalf of our joint venture partner during the first quarter of 2024 of approximately $3.0 million to fund WAT with the necessary capital required to complete the sidetrack of the Acid Gas Injection (“AGI”) well.

Workover operations on the well and injection tests have now been successfully completed.

WAT is now ramping up operations and our current forecast assumes the AGI facility will be processing 20,000 Mcf of natural gas per day by the second quarter of 2024.

The AGI Facility’s injection well also experienced pressure communication between the tubing and annular space after an injection procedure.

We commenced workover operations to remediate this issue.

During the third quarter of 2023, additional complications were encountered with the workover operation at the AGI Facility causing higher than expected costs.

To fund this workover operation, we advanced capital contributions totaling approximately $18.5 million as of December 31, 2024 on behalf of our joint venture partner in WAT.

Pursuant to the terms of the agreement governing the joint venture, we believe that we have multiple remedies to recover such advance, including (1) declaring such payment a loan, which pursuant to the agreement would have an interest rate of the lesser of 15% or the maximum rate permitted by law, (2) recoupment from distributions from the joint venture and (3) reallocation of equity of the joint venture based on the relative level of total capital contributions by the parties after taking into account the advance.

Pursuant to such, we initially recorded the advanced amount as a contract asset.

During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the contract asset may not be recoverable and as a result, we recognized $18.5 million of impairment of charges to reduce the carrying value of the contract asset to zero as of December 31, 2024.

The AGI Facility has been processing gas since March 9, 2024 and continues to process gas currently.

In addition to general facility downtime, the AGI Facility has experienced interruption in processing due to the completion of improvement and maintenance projects, including pump and other facility equipment replacement.

However, the facility has processed over 5.5 Bcf of natural gas since operations commenced through December 31, 2024.

The continued processing delays and interruptions during 2024 have resulted in higher than expected gathering and treating costs as we pay higher processing rates with other service providers.

It is possible that the existing remedial facility work by WAT could extend into 2025, and any delays in fully commissioning the facility or shut downs of the plant past December 31, 2024 will result in higher processing fees than currently forecasted until such time the facility becomes fully operational.

Under the GTA, we pay a treating rate that varies based on volumes delivered to the AGI Facility and have a minimum volume commitment of 20 MMcf per day.

The GTA has a tiered-rate structure based on actual volumes delivered.

Our current estimates of future treating fee reductions are subject to various operational and other risk factors, some of which are beyond our control, which could impact the timing and extent of these estimates .

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

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

Management’s Discussion and Analysis, “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 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.

We were required under the 2021 Amended Term Loan Agreement, and continue to be required under our 2024 Amended Term Loan Agreement, to hedge approximately 85% to 50% 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.

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

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

Our independent engineering firm reports jointly to the reserves committee and to our Vice President of Strategy and Planning.

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.

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

WTI crude oil spot price of $78.21 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.64 per MMBtu, adjusted by lease or field for energy content, transportation fees, and market differentials.

WTI crude oil spot price of $76.32 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $2.13 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.

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At December 31, 2024, total estimated proved reserves were approximately 64.9 MMBoe, a 3.2 MMBoe net decrease from the previous year’s estimate of 68.1 MMBoe.

Proved developed reserves of 40.1 MMBoe decreased approximately 6.2 MMBoe from December 31, 2022 primarily as a result of negative revisions of 3.6 MMBoe and production of 5.0 MMBoe offset by proved undeveloped (“PUD”) reserve development of 2.4 MMBoe.

PUD reserves of 27.9 MMBoe decreased approximately 17.7 MMBoe from December 31, 2022 as a result of the transfer of 2.4 MMBoe to proved developed producing reserves and downward revisions of 15.3 MMBoe due primarily to the removal of 13.0 MMBoe of PUDS due to decreased activity associated with managing cash flow, servicing debt and financial covenants, and ongoing work to recapitalize the business coupled with a downward revision of 2.3 MMBoe due to decreased SEC prices.

Proved developed reserves of 36.3 MMBoe decreased approximately 3.8 MMBoe from December 31, 2023 primarily as a result of negative revisions of 2.1 MMBoe due primarily to the decrease in pricing and changes in differentials, deducts and marketing expenses and production of 4.6 MMBoe offset by proved undeveloped (“PUD”) reserve development of 2.9 MMBoe.

PUD reserves of 28.6 MMBoe increased approximately 0.7 MMBoe from December 31, 2023 as a result of extensions of 4.0 MMBoe primarily associated with infill drilling activity offset by the transfer of 2.9 MMBoe to proved developed producing reserves and downward revisions of 0.4 MMBoe due to decreased SEC prices.

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

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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, this 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 28.6 MMBoe at December 31, 2024, 7.5 MMBoe were associated with 10 gross PUD locations that were more than one offset location from a producing well.

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

(3) Negative realized natural gas pricing for the year ended December 31, 2024 resulted from increased deduct and differential costs exceeding natural gas index prices.

Realized prices differ from the applicable spot prices due to lease or field quality, energy content, transportation fees and market differentials.

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

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

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 U.S.

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.

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

In 2023, two individual purchasers of our production, Western Refining Company L.P.

and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 79% of our total sales for the year.

In 2022, three individual purchasers of our production, 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 2024 and 2023, two individual purchasers of our production, Western Refining Company L.P.

and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 86% and 79%, respectively, of our total sales for the year.

Seasonality of Business

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Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment.

Numerous governmental agencies, such as the United States Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures.

Numerous governmental agencies, such as the U.S.

Environmental Protection Agency (the “EPA”), issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures.

Among other things, environmental regulatory programs typically govern the permitting, construction and operation of a facility.

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Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment.

The federal Comprehensive Environmental Response, Compensation and Liability Act (“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.

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uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as RCRA, most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste.

Under the federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”) most wastes generated by the exploration and production of oil and natural gas are not regulated as hazardous waste.

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

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

Further, we do generate solid wastes that are subject to regulation.

The Texas Railroad Commission, for example, has adopted new oilfield waste management rules that take effect on July 1, 2025.

Among other things, they impose new requirements for certain pits and for land application of waste.

Water Discharges

Our operations also may be subject to the federal Clean Water Act and analogous state statutes.

Our operations also may be subject to the federal Clean Water Act (the “CWA”) and analogous state statutes.

Those laws regulate discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams.

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These laws also require the preparation and implementation of spill prevention, control, and countermeasure plans in connection with on-site storage of significant quantities of oil.

In the event of a discharge of oil into United States waters, we could be liable under the Oil Pollution Act for cleanup costs, damages and economic losses.

In the event of a discharge of oil into U.S.

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

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

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

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

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

Hydraulic fracturing involves the injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depths to stimulate oil and natural gas production.

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Working at the direction of Congress, the EPA issued a study in 2016 finding that hydraulic fracturing could potentially harm drinking water resources under adverse circumstances such as injection directly into groundwater or into production wells lacking mechanical integrity.

The EPA also promulgated pre-treatment standards under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations to municipal sewage treatment plants.

Environmental groups have encouraged the EPA to supplement those requirements.

Various members of Congress likewise have from time to time introduced bills that would result in more stringent control or outright bans of the hydraulic fracturing process.

That study led to calls from environmental groups for increased federal regulatory controls.

Various members of Congress likewise occasionally have introduced bills that would result in more stringent control or outright bans of the hydraulic fracturing process.

In addition, the Department of the Interior promulgated 2015 regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes lands on which we conduct or plan to conduct operations.

While the Trump

Administration rescinded those rules, that decision is being challenged in court.

Those rules were rescinded in 2017, but that decision was challenged in court, and the parties recently have been involved in settlement discussions.

Regardless of how the federal issues are eventually resolved, states have been imposing new restrictions or bans on hydraulic fracturing.

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Air Emissions

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

The federal Clean Air Act (the “CAA”) 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 facilities.

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.

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

Our operations, or the operations of service companies engaged by us, may in certain circumstances and locations, be subject to permits and restrictions under these statutes for emissions of air pollutants.

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Compliance has imposed, and will impose, 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, 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.

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 of the 2015 standard has been ongoing and has resulted in expansion of ozone nonattainment areas across the U.S., 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, 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.

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

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

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

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

Consistent with that strategy, the EPA issued air rules for oil and natural 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, limited new oil and natural 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 announced new final regulations in December 2023 that impose more comprehensive restrictions on emissions of methane (a greenhouse gas) and volatile organic compounds from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries).

In the U.S., 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 least two states have also passed statutes that would authorize collection of payments from certain fossil fuel companies to address the effects of climate change.

At the federal level, the U.S.

has taken a variety of steps intended to address climate change.

For example, the EPA announced new final regulations in December 2023 that impose more comprehensive restrictions on emissions of methane (a greenhouse gas) and volatile organic compounds from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries).

Among other things, the rule sets new emissions standards for certain equipment;

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and prohibits flaring from new oil wells.

In addition, BLM has proposed new rules to reduce venting, flaring and leaks from oil and gas production on public lands.

In addition, the federal Bureau of Land Management (“BLM”) promulgated new rules in 2024 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.

That statute imposes a fee on certain excess methane emissions from oil and gas facilities of $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter.

That statute imposes a fee on certain

excess methane emissions from oil and gas facilities of $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter.

As a general matter, recent Democratic Presidential Administrators have been spearheading the development of federal climate policies and controls.

With President Trump’s return to office in 2025, however, the White House issued executive orders that, among other things, directed the U.S.

Ambassador to the United Nations to give notice of the U.S.’ withdrawal from the Paris Agreement and the heads of all agencies to review their actions that impose an undue burden on the development or use of domestic energy resources, “with particular attention to oil, natural gas, coal, hydropower, biofuels, critical mineral and nuclear energy resources.” We therefore expect the pace of new federal climate regulation to slow at least in the short-term.

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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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.

The United States Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species.

A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development.

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

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

Where takings of or harm to species or damages to wetlands, habitat or other natural resources occur or may occur, restrictions may be imposed on oil and natural gas exploration activities.

Fish and Wildlife Service may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species.

A critical habitat designation could result in further material restrictions on federal or private land use and could delay or prohibit land access or development.

Government entities or at times private parties may act to prevent or seek damages for any injury to protected species or other natural resources, 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

6 unchanged sentences

As of December 31, 2024, we had 38 full-time employees.

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

We also engage the services of

independent contractors and consultants along with certain professional service firms to support our work in specific areas.

We have no collective bargaining agreements with our employees.

17 unchanged sentences

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

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

Employees are required to acknowledge and agree to abide by these policies upon employment.

Principal Office

2 unchanged sentences

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.

We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Forms 3, 4 and 5 filed on behalf of directors and officers, and any amendments to such reports, available free of charge through our corporate website at www.battalionoil .com as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC.

In addition, our insider trading policy, regulation FD policy, corporate governance guidelines, code of conduct, code of ethics, audit committee charter, compensation committee charter, nominating and corporate governance committee charter and reserves committee charter are available on our website under the heading “Investors—Corporate Governance”.

Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the code of conduct and the code of ethics for our chief executive officer and senior financial officers and any waivers applicable to senior officers as defined in the applicable code, as required by the Sarbanes-Oxley Act of 2002.

In addition, our reports, proxy and information statements, and our other filings are also available to the public over the internet at the SEC’s website at www.sec .gov .

In addition, our reports, proxy

and information statements, and our other filings are also available to the public over the internet at the SEC’s website at www.sec .gov .

Unless specifically incorporated by reference in this Annual Report on Form 10-K, information that you may find on our website is not part of this report.

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

What changed 10-K

Item 1. Business