Item 1. Business
ITEM 1. BUSINESS
Overview
Unless the context otherwise requires, all references in this report to “Battalion,”, “the Company”, “our,” “us,” and “we” refer to Battalion Oil Corporation and its subsidiaries, as a common entity. Battalion is the successor reporting company to Halcón Resources Corporation (“Halcón”).
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.
Our working interests in 39,968 net acres in the Delaware Basin as of December 31, 2025 are in Pecos, Reeves, Ward and Winkler Counties, Texas. This resource play is characterized by high oil and liquids-rich natural gas content in thick, continuous sections of source rock that can provide repeatable drilling opportunities and significant initial production rates. Our primary targets in this area are the Wolfcamp and Bone Spring formations. As of December 31, 2025, we had 82 operated wells producing in this area in addition to minor working interests in 22 non-operated wells. Our average daily net production for the year ended December 31, 2025 was 12,096 Boe/d.
At December 31, 2025, our estimated total proved oil and natural gas reserves were approximately 59.7 MMBoe, consisting of 31.8 MMBbls of oil, 11.6 MMBbls of NGLs and 97.5 Bcf of natural gas, as prepared by our independent reserve engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Reserves were prepared using a crude oil price of West Texas Intermediate (“WTI”) of $66.01 per Bbl and a Henry Hub natural gas price of $3.39 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 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
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:
● Develop our Liquids-Rich Acreage Positions to Grow Production and Reserves Efficiently. 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 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.
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● Enhance Returns Through Continued Improvements in Operational and Cost Efficiencies. 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. As operator, we are able to evaluate industry drilling results and implement improved operating practices that may enhance our initial production rates, ultimate recovery factors and rate of return on invested capital. We continue to focus on cost-saving measures including reducing corporate administrative expenses and pursuing operational efficiencies.
● Maintain Adequate Liquidity. Our management team is focused on maintaining adequate liquidity while pursuing our near-term development plans. We believe our internally-generated cash flows 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, 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. From time to time, we may pursue merger and acquisition opportunities to meet our strategic and financial targets, including the maintenance of a conservative leverage position. Selective business combinations provide opportunities to acquire high quality assets complementary to our acreage, expand our drilling inventory and gain operational scale. We believe our management team’s geologic and engineering expertise, particularly in the Permian Basin, provides a competitive advantage in the identification of acquisition targets and evaluation of resource potential.
Our ability to achieve our business strategy is subject to numerous risks and uncertainties, many of which are beyond our control. Additional information regarding our risks can be found in Item 1A. Risk Factors.
Recent Developments
● 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
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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 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”) 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.
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. Management’s Discussion and Analysis, “Recent Developments”.
Risk Management
We have designed a risk management policy for the use of derivative instruments to provide initial protection against certain risks relating to our ongoing business operations, such as commodity price declines and price differentials between the NYMEX commodity price and the index price at the location where our production is sold. Derivative contracts are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. 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
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future cash flows from operations may be volatile. 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 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. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing). WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. As of December 31, 2025, we did not post collateral under any of our derivative contracts as they are secured under our 2024 Amended Term Loan Agreement. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Consolidated Financial Statements and Supplementary Data— Note 8 , “Derivative and Hedging Activities,” for additional information.
Oil and Natural Gas Reserves
The proved reserves estimates reported herein for the years ended December 31, 2025 and 2024, 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.
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 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. Our Vice President of Strategy and Planning is primarily responsible for overseeing the preparation of the annual reserve report by NSAI. 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. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2025. Average prices for the 12-month period were as follows: WTI crude oil
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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.
The following table presents certain proved reserve information as of December 31, 2025 (dollars in thousands):
Proved Reserves (MBoe) (1)(2)
Developed
35,649
Undeveloped
24,053
Total
59,702
PV-10 (3)
$
351,730
Discounted Future Income Taxes
(8,212)
Standardized measure of discounted future net cash flows
$
343,518
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.
(2) 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%. PV-10 of our total year-end proved reserves is considered a non-U.S. GAAP financial measure as defined by the SEC. We believe that the presentation of the PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. We further believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. Refer to the reconciliation of our PV-10 to the standardized measure of discounted future net cash flows in the table above.
The following table presents estimated proved reserves at December 31, 2025:
Proved
Proved
Total
Developed
Undeveloped
Proved (2)
Oil (MBbls)
17,119
14,681
31,800
Natural Gas Liquids (MBbls)
7,615
4,029
11,644
Natural Gas (MMcf)
65,488
32,060
97,548
Equivalent (MBoe) (1)
35,649
24,053
59,702
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.
(2) 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 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. During 2025, approximately $61.7 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. 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
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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.
The estimates of quantities of proved reserves contained in this report were made in accordance with the definitions contained in SEC Release No. 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 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. Consolidated Financial Statements and Supplementary Data —Note 5, “Oil and Natural Gas Properties.”
Wells and Acreage
Our principal properties consist of leasehold interests in developed and undeveloped oil and natural gas properties and the reserves associated with these properties.
The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2025 and 2024. Shut-in wells currently not capable of production are excluded from the well information below.
Years Ended December 31,
2025
2024
Gross
Net
Gross
Net
Oil (1)
104
77.5
108
86.9
Natural Gas
—
—
—
—
Total
104
77.5
108
86.9
(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:
Years Ended December 31,
2025
2024
Gross
Net
Gross
Net
Development Wells:
Productive (1) (2)
6
5.6
4
3.9
Total Development
6
5.6
4
3.9
Total Wells:
Productive (1) (2)
6
5.6
4
3.9
Total
6
5.6
4
3.9
(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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We own interests in developed and undeveloped oil and natural gas acreage in the locations set forth in the table below. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying provisions. The following table presents a summary of our acreage interests as of December 31, 2025:
Developed Acreage
Undeveloped Acreage
Total Acreage
State
Gross
Net
Gross
Net
Gross
Net
Texas (1)
40,228
37,579
3,324
2,389
43,552
39,968
(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. Leases on our undeveloped oil and natural gas acreage are either categorized as “held by production” or perpetuated by continuous development clauses contained in our leases or tolling agreements. Of our 2,389 net undeveloped acres at December 31, 2025, approximately 1,921 acres are subject to continuous development clauses and 468 acres are “held by production.” We continually review our acreage subject to these clauses or agreements when determining our drilling program.
Production Volumes, Sales Prices, and Average Costs
The following table summarizes our oil, natural gas and NGLs production volumes, average sales price per unit and average costs per unit:
Years Ended December 31,
2025
2024
Production:
Crude oil - MBbls
2,251
2,363
Natural gas - MMcf
7,452
7,814
Natural gas liquids - MBbls
922
971
Total MBoe (1)(2)
4,415
4,636
Average daily production - Boe (1)
12,096
12,667
Average price per unit (excluding impact of settled derivatives) :
Crude oil price - Bbl
$
63.51
$
73.89
Natural gas price - Mcf (4)
0.49
(0.28)
Natural gas liquids price - Bbl
19.90
21.44
Barrel of oil equivalent price - Boe (1)
37.36
41.68
Average price per unit ( including impact of settled derivatives) (3) :
Crude oil price - Bbl
$
63.20
$
62.57
Natural gas price - Mcf
2.71
2.02
Natural gas liquids price - Bbl
19.90
21.44
Barrel of oil equivalent price - Boe (1)
40.95
39.78
Average cost per Boe:
Production:
Lease operating
$
10.15
$
9.77
Workover and other
1.46
1.12
Taxes other than income
2.23
2.42
Gathering and other
9.91
11.67
Total average cost
23.75
24.98
(1) Determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on approximate energy equivalency. This is an energy content correlation and does not reflect the value or price relationship between the commodities.
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(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.
(4) 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.
Competitive Conditions in the Business
The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient availability of drilling and completion equipment and services, obtaining purchasers, transporters and take-away capacity for the oil and natural gas we produce and hiring and retaining key employees. 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 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. 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.
Other Business Matters
Markets and Major Customers
The purchasers of our oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, we have not experienced any significant losses from uncollectible accounts. In 2025 and 2024, 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
Weather conditions affect the demand for, and prices of, oil and natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for crude oil can often be higher in the summer months during the peak travel season. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth fiscal quarters. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
Operational Risks
Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to be overcome. There is no assurance that we will discover or acquire additional oil and natural gas in commercial quantities. Oil and natural gas operations also involve the risk that well 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
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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.
As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material effect on our operating results, financial position or cash flows. For further discussion on risks see Item 1A. Risk Factors .
Regulations
All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. On some occasions, local authorities have imposed moratoria or other restrictions on exploration and production activities pending investigations and studies addressing potential local impacts of these activities before allowing oil and natural gas exploration and production to proceed.
The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
Environmental Regulations
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 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. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Failure to comply with environmental laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, which could result in liability for environmental damages and cleanup costs without regard to negligence or fault on our part.
Beyond existing requirements, new programs and changes in existing programs may address various aspects of our business, including naturally occurring radioactive materials, oil and natural gas exploration and production, air emissions, waste management, and underground injection of waste material. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse impact on our capital expenditures, earnings and competitive position.
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Hazardous Substances and Wastes
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. 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.
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. 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 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 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.
Water Discharges
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. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. 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.
Our oil and natural gas production also generates salt water, which is disposed of by underground injection. The federal Safe Drinking Water Act (“SDWA”), the Underground Injection Control (“UIC”) regulations promulgated under the SDWA, and related state programs regulate the drilling and operation of salt water disposal wells. The EPA directly administers the UIC program in some states, and in others it is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
Hydraulic Fracturing
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 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
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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.
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. 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. 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. Even local jurisdictions, such as Denton, Texas and several cities in Colorado, have adopted, or tried to adopt, regulations restricting hydraulic fracturing. Additional hydraulic fracturing requirements at the federal, state or local level may limit our ability to operate or increase our operating costs.
Air Emissions
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 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.
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 oil and natural gas wells that are hydraulically fractured, or refractured, as well as requirements for other processes and equipment, including storage tanks. 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. 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.
Climate Change
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. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning oil, natural gas and refined petroleum products, are considered greenhouse gases. 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
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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; 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. 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. The U.S. 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. 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.
The National Environmental Policy Act
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. 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, 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
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 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. The U.S. 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
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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.
Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.
Human Capital
Employees
At Battalion, our success is delivered through our highly capable and diverse workforce. Our team is comprised of individuals with extensive technical, industry and other professional experience. By recruiting, hiring and retaining an experienced and diverse team, we are able to leverage years of experience, new ideas and problem solving in a collaborative environment. As of December 31, 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 have no collective bargaining agreements with our employees. We believe that we have good relations with our employees.
Driving and Supporting a Safety First Culture
The safety of our employees, contractors and the communities in which we operate is one of our most critical responsibilities. We believe that driving a safety first culture requires daily prioritization and includes a multi-faceted approach to provide our employees with the tools, support, education and incentives to operate safely:
● All employees, contractors and consultants performing work in the field participate in ongoing environmental, health and safety engagements, including training, routine meetings, and individual coaching;
● Work stop authority – all of our employees and contractors have a responsibility to intercede and stop observed high hazard activities or conditions without proper controls;
● Policies and procedures implemented to support a safe working environment; and
● Environmental and safety metrics measuring performance linked to compensation.
Our employees and contractors are educated on the risks inherent in our operations and are equipped with tools to help them operate safely.
Compensation and Benefits
We have designed our compensation program to attract and retain talented employees with the requisite knowledge and experience. We offer market-competitive compensation programs, as well as strong health and welfare benefits along with a competitive 401(k) program. We have designed paid time off policies to allow our employees time off for family and other priorities.
Diversity and Inclusion
We believe all employees should be treated fairly and valued in our organization. Diversity of thoughts and experiences allows us to identify the best solutions within our company. All Battalion employees must act in accordance
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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. Employees are required to acknowledge and agree to abide by these policies upon employment.
Principal Office
As of December 31, 2025, 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”. 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 . 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.