What changed in this filing

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Item 1. Business

2024-04-01 compared with 2023-03-30 · 88 added, 73 removed, 284 unchanged (36% 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 currently in the Delaware Basin in the United States, where we have an extensive drilling inventory that we believe offers attractive long-term economics.

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.

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.

Our working interests in 39,867 net acres in the Delaware Basin as of December 31, 2023 are in Pecos, Reeves, Ward and Winkler Counties, Texas.

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Our average daily net production from this area for the year ended December 31, 2023 was 13,784 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.

At December 31, 2023, our estimated total proved oil and natural gas reserves were approximately 68.1 MMBoe, consisting of 34.6 MMBbls of oil, 14.9 MMBbls of NGLs and 111.7 Bcf of natural gas, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc.

Reserves were prepared using a crude oil price of West Texas Intermediate (“WTI”) of $78.21 per Bbl and a Henry Hub natural gas price of $2.64 per MMBtu, based on the preceding 12-month first day of the month average spot prices as required by the Securities and Exchange Commission (the “SEC”).

Approximately 59% of our estimated proved reserves were classified as proved developed and we maintain operational control of 99.9% of our estimated proved reserves as of December 31, 2023.

Business Strategy

Our primary long-term objective is to increase stockholder value by safely and cost-effectively increasing our production of oil, natural gas and natural gas liquids, adding to our proved reserves and growing our inventory of economic drilling locations, while acting as a responsible corporate citizen in the communities in which we operate.

Our primary long-term objective is to increase stockholder value by safely and cost-effectively increasing our production of oil, natural gas and NGLs, adding to our proved reserves and growing our inventory of economic drilling locations, while acting as a responsible corporate citizen in the communities in which we operate.

To accomplish this objective, we intend to execute the following business strategies:

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

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.

We are the operator for substantially all 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.

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

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 believe our internally-generated cash flows from operations, cash on hand, and preferred equity funding and commitments during 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 $50.1 million in 2024, 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”.

As of December 31, 2023, we have no additional borrowing capacity under our current Amended Term Loan Agreement, 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.

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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.

● 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.”

● 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.

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.

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.

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

● 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.

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.

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 H2S and CO2.

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.

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

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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 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.

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.

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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We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivatives available, we typically use fixed-price swap, costless collar, basis swap, and WTI NYMEX roll agreements to attempt to manage price risk.

While there are many different types of derivatives available, we typically use fixed-price swaps, costless collars, basis swaps and WTI NYMEX roll agreements to attempt to manage price risk.

The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.

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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.

The proved reserves estimates reported herein for the years ended December 31, 2023 and 2022, have been independently evaluated by NSAI, our independent reserve engineering firm.

Within NSAI, 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.

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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.

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.

Our Vice President of Strategy and Planning is primarily responsible for overseeing the preparation of the annual reserve report by NSAI.

He has approximately 14 years of oil and natural gas operations experience and has earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, a Master of Business Administration degree 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.

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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.

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, 2023.

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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.

The following table sets forth these reserves:

The following table presents estimated proved reserves at December 31, 2023:

Natural Gas Liquids (MBbls)

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At December 31, 2023, total estimated proved reserves were approximately 68.1 MMBoe, a 23.9 MMBoe net decrease from the previous year’s estimate of 92.0 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.

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.

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.

During 2023, approximately $33.0 million in capital expenditures went toward the development of PUD reserves, which includes drilling, completion and other facility costs associated with developing PUD wells.

Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well.

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

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

No other alternative methods or technologies were used to estimate

proved reserves.

Out of total PUD reserves of 27.9 MMBoe at December 31, 2023, 12.7 MMBoe were associated with 16 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 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.

For additional information on our estimates of oil and natural gas reserves, the preparation of such estimates by NSAI 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—“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 which is further described in Item 8.

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(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 had no exploratory or extension wells drilled for the years ended December 31, 2023 and 2022.

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

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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:

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

Years Ended December 31,

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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.

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

Competitive Conditions in the Business

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

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

Seasonality of Business

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

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

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.

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

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Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances released into the environment, for damages to natural resources and for the costs of some health studies.

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

In addition, it is not

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

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

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

In the ordinary course of our operations, moreover, 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.

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

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

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

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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 U.S.

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

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

While the Trump

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

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

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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

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.

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In 2012, 2016 and 2023, the EPA issued air regulations for the oil and natural gas industry that address emissions from certain new sources of volatile organic compounds, sulfur dioxide, air toxics, and methane.

The rules included the first federal air standards for natural gas and oil wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks.

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.

The rules included the first federal air standards for oil and natural gas wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks.

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.

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Climate Change

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

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

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

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

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

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

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

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 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.

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).

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

requires routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations;

limits flaring from existing oil wells;

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.

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.

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

The National Environmental Policy Act

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act, or NEPA.

Oil and natural gas exploration and production activities may be subject to the National Environmental Policy Act (“NEPA”).

NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment.

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

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

Diversity and Inclusion

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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.

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.

Principal Office

As of December 31, 2022, we leased corporate office space in Houston, Texas at 3505 West Sam Houston Parkway North.

As of December 31, 2023, we lease corporate office space in Houston, Texas at 820 Gessner Road.

Access to Company Reports

We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Securities Exchange Act of 1934, as amended.

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

In addition, our insider trading policy,

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

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.

2 unchanged sentences

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