What changed in this filing

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Item 1. Business

2026-03-23 compared with 2025-03-31 · 83 added, 91 removed, 312 unchanged (36% of the section changed)

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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.

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.

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Approximately 60% of our estimated proved reserves were classified as proved developed and we maintain operational control of 99.8% of our estimated proved reserves as of December 31, 2025.

On December 18, 2025, we entered into an agreement of sale and purchase with MCM Delaware Resources, LLC (“MCM”) to sell substantially all of our oil and natural gas properties and related assets in the West Quito Draw area located in the Southern Delaware Basin in Ward County, Texas (the “West Quito Assets”) for a total sales price of approximately $62.6 million, subject to adjustment for accounting between the effective date of December 1, 2025 and the closing date and other customary adjustments (the “West Quito Divestiture”).

The West Quito Divestiture closed on February 24, 2026 for an adjusted sales price of $60.1 million.

The West Quito Assets include approximately 6,100 net acres in Ward County, Texas which contributed approximately 15% of our annual production for the year ended December 31, 2025 and accounted for approximately 6.0 MMboe, or approximately 10%, of our proved reserves at December 31, 2025.

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 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.

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

We currently plan to commence drilling two wells in January 2027.

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

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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 preferred equity funding and commitments during 2024 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 $16.9 million in 2025, and maintain compliance with our debt covenants.

We believe our internally-generated cash flows from operations, cash on hand, proceeds from the West Quito Divestiture and the private placement equity offering, and existing preferred equity commitments under support letters from our largest investors will provide us with sufficient liquidity to execute our capital and operating program over the next twelve months, address near-term debt maturities of $22.5 million in 2026, 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, 2024, we have no additional borrowing capacity under our current 2024 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”.

As of December 31, 2025, we have no additional borrowing capacity under our current 2024 Amended Term Loan Agreement (defined below), 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

● Monument Draw Acquisition.

On March 10, 2026, we entered into a purchase and sale agreement to acquire certain oil and natural gas assets, comprising 7,090 net acres located in Ward County, Texas, from RoadRunner Resource Holding LLC (formerly, Sundown Energy LP) (“RoadRunner”), effective March 1, 2026, in an all-stock transaction.

Under the terms of the agreement, upon closing on March 19, 2026, we issued 485,000 shares of our common stock to RoadRunner in exchange for the assets.

The acquired acreage is directly adjacent to our existing Monument Draw acreage.

The transaction is subject to customary post-closing adjustments.

● Private Placement Equity Offering.

On March 3, 2026, we entered into a definitive agreement to sell in a private placement to an institutional investor 1,800,000 shares of our common stock and 927,273 prefunded warrants for the purchase of common stock at $5.50 per share for total proceeds of $15.0 million.

The offering closed on March 4, 2026, on satisfaction of customary closing conditions.

We intend to use the net proceeds received from the offering for working capital and general corporate purposes.

● West Quito Divestiture.

On December 18, 2025, we entered into an agreement of sale and purchase with MCM to sale our West Quito Assets for a total sales price of $62.6 million, subject to adjustment for accounting effective date of December 1, 2025 and other customary adjustments.

The West Quito Divestiture closed on February 24, 2026 for an adjusted sales price of $60.1 million and $45.6 million of the net proceeds from closing were used to repay amounts outstanding under the 2024 Amended Term Loan Agreement on February 24, 2026 - $40.0 million pursuant to the Third Amendment (defined below) and prepayment of $5.6 million for the scheduled quarterly amortization payment for the quarterly period ending March 31, 2026.

Pursuant to the Third Amendment (defined below), $12.9 million of proceeds from the sale (the “Reinvestment Proceeds”) are to be used to acquire additional contiguous non-operated oil and natural gas properties consisting of proved

developed reserves in Ward and Winkler Counties, Texas, to fund permitted capital expenditures in the Monument Draw area and/or to fund the drilling and completion of two Monument Draw wells within 180 days after receipt.

Should such funds have not been spent within the 180-day period, the Reinvestment Proceeds shall be used to prepay borrowings outstanding under the 2024 Amended Term Loan Agreement.

● 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 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 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.

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”.

On February 24, 2026, we entered into the Limited Consent, Third Amendment to Second Amended and Restated Senior Secured Credit Agreement and First Amendment to Fee Letter (the “Third Amendment”) to the Second Amended and Restated Senior Secured Credit Agreement (the “2024 Amended Term Loan Agreement”).

Pursuant to the Third Amendment, among other changes specified therein, (a) the lenders consented to the transactions contemplated by the West Quito Divestiture sale agreement;

and (b) we were required, upon receipt of the net cash proceeds from the West Quito Divestiture, to prepay the outstanding principal amount of the 2024 Amended Term Loan Agreement borrowings in an aggregate amount equal to $40.0 million.

We may retain the remaining net cash proceeds received from the West Quito Divestiture, subject to certain reinvestment requirements, set forth in the Third Amendment.

● 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 “AGI 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.

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

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

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

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 .

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 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 .

After significant complications and delays, the AGI Facility began processing gas on March 9, 2024 and treated volumes from March 2024 to August 11, 2025.

In addition to general facility downtime, the AGI Facility experienced interruptions in processing due to failure to complete necessary improvement and maintenance projects.

The AGI Facility processed over 9.3 Bcf of natural gas before ceasing operations.

On August 11, 2025, we received notice from WAT that it was ceasing taking deliveries of natural gas and was ceasing operations effective immediately.

In response, we temporarily shut-in a portion of our Monument Draw field production while management actively worked to identify and execute on a plan for long-term alternative gas processing.

We terminated the GTA on January 19, 2026.

Following termination of the GTA, we entered into an agreement with a publicly traded large-cap midstream provider to process our natural gas production at an alternative facility.

This processing provider has the ability to process substantially all of our natural gas production from Monument Draw.

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.

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.

We are required under our 2024 Amended Term Loan Agreement, to hedge approximately 85% to 50% of our anticipated oil and natural gas production, respectively, 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 2024 Amended Term Loan Agreement.

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

Our future performance is subject to commodity price risks and our

future cash flows from operations may be volatile.

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

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

He has approximately 15 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.

He has more than 16 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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Average prices for the 12-month period were as follows:

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.

WTI crude oil

spot price of $66.01 per Bbl, adjusted by lease or field for quality, transportation fees, and market differentials and a Henry Hub natural gas spot price of $3.39 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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This is an energy content correlation and does not reflect the value or price relationship between the commodities.

(2) Proved reserves associated with the West Quito Divestiture represented 6,002 MBoe, or approximately 10%, of total proved reserves, all of which were classified as proved developed, and $36.2 million of PV-10 value at December 31, 2025.

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

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

(2) At December 31, 2025, reserves associated with the West Quito Assets totaled 6,002 Mboe (2,004 MBbls of oil, 1,203 MBbls of NGLs and 16,766 Mcf of natural gas), all of which were classified as proved developed.

At December 31, 2025, total estimated proved reserves were approximately 59.7 MMBoe, a 5.2 MMBoe net decrease from the previous year’s estimate of 64.9 MMBoe.

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.

Proved developed reserves of 35.6 MMBoe decreased approximately 0.7 MMBoe from December 31, 2024 primarily as a result of negative revisions of 1.8 MMBoe due to the decrease in pricing and changes in differentials, deducts and marketing expenses and production of 4.4 MMBoe offset by proved undeveloped (“PUD”) reserve development of 5.5 MMBoe.

PUD reserves of 24.1 MMBoe decreased approximately 4.6 MMBoe from December 31, 2024 as a result of downward revisions of 1.2 MMBoe due to decreased SEC prices and transfer of 5.5 MMBoe to proved developed producing reserves offset by extensions of 2.1 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.

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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.

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.

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

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Years Ended December 31,

(1) At December 31, 2025 and 2024, 13 gross (11.5 net) oil wells and 15 gross (14.0 net) oil wells, respectively, were associated with West Quito Assets.

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

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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.

(2) Of the wells drilled during 2025, two gross (1.6 net) wells were located in West Quito.

There were no West Quito wells drilled during 2024.

We had no exploratory or extension wells drilled for the years ended December 31, 2025 and 2024.

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Total Acreage

(1) As of December 31, 2025, 7,608 gross (6,134 net) acres were located in the West Quito area.

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

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

(2) Total production for the years ended December 31, 2025 and 2024 from West Quito totaled 679 MBoe and 644 MBoe, respectively.

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

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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.

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.

Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

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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 (“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, we do handle materials that may be subject to extensive existing RCRA regulations or that may be classified as hazardous substances under CERCLA.

In the ordinary course of our operations, we handle some 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.

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.

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

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

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

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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.

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.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with substantially all of the wells for which we are the operator.

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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.

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

Those rules were rescinded in 2017, but that decision was challenged in court, and regulations could possibly be re-issued in the future.

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 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 2025, the EPA proposed discrete technical changes to its oil and gas emission standards and extended various compliance deadlines (a decision being challenged in court).

Nonetheless, federal air standards have 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.

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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 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.

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and prohibits flaring from new oil wells.

To reduce the compliance difficulties, the EPA proposed discrete technical changes to those emission standards in 2025 and extended various compliance deadlines (a decision being challenged in court).

Nonetheless, those federal air standards have imposed, and will impose, additional requirements and costs on our operations.

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.

District Court for the District of North Dakota enjoined enforcement in five states, including Texas, but the litigation is being held in abeyance, and BLM reportedly is working on a replacement proposed rule.

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

That statute required the EPA to impose 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.

The EPA had promulgated a final rule to implement the methane charges, but Congress disapproved it pursuant to the Congressional Review Act.

The EPA reportedly is evaluating its options for complying with the statutory obligation to assess methane fees.

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

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

In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA.

This process has the potential to delay the development of oil and natural gas projects.

This process has the potential to delay the development of oil and natural gas projects, especially since federal agencies have been revising their NEPA regulations and policies in response to recent judicial decisions.

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

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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.

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.

Further, the EPA and U.S.

Army Corps of Engineers have proposed a new definition for regulated wetlands that is expected to reduce the scope of federal jurisdiction but may prove difficult to implement.

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.

7 unchanged sentences

As of December 31, 2025, we had 40 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.

15 unchanged sentences

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

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

All Battalion employees must act in accordance

with our Employee Handbook, which is inclusive of our Code of Conduct.

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

7 unchanged sentences

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