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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

Commission File Number: 001-35467

Battalion Oil Corporation

(Exact name of registrant as specified in its charter)


Delaware	20-0700684
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

820 Gessner Road, Suite 1100, Houston, TX 77024

(Address of principal executive offices)

(832) 538-0300

(Registrant’s telephone number)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock par value $0.0001	BATL	NYSE American

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive oﬃcers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

☐

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☒

Smaller reporting company ☒

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

As of March 18, 2026, there were 18,256,563 shares outstanding of registrant’s $.0001 par value common stock. The aggregate market value of shares of common stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing price on June 30, 2025 reported by the NYSE American) was approximately $5.0 million.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities made under a plan confirmed by a court. Yes ☒ No ☐

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13, and 14, is incorporated by reference to portions of the registrant’s definitive proxy statement for its 2026 annual meeting of stockholders which will be filed no later than 120 days after December 31, 2025.

Table of Contents

TABLE OF CONTENTS

		PAGE
Special note regarding forward-looking statements		3
Glossary of Oil and Natural Gas Terms		5
PART I
ITEM 1.	Business	7
ITEM 1A.	Risk factors	20
ITEM 1B.	Unresolved staff comments	39
ITEM 1C.	Cybersecurity	39
ITEM 2.	Properties	40
ITEM 3.	Legal proceedings	40
ITEM 4.	Mine safety disclosures	40
PART II
ITEM 5.	Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities	40
ITEM 6.	Reserved	40
ITEM 7.	Management’s discussion and analysis of financial condition and results of operations	41
ITEM 7A.	Quantitative and qualitative disclosures about market risk	54
ITEM 8.	Consolidated financial statements and supplementary data	55
ITEM 9.	Changes in and disagreements with accountants on accounting and financial disclosure	96
ITEM 9A.	Controls and procedures	96
ITEM 9B.	Other information	96
ITEM 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	96
PART III
ITEM 10.	Directors, executive officers and corporate governance	97
ITEM 11.	Executive compensation	97
ITEM 12.	Security ownership of certain beneficial owners and management and related stockholder matters	97
ITEM 13.	Certain relationships and related transactions, and director independence	97
ITEM 14.	Principal accountant fees and services	98
PART IV
ITEM 15.	Exhibits and financial statements schedules	98
ITEM 16.	Form 10-K Summary	100

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Special note regarding forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements, other than statements of historical facts, may be forward-looking statements, should be evaluated as such and may concern, among other things, planned capital expenditures, potential increases in oil and natural gas production, potential costs to be incurred, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. These forward-looking statements may be identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “objective,” “believe,” “predict,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section of this report and other sections of this report which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, which include, but are not limited to, the following factors:

●

volatility in prices for oil, natural gas and natural gas liquids (“NGLs”);

●

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and develop our undeveloped acreage positions;

●

contractual limitations that affect our management’s discretion in managing our business, including covenants that, among other things, limit our ability to incur debt, make investments and pay cash dividends;

●

our indebtedness, which may increase in the future, and higher levels of indebtedness can make us more vulnerable to economic downturns and adverse developments in our business;

●

our ability to replace our oil and natural gas reserves and production;

●

the presence or recoverability of estimated oil and natural gas reserves attributable to our properties and the actual future production rates and associated costs of producing those oil and natural gas reserves;

●

our ability to successfully develop our large inventory of undeveloped acreage;

●

the cost and availability of goods and services, such as drilling rigs, fracture stimulation services and tubulars, which may be subject to inflation caused by labor shortages, supply shortages and increased demand, tariffs and other inflationary pressures;

●

drilling and operating risks, including accidents, equipment failures, fires, and releases of toxic or hazardous materials, such as hydrogen sulfide (H₂S), which can result in injury, loss of life, pollution, property damage and suspension of operations;

●

senior management’s ability to execute our plans to meet our goals;

●

access to and availability of water, sand and other treatment materials to carry out fracture stimulations in our completion operations;

●

the possibility that our industry may be subject to future regulatory or legislative actions (including, but not limited to, additional taxes and changes in environmental regulations);

●

access to adequate gathering systems, processing and treating facilities and transportation take-away capacity to move our production to marketing outlets to sell our production at market prices;

●

our ability to pursue and integrate strategic mergers and acquisitions;

●

divestitures could negatively impact our business and our results of operations may be adversely affected if we fail to manage and complete divestitures;

●

the potential for production decline rates for our wells to be greater than we expect;

●

competition, including competition for acreage in our resource play;

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●

environmental risks, such as accidental spills of toxic or hazardous materials, and the potential for environmental liabilities;

●

exploration and development risks;

●

our ability to retain key members of senior management, the board of directors and key technical employees;

●

social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States (the “U.S.”), such as the political situation in Venezuela, the ongoing conflict between Ukraine and Russia and the war in the Middle East, and acts of terrorism or sabotage;

●

impacts of climate regulations or lawsuits;

●

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

●

impacts and potential risks related to actual or anticipated pandemics, including any associated impact to our operations, financial results, liquidity, contractors, customers, employees and vendors;

●

impacts and potential risks of extreme weather;

●

other economic, competitive, governmental, regulatory, legislative, including federal and state regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

●

our insurance coverage may not adequately cover all losses that we may sustain; and

●

title to the properties in which we have an interest which may be impaired by title defects.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Any forward-looking statements speak only as of this Annual Report on Form 10-K. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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Glossary of Oil and Natural Gas Terms

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent determined using a ratio of six Mcf of natural gas to one barrel of oil, condensate, or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of one-pound of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed property. Property where wells have been drilled and production equipment has been installed.

Development well. A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Extension well. A well drilled to extend the limits of a known reservoir.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Hydraulic fracturing. The injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production.

H₂S. Hydrogen sulfide, a colorless, flammable and extremely hazardous naturally occurring gas that is sometimes produced from oil and natural gas wells.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million Boe.

MMBtu. One million Btu.

MMcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs. Natural gas liquids, i.e. hydrocarbons removed as a liquid, such as ethane, propane and butane.

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Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves. Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.

Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reserve-to-production ratio or Reserve life. A ratio determined by dividing estimated existing reserves determined as of the stated measurement date by production from such reserves for the prior twelve month period.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud. Commencement of actual drilling operations.

3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

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PART I

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.

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.

●

H₂S 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.

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:

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All employees, contractors and consultants performing work in the field participate in ongoing environmental, health and safety engagements, including training, routine meetings, and individual coaching;

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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;

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Policies and procedures implemented to support a safe working environment; and

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Environmental and safety metrics measuring performance linked to compensation.

Our employees and contractors are educated on the risks inherent in our operations and are equipped with 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.

ITEM 1A. RISK FACTORS

Risk Factors Summary

The following is a summary of the principal factors that make an investment in our common stock speculative or risky.

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Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

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We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

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Failure to comply with the covenants in our 2024 Amended Term Loan Agreement may limit our ability to borrow, result in an event of default and cause amounts outstanding under our 2024 Amended Term Loan Agreement to become immediately due and payable.

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Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

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Historically, we have had substantial indebtedness and we may incur substantially more debt in the future. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

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Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of our reserves.

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We are subject to various contractual limitations that affect the discretion of our management in operating our business.

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Federal legislation and rulemaking could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

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We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

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Our ability to use net operating loss carryforwards and realized built in losses to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

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We may be required to take non-cash asset write-downs.

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Hedging transactions may limit our potential gains and increase our potential losses.

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We are substantially dependent upon our drilling success on our Delaware Basin properties.

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Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted rates of return.

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Our financial results following the sale of our West Quito Assets may not be comparable to our historical financial results and historical trends may not be indicative of our future results.

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Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases, we may be required to retain liabilities for certain matters.

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Increasing attention to environmental, social and corporate governance (“ESG”) matters may impact our business.

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We could experience periods of higher costs for various reasons, including due to higher commodity prices, increased drilling activity in the Delaware Basin and trade disputes, tariffs or inflation that affect the costs of steel and other raw materials that we and our vendors rely upon, which could adversely affect our ability to execute our exploration and development plans on a timely basis and within budget.

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We may not be able to drill wells on a substantial portion of our acreage.

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Certain of our undeveloped leasehold acreage could expire if we are unable to meet continuous development clauses or similar provisions in our leases requiring development of our undeveloped acreage and/or maintaining production on units containing the acreage.

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Our oil and natural gas activities are subject to various risks that are beyond our control.

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Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

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Our strategy involves drilling in shale formations, using horizontal drilling and modern completion techniques. The results of our drilling program using these techniques may be subject to more uncertainties than conventional drilling programs. These uncertainties could result in an inability to meet our expectations for reserves and production.

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Title to the properties in which we have an interest may be impaired by title defects.

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We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

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There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

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Future sales of our common stock in the public market or the issuance of securities senior to our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and our ability to raise funds in stock offerings.

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Our stock price has been volatile, and you may not be able to resell our common stock at or above the price you paid.

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Our failure to meet the continued listing standards of NYSE American could result in a delisting of our common stock.

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We may be unable to either redeem or pay cash dividends on the outstanding shares of our Redeemable Preferred Stock, resulting in increases in the liquidation preference of the Redeemable Preferred Stock and the right of the holders of Redeemable Preferred Stock to receive a greater number of shares of our common stock in the event such holders elect to exercise their conversion rights. Consequently, the financial and voting interests in our Company of the holders of our common stock may be diluted.

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We are subject to complex federal, state, local and other laws and regulations that frequently are amended to impose more stringent requirements that could adversely affect the cost, manner or feasibility of doing business.

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Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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Regulation or litigation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

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Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.

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Our business could be adversely impacted by events beyond our control, including economic downturns, inflation, tariffs, increases in interest rates, natural disasters, public health crises such as pandemics, political crises, geopolitical events such as the conflict in Venezuela, Russia and Ukraine and the Middle East, or other

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macroeconomic conditions, which have in the past and may in the future result in adverse operating and financial results.

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A financial downturn could negatively affect our business, results of operations, financial condition and liquidity.

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We depend on computer, telecommunications and information technology systems to conduct our business, and failures, disruptions, cyber-attacks or other breaches in data security could significantly disrupt our business operations, create liability and increase our costs.

Financial and Liquidity Risk Factors

Oil, natural gas and NGLs and natural gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability, future growth and the carrying value of our properties depend substantially on prevailing oil, natural gas and NGLs prices. Prices also affect the amount of cash flow we have available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties.

Oil, natural gas and NGLs prices are volatile. Among the factors that affect volatility are:

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domestic and foreign supplies of oil, natural gas and NGLs and natural gas;

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the ability of members of the Organization of Petroleum Exporting Countries and other oil exporting countries, including Russia, to agree upon and maintain production quotas;

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social unrest and political instability, particularly in major oil and natural gas producing regions outside the U.S., such as Venezuela, Russia and Ukraine and the Middle East, and armed conflict or terrorist attacks;

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the level of consumer demand for oil and natural gas, including demand growth in developing countries, such as China and India;

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labor unrest in oil and natural gas producing regions;

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weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand for oil and natural gas;

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the price and availability of alternative fuels and energy sources;

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the price and availability of foreign imports and domestic exports; and

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worldwide and regional economic and political conditions impacting the global supply and demand for oil and natural gas, which may be driven by many factors, including sanctions, import and export restrictions, climate change initiatives and environmental protection affects, health epidemics (such as the global COVID-19 coronavirus outbreak) and numerous other factors.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

We may have difficulty financing our planned capital expenditures which could adversely affect our growth.

Our business requires substantial capital expenditures primarily to fund our drilling program. We may also continue to selectively increase our acreage position, which would require capital in addition to the capital necessary to drill on our existing acreage. It is possible that we will acquire acreage in other areas that we believe are prospective for oil and natural gas production and expend capital to develop such acreage. We expect to use a portion of the proceeds from the sale of our West Quito Assets and from the sales of redeemable convertible preferred stock, if necessary, and which may be difficult or limited to access, to fund capital expenditures that are in excess of our operating cash flow and cash on hand.

Additionally, certain segments of the investor community have negative sentiment towards investing in our industry, with some investors and investment advisors adopting policies negatively impacting investment in the oil and gas sector based on social and environmental considerations. Commercial and investment banks have also come under pressure to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental

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activism and initiatives aimed at limiting climate change and reducing air pollution, could potentially result in a reduction of available capital funding for development projects, thus impacting future financial results.

If we are unable to raise sufficient capital to fund our capital expenditures, we may be required to curtail our drilling, development, land acquisitions and other activities, which could result in a decrease in our production of oil and natural gas, forfeiture of leasehold interests if we are unable or unwilling to renew them, and the sale of some of our assets on an unfavorable basis, each of which could have a material adverse effect on our results and future operations.

On December 26, 2024, we entered into the 2024 Term Loan Agreement with Fortress Credit Corp. Pursuant to the 2024 Term Loan Agreement, we were provided (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. On January 9, 2025, we entered into the First Amendment to our 2024 Term Loan Agreement and incurred incremental term loans in the aggregate principal amount of $63.0 million. On November 12, 2025, we entered into the Second Amendment to the 2024 Amended Term Loan Agreement to amend certain financial covenants, as described in more detail in Item 1. Business – Recent Developments.

As of December 31, 2025, we had approximately $208.1 million of indebtedness outstanding under the 2024 Amended Term Loan Agreement and no additional borrowing capacity under the 2024 Amended Term Loan Agreement. Additionally, our 2024 Amended Term Loan Agreement contains certain covenants as well as a mandatory repayment schedule requiring us to make scheduled amortization payments in the aggregate amount of $22.5 million in both 2026 and 2027. The 2024 Amended Term Loan Agreement matures on December 26, 2028.

Our 2024 Amended Term Loan Agreement contains the following financial covenants (as defined), including the maintenance of the following ratios:

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Asset Coverage Ratio not to fall below 1.85x as of December 31, 2025 through and including December 31, 2026 and 2.00x for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

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Total Net Leverage Ratio not to exceed 3.20x as of December 31, 2025, 3.25x as of March 31, 2026 and not to exceed the levels set forth in Item 1. Business – Recent Developments for each fiscal quarter thereafter, determined as of the last day of each fiscal quarter;

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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; and

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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.

In the past, we have periodically sought amendments to the covenants under our revolving credit agreements, including the financial covenants, where we have anticipated difficulty in maintaining compliance. While historically we have largely been successful in obtaining modifications of our covenants as needed, as evidenced most recently by the Second Amendment to our 2024 Amended Term Loan Agreement, there can be no assurance that we will be successful in the future. In the event we are not successful in obtaining covenant modifications, if needed, there is no assurance that we will be successful in implementing alternatives that allow us to maintain compliance with our covenants or that we will be successful in obtaining alternative financing that provides us with the liquidity that we need to operate our business. Even if successful, alternative sources of financing could prove more expensive than borrowings under our 2024 Amended Term Loan Agreement. Failure to comply with the covenants in our 2024 Amended Term Loan Agreement may limit our ability to borrow, result in an event of default and cause amounts outstanding under our 2024 Amended Term Loan Agreement to become immediately due and payable.

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Unless we replace our reserves, our reserves and production will decline, which would adversely affect our financial condition, results of operations and cash flows.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Decline rates are typically greatest early in the productive life of a well. Estimates of the decline rate of an oil or natural gas well are inherently imprecise, and are less precise with respect to new or emerging oil and natural gas formations with limited production histories than for more developed formations with established production histories. Our production levels and the reserves that we currently expect to recover from our wells will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Our future oil and natural gas reserves and production and, therefore, our cash flows and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, our cash flows and the value of our reserves may decrease, adversely affecting our business, financial condition, results of operations and cash flows.

We have substantial indebtedness and we may incur substantially more debt in the future. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.

We had $208.1 million principal amount of debt, including current portions, as of December 31, 2025 and as of the date of this Annual Report on Form 10-K. As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, and outstanding principal during 2026, which will reduce the amount of cash flow we will have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes or adverse developments in our business or economic downturns impacting the industry in which we operate. Indebtedness under our 2024 Amended Term Loan Agreement is at a variable interest rate, and so a rise in interest rates will generate greater interest expense to the extent we do not have hedging arrangements that are effective in offsetting interest rate fluctuations. A rise in interest rates could impact on our borrowing costs and could have an adverse effect on our cash flows. Borrowings under the 2024 Amended Term Loan Agreement initially bore interest at a rate per annum equal to the Secured Overnight Financing Rate (“SOFR”) (with a credit spread of adjustment of 0.15% per annum) plus an applicable margin of 7.75%. Under the Second Amendment, the Applicable Margin (as defined in the 2024 Amended Term Loan Agreement) is to be the rate per annum set forth below under the caption “SOFR Loans Spread” or “ABR Loans Spread”, as the case may be, based on the Total Net Leverage Ratio set forth in the table above in Item 1. Business – Recent Developments; provided that (a) until the Adjustment Date (the date of delivery of financial statements pursuant to the 2024 Amended Term Loan Agreement) following the Second Amendment effective date, the Applicable Margin shall be the applicable rate per annum set forth below in Category 1 and (b) the Applicable Margin shall be the applicable rate per annum set forth in Category 4 below at any time that an Event of Default (as defined in the 2024 Amended Term Loan Agreement) exists:


Total Net Leverage Ratio	SOFR Loans Spread	ABR Loans Spread
Category 1 ≤ 2.50 to 1.00	7.75%	6.75%
Category 2 > 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3 > 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4 > 3.25 to 1.00	8.50%	7.50%

The Applicable Margin shall be adjusted quarterly on a prospective basis on each Adjustment Date based upon the Total Net Leverage Ratio in accordance with the table above.

We may incur substantially more debt in the future. Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors,

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many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional shares of common or preferred stock on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

Estimates of proved oil and natural gas reserves involve assumptions and any material inaccuracies in these assumptions will materially affect the quantities and the value of our reserves.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. The process of estimating oil and natural gas reserves in accordance with SEC requirements is complex, involving significant estimates and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The estimates of our reserves as of December 31, 2025 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, in accordance with SEC requirements, estimates of oil and gas reserves, future net revenue from proved reserves and the present value of our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the 12-month first-day-of-the-month average oil and gas prices for the year ended December 31, 2025. Average prices for oil and natural gas for the 12-month period were as follows: 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. Any significant variance in the actual future prices from these assumptions could materially affect the estimated quantity and value of our reserves set forth in this report.

In addition, at December 31, 2025, approximately 40% of our estimated proved reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Estimated proved reserves as of December 31, 2025 assume that we will make future capital expenditures of approximately $270.3 million in the aggregate primarily from 2026 through 2029, which are necessary to develop and realize the value of proved reserves on our properties. The estimates of these oil and natural gas reserves and the costs associated with development of these reserves have been prepared in accordance with SEC regulations; however, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.

We are subject to various contractual limitations that affect the discretion of our management in operating our business.

Our 2024 Amended Term Loan Agreement contains various provisions that may limit our management’s discretion in certain respects. In particular, the 2024 Amended Term Loan Agreement limits our and our subsidiaries’ ability to, among other things:

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pay dividends on, redeem or repurchase shares of our common stock and any other capital stock we may issue;

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make loans to others;

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make investments;

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incur additional indebtedness;

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create certain liens;

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sell assets;

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enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;

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consolidate, merge or transfer all or substantially all of our assets and those of our restricted subsidiaries taken as a whole;

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engage in transactions with affiliates;

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increase our exposure to commodity price fluctuations;

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create unrestricted subsidiaries; and

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enter into sale and leaseback transactions.

Compliance with these and other limitations may limit our ability to operate and finance our business and engage in certain transactions in the manner we might otherwise. In addition, if we fail to comply with the limitations under our 2024 Amended Term Loan Agreement, our creditors, to the extent the agreement so provides, may accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make further funds available to us.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) established, among other provisions, federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities that participate in that market. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail or alter their derivative activities.. The Dodd-Frank Act also created new categories of regulated market participants, such as "swap dealers" and "security-based swap dealers" that are subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements, a large number of which have been implemented. This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as us. In particular, new margin requirements and capital charges, even when not directly applicable to us, have increased the pricing of derivatives that we transact in. New exchange trading margin regulations, trade reporting requirements and position limits may lead to changes in the liquidity of our derivative transactions or higher pricing. That said, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with the Dodd-Frank Act. Additionally, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under applicable federal and exchange-mandated position limits rules and are not materially impacted by the limitations under such rules.

The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses that may be sustained in connection with all oil and natural gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:

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personal injury;

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bodily injury;

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third party property damage;

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medical expenses;

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legal defense costs;

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pollution in some cases;

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well blowouts in some cases; and

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workers compensation.

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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 financial position, results of operations and cash flows.

Our ability to use net operating loss carryforwards and realized built in losses to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses (“NOLs”), and realized built in losses (“RBILs”), to offset future taxable income. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders (generally 5% stockholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders’ lowest percentage ownership during the testing period (generally three years).

We experienced ownership changes in December 2018 and October 2019 and we may experience additional ownership changes in the future. Limitations imposed on our ability to use NOLs and RBILS to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs and RBILS to expire unused, in each case reducing or eliminating the benefit of such NOLs and RBILS. Similar rules and limitations may apply for state income tax purposes. As of December 31, 2025, no additional ownership change has occurred.

We may be required to take non-cash asset write-downs.

We may be required under full cost accounting rules to write-down the carrying value of oil and natural gas properties if oil and natural gas prices decline or if there are substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. We utilize the full cost method of accounting for oil and natural gas exploration and development activities. Under full cost accounting, we are required by SEC regulations to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of oil and natural gas properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using the unweighted arithmetic average of the first day of each month for the 12-month period ending at the balance sheet date. If the net book value of oil and natural gas properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, SEC regulations require us to impair or “write-down” the book value of our oil and natural gas properties.

Costs associated with unevaluated properties, which were approximately $48.0 million at December 31, 2025, are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the ceiling test limitation. Accordingly, a significant change in these factors, many of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to depletion and the ceiling test limitation.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids production and comply with the requirements of our 2024 Amended Term Loan Agreement, we have entered into oil and natural gas hedging arrangements with respect to a portion of our anticipated production and we may enter into

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additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

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our production is less than expected;

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there is a widening of price differentials between delivery points for our production; or

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the counterparties to our hedging agreements fail to perform under the contracts.

Operational Risk Factors

We are substantially dependent upon our drilling success on our Delaware Basin properties.

We are a pure-play, single-basin operator in the Delaware Basin in West Texas. As a consequence of this geographical concentration, we may have greater exposure to the impact of regional supply and demand factors, delays or interruptions in production from governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, or other conditions adversely impacting our ability to produce or market our production. Such events could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted rates of return.

Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that our leasehold acreage will be profitably developed, that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results is dependent upon current and future market prices for our oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. The costs of drilling and completing a well are often uncertain, and are affected by many factors, including:

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unexpected drilling conditions;

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pressure or irregularities in formations;

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equipment failures or accidents and shortages or delays in the availability of drilling and completion equipment and services;

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adverse weather conditions; and

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compliance with governmental requirements.

If we are unable to accurately predict and control the costs of drilling and completing a well, we may be forced to limit, delay or cancel drilling operations.

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Our financial results following the sale of our West Quito Assets may not be comparable to our historical financial results and historical trends may not be indicative of our future results.

We entered into a sale and purchase agreement 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 on December 18, 2025, with an accounting effective date of December 1, 2025. The West Quito Assets included approximately 6,100 net acres in Ward County, Texas and proved reserves for these properties accounted for approximately 6.0 MMBoe, or approximately 10%, of our proved reserves at December 31, 2025 and approximately 15% of our annual production for the year ended December 31, 2025. As a result, our historical financial results will not be comparable to our future results and historical trends may not be indicative of results expected in future periods.

From time to time, we may sell assets or interests in an asset for the purpose of assisting or accelerating the asset’s development, most recently our West Quito Divestiture, and we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and prices acceptable to us.

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Increasing attention to ESG matters may impact our business.

Companies conducting oil and natural gas activities, like many firms in other industries, are facing increased scrutiny from stakeholders related to their ESG policies and practices. Stakeholder expectations and standards around ESG are evolving and companies that do not adapt or comply with those expectations and standards, regardless of whether there is a legal requirement to do so, may be adversely impacted. Increased attention to ESG matters may impact our business by increasing costs, reducing demand for oil and natural gas, reducing profits, increasing regulations and litigation, or impeding our access to capital and may negatively impact our stock price.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their ESG approaches. Currently, there are no universal standards for scores or ratings; however, the importance of sustainability evaluations is becoming more broadly accepted and utilized by investors and stockholders. Unfavorable ratings or assessment of our ESG practices may lead to negative investor sentiment toward us, which could have a negative impact on our stock price and our access to capital.

Our industry is cyclical. When oil, natural gas and NGLs prices increase, shortages of drilling rigs, equipment, supplies, water or qualified personnel may result. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production, particularly in the Delaware Basin, likewise may increase demand for oilfield services and equipment, and the costs of these services and

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equipment may increase, while the quality of these services and equipment may suffer. Cost increases may also result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other materials that we and our vendors rely upon and increases in the cost of services to process, treat and transport our production. Any escalation or expansion of tariffs could result in higher costs and affect a greater range of materials we rely upon in our business. The unavailability or high cost of drilling rigs, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability. In order to secure drilling rigs and pressure pumping equipment and related services, we may enter into contracts that extend over several months or years. If demand for drilling rigs and pressure pumping equipment subside during the period covered by these contracts, the price we are required to pay may be significantly more than the market rate for similar services.

We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate enough cash flow from operations or be able to raise sufficient capital to do so. Commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we conduct may not be successful or result in additional proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

As of December 31, 2025, we owned leasehold interests in approximately 37,600 net acres in the Delaware Basin in West Texas of which approximately 2,400 net acres are undeveloped and approximately 6,100 net acres are to be divested in the West Quito Divestiture. Generally, our oil and natural gas leases remain in force as long as production in paying quantities is maintained. Currently, our leases on undeveloped oil and natural gas properties are either categorized as “held by production” or perpetuated by continuous development clauses contained in our leases or tolling agreements. We continually review our leases on acreage subject to these clauses or agreements when planning for our future drilling programs. If our leases on acreage subject to these provisions are not maintained by production in paying quantities or continuous development, our leases could expire and we would lose our right to develop the related properties.

Our drilling plans are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, while not material, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. As a non-operating leaseholder we have less control over the timing of drilling and are therefore subject to additional risk of expirations.

Our oil and natural gas activities are subject to various risks that are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and natural gas. Although we take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce oil and natural gas in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest. Such risks and hazards include:

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human error, accidents and other events beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

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blowouts, fires, adverse weather events, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

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accidental releases of natural gas, including gas with high levels of hydrogen sulfide (H2S), and other hydrocarbons or toxic or hazardous materials into the environment as a result of human error or the malfunction of equipment or facilities, which can result in personal injury and loss of life, pollution, damage to equipment and suspension of operations;

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well-on-well interference that may reduce recoveries;

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unavailability of materials and equipment;

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engineering and construction delays;

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unanticipated transportation costs and delays;

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unfavorable weather conditions;

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hazards resulting from unusual or unexpected geological or environmental conditions;

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changes in laws and regulations, including laws and regulations applicable to oil and natural gas activities or markets for the oil and natural gas produced;

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fluctuations in supply and demand for oil and natural gas causing variations of the prices we receive for our oil and natural gas production; and

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the availability of alternative fuels and the price at which they become available.

Some of these risks may be exacerbated by other risks that we face. For instance, certain of our wells produce high levels of H₂S, a highly toxic, naturally-occurring gas frequently associated with oil and natural gas production. Safely handling H₂S gas requires complex operations and highly skilled field personnel as well as specialized infrastructure, treating facilities, disposal facilities, and/or third-party sour gas takeaway. If we are unable to attract and retain qualified and highly skilled personnel, our ability to effectively manage this and other risks may be adversely impacted. Additionally, if we are unable to successfully operate our specialized treating facilities or secure adequate sour gas takeaway capacity from third parties when and if necessary, our ability to effectively manage the H₂S levels we see in our natural gas production may be adversely impacted and our processing costs may increase. As a result, our production, revenues, operating costs and liabilities and expenses may be materially and adversely affected and may differ materially from those anticipated by us.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of natural gas, condensate or oil being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems available in our operating areas, it may be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks or trains to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions, the availability and cost of capital, public opposition, regulatory restrictions and judicial challenges. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut-in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently expect, which would adversely affect our results of operations.

A portion of our production may also be interrupted, or shut-in, from time to time for numerous other reasons, including as a result of weather conditions (which may worsen due to climate changes), accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

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The drilling of long horizontal laterals and the use of modern completion techniques with multi-stage fracture stimulation in shale formations involves certain risks and complexities that do not exist in conventional wells. Such risks include, but are not limited to, landing the horizontal wellbore in the desired drilling zone, maintaining the desired drilling zone while drilling horizontally through the wellbore formation, running casing through the full span of the wellbore, and being able to run tools and other necessary equipment consistently throughout the horizontal wellbore. Additionally, horizontal drilling and completion techniques may result in faster production decline rates relative to conventional drilling methods. The ultimate success of our drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established.

If our drilling results are less than anticipated, our investment in these areas may not be as attractive as we anticipate and could result in material write-downs of unevaluated properties and future declines in the value of our undeveloped acreage.

Title to the properties in which we have an interest may be impaired by title defects.

We generally obtain title opinions on significant properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

Our success depends upon the continued contributions of our executive officers and key employees, particularly with respect to providing the critical management decisions and contacts necessary to manage and maintain growth within a highly competitive industry. Competition for qualified personnel can be intense, particularly in the oil and natural gas industry, and there are a limited number of people with the requisite knowledge and experience. Under these conditions, we could be unable to attract and retain these personnel. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

Investment in Securities Risk Factors

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds advised by Luminus Management, LLC, Oaktree Capital Management, LP, and LSP Investment Advisors, LLC held approximately 34%, 22% and 13%, respectively, of our common stock as of March 18, 2026. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures, or the issuance of additional equity securities or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

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A large percentage of our shares of common stock are held by a relatively small number of investors. Sales by us or our stockholders of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could cause the market price of our common stock to decline or could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.

We are currently authorized to issue 100.0 million shares of common stock and 1.0 million shares of preferred stock, with such designations, rights, preferences, privileges and restrictions as determined by the Board. As of March 18, 2026, we had approximately 18.3 million shares of common stock outstanding and options and restricted stock units to purchase or receive an aggregate of 0.1 million shares of our common stock. As of March 18, 2026, we have also reserved an additional 1.3 million shares for future issuance to our directors, officers and employees under our 2020 Long-Term Incentive Plan. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock.

We may issue common stock or other equity securities senior to our common stock in the future for a number of reasons, including to finance acquisitions, to adjust our leverage ratio, and to satisfy our obligations upon the exercise of warrants and options, or for other reasons. We cannot predict the effect, if any, that future sales or issuances of shares of our common stock or other equity securities, or the availability of shares of common stock or such other equity securities for future sale or issuance, will have on the trading price of our common stock.

Our stock price has been volatile, and you may not be able to resell our common stock at or above the price you paid.

Our stock price has been highly volatile in recent years. Such volatility may continue in response to various factors, some of which are beyond our control, including:

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market conditions in the broader stock market;

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fluctuations in the values of companies perceived by investors to be comparable to us;

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sales, or the anticipation of sales, of our common stock by us, our insiders or our other stockholders, including the impacts if we are no longer a controlled company;

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public response to press releases or other public announcements by us or third parties, including our filings with the SEC; and

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the realization of any risks described under this “Risk Factors” section, or other risks that may materialize in the future.

These and other factors, many of which are beyond our control, may cause our operating results and the market price and demand for our common stock to fluctuate substantially. While we are of the view that operating results for any particular quarter are not necessarily a meaningful indication of future results, fluctuations in our quarterly operating results may negatively affect the market price and liquidity of our stock. In addition, in the past, when the market price of a stock has been volatile, holders of that stock have sometimes instituted securities class action litigation against the company that issued the stock. If any of our stockholders brought a lawsuit against us, we could incur substantial costs defending and/or settling the lawsuit, a portion or all of which may not be covered by insurance. Settlement and verdict damages from securities class action lawsuits are often material. Such a lawsuit could also divert the time and attention of our management from our business, which could significantly harm our profitability and reputation.

In addition, the stock markets, and the market for growth stocks in particular, have from time to time experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of those companies. Broad market and industry factors may significantly affect the market price of our common stock, regardless of our actual operating performance. You may not realize any return on your investment in us and may lose some or all of your investment.

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Our failure to meet the continued listing requirements of NYSE American could result in a delisting of our common stock.

If we fail to satisfy the continued listing requirements of NYSE American, such as minimum financial and other continued listing requirements and standards, including those regarding minimum stockholders’ equity, minimum share price and certain corporate governance requirements, the NYSE may take steps to delist our common stock. Such a delisting would likely have a negative effect on the price of our common stock and would impair your ability to sell or purchase our common stock when you wish to do so. In the event of a delisting, we would expect to take actions to restore our compliance with NYSE American’s listing requirements, but we can provide no assurance that any such action taken by us would allow our common stock to become listed again, stabilize the market price or improve the liquidity of our common stock, prevent our common stock from dropping below the NYSE minimum bid price requirement or prevent future non-compliance with NYSE’s listing requirements.

On May 30, 2025, we received written notice (the “Notice”) on behalf of the NYSE American indicating that we are no longer in compliance with NYSE American’s continued listing standards. Specifically, the letter stated that we are not in compliance with the continued listing standards set forth in Sections 1003(a)(i) and 1003(a)(ii) of the NYSE American Company Guide (the “Company Guide”). Section 1003(a)(i) requires a listed company to have stockholders’ equity of $2.0 million or more if the listed company has reported losses from continuing operations and/or net losses in two of its three most recent fiscal years. Section 1003(a)(ii) requires a listed company to have stockholders’ equity of $4.0 million or more if the listed company has reported losses from continuing operations and/or net losses in three of its four most recent fiscal years. Our noncompliance resulted from our reporting stockholders’ equity of $(1.8) million as of March 31, 2025, and losses from continuing operations and/or net losses in three of our four most recent fiscal years ended December 31, 2024. We continue to report negative stockholders’ equity at December 31, 2025 of $(32.8) million and additional losses from continuing operations. The Notice further provided that we must submit a plan of compliance (the “Plan”) by June 30, 2025 addressing how we intend to regain compliance with the continued listing standards by November 30, 2026. Such Plan was submitted by the required deadline and our Plan was accepted by the NYSE. The Notice has no immediate impact on the listing of our shares of common stock, which will continue to be listed and traded under the symbol “BATL” on the NYSE American during this period, subject to our compliance with the other listing requirements of the NYSE American. The notice does not affect our ongoing business operations or our reporting requirements with the Securities and Exchange Commission.

We may be unable to either redeem or pay cash dividends on the outstanding shares of our Redeemable Preferred Stock, resulting in increases in the liquidation preference of the Redeemable Preferred Stock and the right of the holders of the Redeemable Preferred Stock to receive a greater number of shares of our common stock in the event such holders elect to exercise their conversion rights. Consequently, the financial and voting interests in our Company of the holders of our common stock may be diluted.

As noted elsewhere herein, the Company has issued shares of Redeemable Preferred Stock with an initial aggregate liquidation value of $138.0 million. Dividends are payable on the Redeemable Preferred Stock at a rate of 14.5% per annum; however, in the event the Company does not declare and pay dividends in cash when due, the dividend rate increases to 16.0% per annum and is added to the liquidation value of the Redeemable Preferred Stock. The Company has heretofore not paid dividends on the Redeemable Preferred Stock in cash and is not expected to in the future. Accordingly, the liquidation value of the Redeemable Preferred Stock is increasing and would be expected to increase in the future. In addition to other rights, the holders of the Redeemable Preferred Stock are also entitled generally to convert their shares of Redeemable Preferred Stock into shares of our common stock by dividing a “conversion price” specified in the terms of the Redeemable Preferred Stock into the then current liquidation preference of the Redeemable Preferred Stock, such that increases in the liquidation preference may ordinarily result in an increase in the number of shares of common stock received by such holder upon conversion. Accordingly, if the Company is unable to redeem the Redeemable Preferred Stock or is unable to pay, or elects not to pay, dividends on the Redeemable Preferred Stock in cash, the liquidation preference of the Redeemable Preferred Stock will continue to increase, thereby diluting the financial interests of the holders of our common stock in our Company and diluting the voting interests of the holders of our common stock to the extent holders of the Redeemable Preferred Stock elect to convert such shares into shares of our common stock.

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Regulatory Risk Factors

Companies that explore for, develop, produce, sell and transport oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental, health and safety laws and corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our activities, we may not be able to conduct our operations as planned. We also may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

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water discharge and disposal permits for drilling operations;

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drilling bonds;

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drilling permits;

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reports concerning operations;

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air quality, air emissions, noise levels and related permits;

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spacing of wells;

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rights-of-way and easements;

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unitization and pooling of properties;

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pipeline construction;

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gathering, transportation and marketing of oil and natural gas;

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taxation; and

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waste transport and disposal permits and requirements.

Failure to comply with applicable laws may result in the suspension or termination of operations and subject us to liabilities, including administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, the laws governing our operations or the enforcement thereof could change in ways that substantially increase our costs of doing business. For example, negative public perception regarding us and/or our industry may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Under environmental, health and safety laws and regulations, we also could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages including the assessment of natural resource damages. Such laws may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling and pipeline projects. Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities. In addition, our activities are subject to regulation relating to conservation practices and protection of correlative rights. Such regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. Delays in obtaining regulatory approvals or necessary permits, the failure to obtain a permit or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on, develop or produce our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. By way of example, in 2015 the EPA lowered the primary national ambient air quality standard for ozone from 75 parts per billion to 70 parts per billion. Implementation eventually could result in more stringent emissions controls and additional permitting obligations for our operations.

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Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Federal, state and local governments have been adopting or considering restrictions on or prohibitions of fracturing in areas where we currently conduct operations, or may in the future, plan to conduct operations. Consequently, we could be subject to additional levels of regulation, operational delays or increased operating costs and could have additional regulatory burdens imposed upon us that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

From time to time, for example, legislation has been proposed in Congress to require more stringent federal control or outright bans of hydraulic fracturing. Further, 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 for additional federal regulatory control.

Certain states, including Texas where we conduct our operations, likewise are considering or have adopted more stringent requirements for various aspects of hydraulic fracturing operations, such as permitting, disclosure, air emissions, well construction, seismic monitoring, waste disposal and water use. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have extended to bans on hydraulic fracturing.

The proliferation of regulations may limit our ability to operate. If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Various studies 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 international negotiations over climate change and greenhouse gases are continuing. Meanwhile, 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, emission 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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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 Administrations 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.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that cause or contribute to significant greenhouse gas emissions. Such cases may seek emissions reductions, challenge air emissions or other permits or request damages for alleged climate change impacts to the environment, people, and property.

Any new initiatives that may be adopted to reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our products.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water from local sources to use in our operations, we may be unable to economically produce oil, natural gas liquids and natural gas, which could have an adverse effect on our business, financial condition and results of operations. Wastewaters from our operations typically are disposed of via underground injection. Some studies have linked earthquakes in certain areas to underground injection, which is leading to greater public scrutiny and regulation of disposal wells. Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

Macroeconomic Risk Factors

The global economy, including credit and financial markets, has experienced extreme volatility and disruptions,

including, among other things, severely diminished liquidity and credit availability, declines in consumer confidence, declines in economic growth, supply chain shortages, increases in inflation rates and tariffs, higher interest rates and uncertainty about economic stability.

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In order to manage the inflation risk present in the U.S.’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between 2022 and 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.75% in 2024 and 2025. While inflationary pressures in the U.S.’ economy have begun to subside, it is uncertain what impact recent tariff activity by the U.S. and foreign governments will have on inflation. Higher interest rates, coupled with reduced government spending and volatility in financial markets may increase economic uncertainty and affect consumer spending. If the equity and credit markets deteriorate, including as a result of political unrest or war, it may make any necessary debt or equity financing more difficult to obtain in a timely manner or on favorable terms, more costly or more dilutive. Increased inflation rates can adversely affect us by increasing our costs, including labor and employee benefit costs.

A widespread public health crisis such as a pandemic could result in significant disruption of global financial markets, reducing our ability to access capital, which could negatively affect our liquidity. In addition, a recession or market correction resulting from the effects of public health crises could materially affect our business and the value of our common stock. It may have further negative impacts, such as (a) a global or U.S. recession or other economic crisis; (b) credit and capital markets volatility (and access to these markets, including by our suppliers and customers); (c) manufacturing supply disruption due to travel restrictions or other government actions; and (d) disruptions services and supplies. The ultimate impact of a public health crisis is highly uncertain.

A financial downturn could negatively affect our business, results of operations, financial condition and liquidity.

Actual or anticipated declines in domestic or foreign economic growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price we receive for our oil and natural gas production. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations and cash flows.

Cybersecurity Risk Factors

The oil and natural gas industry in general has become increasingly dependent upon technology to conduct day-to-day operations, including certain exploration, development and production activities. We have agreements with third parties for hardware, software, telecommunications and other information technology services necessary to our business and have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We use these systems and data to, among other things, estimate quantities of oil, natural gas liquids and natural gas reserves, process and record financial data and communicate with our employees and third parties. Failures in these systems due to hardware or software malfunctions, computer viruses, natural disasters, fire, human error or other causes could significantly affect our ability to conduct our business. In particular, cybersecurity attacks on systems are increasing in frequency and sophistication and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to them, there can be no assurance that these procedures and controls will be sufficient to prevent security threats from materializing and any interruptions to our arrangements with third parties, to our computing and communications infrastructure or our information systems could significantly disrupt our business operations. Further, the loss or corruption of sensitive information could have a material adverse effect on our reputation, financial position, results of operations or cash flows. In addition, as cyber-attacks continue to evolve, we may be required to

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expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Risk Management and Strategy

We rely on information technology to operate our business. We have endpoint and other protection systems, and incident response processes, both internally and through third-party experts designed to protect our information technology systems. These established processes assist us to continuously assess and identify threats to our systems and minimize impact to our business in the event of a breach or other security incident. With our third-party consultants, the processes protect our information systems and allow us to resolve any issue which may arise in the most timely and aggressive fashion. Our internal auditors perform audit engagements to assess our strategies, policies, procedures, and controls to reduce the risk of a cybersecurity incident.

As any new threat to security may be identified, our personnel are notified, with instruction to increase awareness of the threat and how to react if such a threat or actual breach appears to be encountered. Periodic educational notices are also disseminated to all personnel. Additionally, as our systems are modified and upgraded, all personnel are notified, with instruction as appropriate. With the assistance and advice of our expert consultants, responsibility for the identification and assessment of risks and the recommendation of upgrades to our systems resides with our Director of Information Technology, who reports to our Chief Executive Officer. Our Director of Information Technology has more than 16 years of information technology experience.

Governance

Our Board oversees the risks involved in our operations as part of its general oversight function, integrating risk management into our compliance policies and procedures. With respect to cybersecurity, the Board has the ultimate oversight responsibility, with the Audit Committee of the Board having certain responsibilities relating to risk management of cybersecurity.

Among other things, the Audit Committee discusses with management the Company’s major policies with respect to risk assessment and risk management, including cybersecurity, as they relate to the integrity of the Company’s accounting and financial reporting processes and the Company’s compliance with legal and regulatory requirement.

In addition, the Audit Committee, with the assistance and advice of Company management and third-party consultants, oversees operational information technology risks, including cybersecurity, as they relate to the technical aspects of the Company’s operations. The Audit Committee receives periodic reports from Company management regarding cybersecurity risk factors.

The Board routinely receives information and updates from Company management and the Audit Committee with respect to the effectiveness of the Company’s information systems’ security framework, which may include cybersecurity assessments, risk management, and mitigation measures. The Board will also be provided updates on any material incidents relating to information systems security and cybersecurity incidents. As discussed above, we maintain endpoint and other protection systems, and incident response processes, both internally and through third-party experts.

We have not identified an indication of a substantive cybersecurity incident that would have a material impact on our business, results of operations or financial statements. For additional information regarding risks from cybersecurity threats, please refer to Item 1A. Risk Factors above.

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ITEM 2. PROPERTIES

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for us to conduct business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Item 8. Consolidated Financial Statements and Supplementary Data—Note 10, “Commitments and Contingencies,” and is incorporated herein by reference.

Under rules promulgated by the SEC, administrative or judicial proceedings arising under any federal, state or local provisions that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment are disclosed if the governmental authority is party to such proceeding and the proceeding involves potential monetary sanctions of $300,000 or more. We are not party to any such proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

On February 20, 2020, our common stock commenced trading on the NYSE American exchange under the symbol “BATL.” Approximately 50 registered stockholders of record as of March 18, 2026 held our common stock. In most instances, a registered stockholder holds shares in street name for one or more customers who beneficially own the shares.

We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant. We are also restricted from paying cash dividends on common stock under our 2024 Amended Term Loan Agreement.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

None.

Recent Sales of Unregistered Securities

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.

ITEM 6. RESERVED

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. For more information, see “Special note regarding forward-looking statements.”

Overview

We are an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States (“U.S.”). Our properties and drilling activities are currently focused in the Delaware Basin of West Texas, where we have an extensive drilling inventory that we believe offers attractive economics.

Our financial results depend upon many factors but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

When commodity prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. While we use derivative instruments to provide partial protection against declines in oil and natural gas prices, the total volumes we hedge are less than our expected production, vary from period to period based on our view of current and future market conditions, remain consistent with the requirements in effect under our 2024 Amended Term Loan Agreement and extend, on a rolling basis, for the next four years. These limitations result in our liquidity being susceptible to commodity price declines. Additionally, while intended to reduce the effects of volatile commodity prices, derivative transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. Our hedge policies and objectives may change significantly as our operational profile changes and/or commodities prices change. We do not enter into derivative contracts for speculative trading purposes.

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

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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 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 and proved reserves for these properties accounted for approximately 6.0 MMboe, or approximately 10%, of our proved reserves at December 31, 2025. We used $45.6 million of the net proceeds from closing to repay amounts outstanding under the 2024 Amended Term Loan Agreement on February 24, 2026 - $40.0 million pursuant to the Third Amendment 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, $12.9 million of 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.

Term Loan Credit Facility

On February 24, 2026, we entered into the Third Amendment to our 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

H₂S Treating Joint Venture

In May 2022, we entered into a joint venture agreement with Caracara to develop the AGI Facility in Winkler County, Texas. The joint venture, operating as WAT, also entered into a GTA with us for natural gas production from our Monument Draw area. Under the GTA, we were to pay a treating rate that varied based on volumes delivered to the AGI Facility and we 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 unconsolidated subsidiary. Caracara provided the initial capital for the construction of the Facility, which was expected to have an initial capacity of approximately 30 MMcf per day, and a design capacity to treat up to 10% combined concentrations for H₂S and CO₂. We initially expected the AGI Facility to be mechanically complete in early April 2023 and the facility 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. Workover operations commenced 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 to date as of September 30, 2024 on behalf of our joint venture partner in WAT. Pursuant to the terms of the agreement governing the joint venture, we believed that we had 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)

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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 at December 31, 2024.

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, including pump and other facility equipment replacement. 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. During the fourth quarter of 2025, we concluded that the fair value of our equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on our consolidated balance sheet and recorded an impairment of $1.1 million to reduce the carrying value of the investment in unconsolidated affiliate asset to zero as of December 31, 2025.

We terminated the GTA with WAT on January 19, 2026.

Capital Resources and Liquidity

Overview. Our ability to execute our operating strategy is dependent on our ability to maintain adequate liquidity and access additional capital, as needed. Our future capital resources and liquidity depend, in part, on our success in developing our leasehold interests, growing our reserves and production and finding additional reserves. Sufficient levels of available cash are required to fund capital expenditures necessary to offset inherent declines in our production and proven reserves. We generated a net loss available to common stockholders of $36.8 million for the year ended December 31, 2025 and had negative working capital of $6.5 million as of December 31, 2025. As of December 31, 2025, we had $28.0 million of cash and cash equivalents, no borrowing capacity remaining under our 2024 Amended Term Loan Agreement (see Item 8. Consolidated Financial Statements and Supplementary Date – Note 6, Debt) and a total of $22.5 million in debt repayments due under our 2024 Term Loan Agreement through December 2026. At December 31, 2025, $30.0 million remained available for issuance on or before August 31, 2026 under a support letter from the Investors. We closed on the sale of our West Quito Assets on February 24, 2026 for net proceeds of $60.1 million, of which $45.6 million was used to repay a portion of outstanding borrowings under our 2024 Amended Term Loan Agreement - $40.0 million pursuant to the Third Amendment 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, $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. 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.

Our 2024 Amended Term Loan Agreement contains certain restrictive covenants as well as a mandatory repayment schedule. We are required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the total loans outstanding.

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We continue to execute on a plan to reduce operating and capital costs to improve cash flow. We believe that, based upon our operational forecasts, cash and cash equivalents on hand, proceeds from the sale of our West Quito Assets and from the private placement equity offering, and cost reduction measures, it is probable that we will have sufficient liquidity to fund our operations, meet our debt requirements and maintain compliance with our future debt covenants as described in Item 8. Consolidated Financial Statements and Supplementary Date – Note 6 Debt for the next 12 months from the issuance of these consolidated financial statements. We will, however, continue to consider alternative liquidity sources which could include entering into other financing arrangements (e.g. future equity raises), a sale of a portion of our assets, seeking capital partners for our drilling program, pursuing strategic merger opportunities or joint ventures, the sale of the Company, or pursuing additional general and administrative or other cost reduction opportunities. Our estimates and forecasts are based upon assumptions that may prove to be incorrect due to many factors that are currently unknown, such as prevailing economic conditions, many of which are beyond our control. In the event the assumptions underlying our estimates and forecasts prove to be incorrect, our operating plans, capital requirements, and covenant compliance may be adversely impacted.

In the event our cash flows are materially less than anticipated or our costs are materially greater than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may be required to curtail drilling, development, land acquisitions and other activities to reduce our capital spending. However, significant or prolonged reductions in capital spending will adversely impact our production and may negatively affect our future cash flows.

We continuously monitor changes in market conditions and will continue to adapt our operational plans as necessary to strive to maintain sufficient liquidity, facilitate drilling on our undeveloped acreage position and permit us to selectively expand our acreage, as well as meet our debt obligations and restrictive covenants. We have been, and continue to, explore strategic transactions to address these concerns, while also looking at opportunities to significantly reduce expenses in the near term. However, there can be no assurance that, absent additional capital, reducing costs or other material favorable developments, the company will not experience liquidity and covenant compliance issues in the future.

Other Risks and Uncertainties. Our ability to complete transactions and maintain or increase our liquidity is subject to a number of variables, including our level of oil and natural gas production, proved reserves and commodity prices, the amount and cost of our indebtedness, as well as various economic and market conditions that have historically affected the oil and natural gas industry. Even if we are otherwise successful in growing our proved reserves and production, if oil and natural gas prices decline for a sustained period of time, our ability to fund our capital expenditures, complete acquisitions, reduce debt, meet our financial obligations and become profitable may be materially impacted.

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Additionally, in periods of increasing commodity prices, we continue to be at risk to supply chain issues, including, but not limited to, labor shortages, pipe restrictions and potential delays in obtaining frac and/or drilling related equipment that could impact our business. During these periods, the costs and delivery times of rigs, equipment and supplies may also be substantially greater. The unavailability or high cost of drilling rigs and/or frac crews, pressure pumping equipment, tubulars and other supplies, and of qualified personnel can materially and adversely affect our operations and profitability.

Lastly, actual or anticipated declines in domestic or foreign economic activity or growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from international conflicts, efforts to contain pandemics or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide oil demand, negatively impacting the price received for oil and natural gas production or adversely impacting our ability to comply with covenants in our 2024 Amended Term Loan Agreement. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. All of the foregoing may adversely affect our business, financial condition, results of operations, cash flows and, potentially, compliance with the covenants contained in our 2024 Amended Term Loan Agreement.

Capital Expenditures. During 2025, we spent approximately $74.6 million in capital expenditures, including drilling, completion, support infrastructure and other capital costs. During 2025, we ran one operated rig in the Delaware Basin. We drilled and cased 6.0 gross (5.6 net) operated wells, completed 6.0 gross (5.6 net), and put online 6.0 gross (5.6 net) operated wells during the year.

Debt Obligations. On December 26, 2024 (the “Initial Closing Date”), we and our wholly-owned subsidiary Halcón Holdings, LLC (the “Borrower”), entered into the 2024 Term Loan Agreement. Pursuant to the 2024 Term Loan Agreement, the lenders party thereto agreed to provide the Borrower 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 to be made available to the Borrower from January 3, 2025 until the date that is the earliest to occur of (x) the date on which such incremental term facility is fully drawn, (y) the date on which such incremental term facility is terminated and (z) January 11, 2025, subject to the satisfaction of certain conditions. On January 9, 2025, the Borrower entered into the First Amendment to its 2024 Term Loan Agreement. Pursuant to the First Amendment, the Borrower incurred $63.0 million of Incremental Term Loans.

The maturity date of the 2024 Amended Term Loan Agreement is December 26, 2028.

All obligations under the 2021 Amended Term Loan Agreement 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 in an aggregate amount of approximately $152.1 million, including accrued and unpaid interest, and to pay related fees and expenses related to the new credit agreement.

Borrowings under the 2024 Amended Term Loan Agreement initially bore interest at a rate per annum equal to a forward-looking term rate based on 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%.

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On November 12, 2025, we entered into the Second Amendment, which amended the Applicable Margin (as defined in the 2024 Amended Term Loan Agreement) to be the rate per annum set forth below under the caption “SOFR Loans Spread” or “ABR Loans Spread”, as the case may be, based on the Total Net Leverage Ratio; provided that (a) until the Adjustment Date (the date of delivery of financial statements pursuant to the 2024 Amended Term Loan Agreement) following the Second Amendment effective date, the Applicable Margin shall be the applicable rate per annum set forth below in Category 1 and (b) the Applicable Margin shall be the applicable rate per annum set forth in Category 4 below at any time that an Event of Default (as defined in the 2024 Amended Term Loan Agreement) exists:


Total Net Leverage Ratio	SOFR Loans Spread	ABR Loans Spread
Category 1 ≤ 2.50 to 1.00	7.75%	6.75%
Category 2 > 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3 > 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4 > 3.25 to 1.00	8.50%	7.50%

The Applicable Margin shall be adjusted quarterly on a prospective basis on each Adjustment Date based upon the Total Net Leverage Ratio in accordance with the table above.

The Second Amendment provides that we shall not permit the Total Net Leverage Ratio, as of the last day of each fiscal quarter (commencing with the fiscal quarter ending March 31, 2025), to be greater than the levels set forth in the following table for the applicable quarter:


Fiscal Quarter	Total Net Leverage Ratio
Fiscal quarters ending March 31, 2025 through and including June 30, 2025	2.75 to 1.00
Fiscal quarter ending September 30, 2025	2.50 to 1.00
Fiscal quarter ending December 31, 2025	3.20 to 1.00
Fiscal quarter ending March 31, 2026	3.25 to 1.00
Fiscal quarter ending June 30, 2026	3.40 to 1.00
Fiscal quarter ending September 30, 2026	3.50 to 1.00
Fiscal quarter ending December 31, 2026	3.40 to 1.00
Fiscal quarter ending March 31, 2027	3.25 to 1.00
Fiscal quarter ending June 30, 2027	3.00 to 1.00
Fiscal quarter ending September 30, 2027 and each fiscal quarter thereafter	2.50 to 1.00

Additionally, the Second Amendment provides that we shall not permit the Asset Coverage Ratio, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2025) to be less than the applicable level set forth in the following table for the applicable fiscal quarter:


Fiscal Quarter	Asset Coverage Ratio
Fiscal quarters ending March 31, 2025 through and including December 31, 2026	1.85 to 1.00
Each fiscal quarter thereafter	2.00 to 1.00

We may elect, at our option, to prepay any borrowing outstanding under the 2024 Amended Term Loan Agreement. Such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:


Period			Premium
Months 0 - 12			Make-whole amount equal to 12 months of interest plus 4.00%
Months 13 - 30			2.00%
Thereafter			0.00%

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In the event we shall receive a disapproval notice (as defined in the 2024 Term Loan Agreement) from the required lenders under the 2024 Amended Term Loan Agreement rejecting or otherwise disqualifying a proposed buyer in connection with a permitted change in control thereunder to be consummated within 12 months following the Initial Closing Date, such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:


Period			Premium
Months 0 - 9			Make-whole amount equal to 9 months of interest plus 2.00%
Months 10 - 30			2.00%
Thereafter			0.00%

We are required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding commencing with the fiscal quarter ending June 30, 2025. We may be required to make mandatory prepayments of the loans under the 2024 Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales and with excess cash on hand in excess of certain maximum levels. Subsequent to the closing of the West Quito Divestiture on February 24, 2026, we used $40.0 million of the net proceeds as prepayment of the loan per the terms of the Third Amendment.

Amounts outstanding under the 2024 Amended Term Loan Agreement are guaranteed by certain of our direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by the Company.

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

●

Asset Coverage Ratio not to fall below 1.85x as of December 31, 2025 through and including December 31, 2026 and 2.00x for each fiscal quarter thereafter (see above), determined as of the last day of each fiscal quarter;

●

Total Net Leverage Ratio not to exceed 3.20x as of December 31, 2025 and not to exceed the levels set forth in the table above 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; and

●

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; judgments; change of control; and voluntary and involuntary bankruptcy.

Changes in the level and timing of our production, drilling and completion costs, the cost and availability of transportation for our production and other factors varying from our expectations can affect our ability to comply with

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the covenants under our 2024 Amended Term Loan Agreement. As a consequence, we endeavor to anticipate potential covenant compliance issues and work with our lenders to address any such issues ahead of time.

The results presented in this Form 10-K are not necessarily indicative of future operating results. For further information regarding these risks and uncertainties on us, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K.

Cash Flow. Net (decrease) increase in cash, cash equivalents and restricted cash is summarized as follows for the periods presented (in thousands):


		Years Ended December 31,
		2025		2024
Cash flows provided by operating activities		$	39,090	$	35,355
Cash flows used in investing activities			(74,951)		(65,443)
Cash flows provided by (used in) financing activities			44,114		(7,728)
Net increase (decrease) in cash, cash equivalents and restricted cash		$	8,253	$	(37,816)

Operating Activities. Net cash flows provided by operating activities for the years ended December 31, 2025 and 2024 were $39.1 million and $35.4 million, respectively. Operating cash flows for the year ended December 31, 2025 increased from the prior year primarily due to lower gathering and transportation expense and changes in working capital. The increase in operating cash flows in 2025 were partially offset by decreased oil and natural gas revenues as a result of lower realized commodity prices and lower production volumes than the comparable prior year period.

Investing Activities. Net cash flows used in investing activities for the years ended December 31, 2025 and 2024 were approximately $75.0 million and $65.4 million, respectively.

During the year ended December 31, 2025, we spent $74.6 million on oil and natural gas capital expenditures, of which $61.7 million related to drilling and completion costs and $11.4 million related to the development of our treating equipment and gathering support infrastructure.

During the year ended December 31, 2024, we spent $64.6 million on oil and natural gas capital expenditures, of which $57.8 million related to drilling and completion costs and $5.7 million related to the development of our treating equipment and gathering support infrastructure.

Financing Activities. Net cash flows provided by financing activities for the year ended December 31, 2025 were $44.1 million compared to net cash flows used in financing activities for the year ended December 31, 2024 of $7.7 million. During the year ended December 31, 2025, we received net proceeds of $61.1 million from the incurrence of the Incremental Term Loans and repaid $16.9 million under our 2024 Amended Term Loan Agreement.

During the year ended December 31, 2024, prior to the refinancing transaction, we made principal payments of $52.4 million under our 2021 Amended Term Loan Agreement. On December 26, 2024, we entered into the 2024 Term Loan Agreement, incurring $162.0 million in borrowings, which such proceeds were used to repay all amounts outstanding under the 2021 Amended Term Loan Agreement in the amount of $147.7 million. Additionally, we incurred $8.2 million of debt issuance costs related to the new credit agreement. We received $38.8 million in proceeds from the sales and issuance of preferred stock during the year ended December 31, 2024.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our

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consolidated financial statements. Described below are the significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under U.S. GAAP. We also describe the significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, “Financial Statement Presentation and Summary of Significant Accounting Policies,” for a discussion of additional accounting policies and estimates made by management.

Oil and Natural Gas Activities

Full Cost Method

We use the full cost method of accounting for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized into a cost center (the amortization base or full cost pool). Such amounts include the cost of drilling and equipping productive wells, treating equipment and gathering support facilities costs, dry hole costs, lease acquisition costs and delay rentals. All general and administrative costs unrelated to drilling activities are expensed as incurred. The capitalized costs of our evaluated oil and natural gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations could have been significantly different had we used the successful efforts method of accounting for our oil and natural gas activities.

Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with U.S. GAAP and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depletion, depreciation and accretion expense and the full cost ceiling test limitation. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

Our estimated proved reserves for the years ended December 31, 2025 and 2024 were prepared by NSAI, an independent oil and natural gas reservoir engineering consulting firm. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8. Consolidated Financial Statements and Supplementary Data—“Supplemental Oil and Gas Information (Unaudited).”

Depletion Expense

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2025, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.52 per Boe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.56 per Boe.

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Full Cost Ceiling Test Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and could result in lower amortization expense in future periods. The present value of our estimated proved reserves (discounted at 10%) is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, it is possible that write-downs of our oil and natural gas properties could occur in the future. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Using the first-day-of-the-month average for the 12-months ended December 31, 2025 of the WTI crude oil spot price of $66.01 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2025 of the Henry Hub natural gas price of $3.39 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2025, holding all other inputs and factors constant. Based on SEC prices as of March 1, 2026, the prices utilized in the first quarter 2026 full cost ceiling test limitation calculation will be $63.80 per barrel of oil and $3.72 per MMBtu of natural gas. Applying these first quarter 2026 prices and holding all other inputs constant to those used in the calculation of our December 31, 2025 ceiling test, no full cost ceiling limitation impairment is indicated for March 31, 2026. However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in the future could be material to our net earnings.

Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production facilities, gathering systems and related structures and restoration costs. We develop estimates of these costs for each of our properties based upon their geographic location, type of production facility, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis. At December 31, 2025, a five percent increase in future development and abandonment costs would increase the depletion rate by approximately $0.25 per Boe and a five percent decrease in future development and abandonment costs would decrease the depletion rate by $0.26 per Boe.

Accounting for Derivative Instruments and Hedging Activities

We account for our derivative activities under the provisions of the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC” Topic 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, in accordance with our policy, we may hedge a portion of our forecasted oil and natural gas production. We elected to not designate any of our positions for hedge accounting. Accordingly, we record the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

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Income Taxes

Our provision for income taxes includes both state and federal taxes. We account for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

In assessing the need for a valuation allowance on our deferred tax assets, we consider possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. We consider all available evidence (both positive and negative) in determining whether a valuation allowance is required. Based upon the evaluation of available evidence, a valuation allowance of $316.4 million has been applied against our deferred tax asset balance as of December 31, 2025.

ASC Topic 740, Income Taxes (“ASC 740”) creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the financial statements. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

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Results of Operations

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

The table below set forth financial information for the periods presented.


	Years Ended
	December 31,
In thousands (except per unit and per Boe amounts)	2025		2024
Operating revenues:
Oil	$	142,951	$	174,607
Natural gas		3,665		(2,213)
Natural gas liquids		18,346		20,822
Other		1,081		677
Total operating revenues		166,043		193,893
Operating expenses:
Production:
Lease operating		44,804		45,275
Workover and other		6,454		5,215
Taxes other than income		9,842		11,238
Gathering and other		43,742		54,117
General and administrative:
General and administrative		14,574		18,204
Stock-based compensation		48		152
Depletion, depreciation and accretion:
Depletion – Full cost		50,710		51,297
Depreciation – Other		351		638
Accretion expense		1,083		991
Asset impairment		1,072		18,511
Other income (expenses):
Net gain on derivative contracts		45,263		2,308
Interest expense and other		(26,747)		(14,956)
Loss on extinguishment of debt		—		(7,489)
Net income (loss)	$	11,879	$	(31,882)

Production:
Crude oil – MBbls		2,251		2,363
Natural gas – MMcf		7,452		7,814
Natural gas liquids – MBbls		922		971
Total MBoe⁽¹⁾		4,415		4,636
Average daily production – Boe⁽¹⁾		12,096		12,667

Average price per unit ⁽²⁾:
Crude oil price - Bbl	$	63.51	$	73.89
Natural gas price - Mcf		0.49		(0.28)
Natural gas liquids price - Bbl		19.90		21.44
Total per Boe⁽¹⁾		37.36		41.68

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
General and administrative:
General and administrative		3.30		3.93
Stock-based compensation		0.01		0.03
Depletion		11.49		11.06

(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)	Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

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Operating Revenues. Oil, natural gas and NGLs revenues were $165.0 million and $193.2 million for the years ended December 31, 2025 and 2024, respectively. The decrease of $28.3 million in revenue is primarily attributable to a $19.6 million decrease resulting from lower average realized prices and an $8.7 million decrease due to lower production volumes in 2025 compared to 2024. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, transportation take-away capacity constraints, inventory storage levels, quality of production, basis differentials and other factors.

Production for the years ended December 31, 2025 and 2024 averaged 12,096 Boe/d and 12,667 Boe/d, respectively. Production is lower in 2025 compared with 2024 in total due largely to natural production declines on our existing producing wells and curtailed production resulting from the AGI Facility complications. In 2025, we put online 6.0 gross (5.6 net) operated wells while in 2024 we put online 4.0 gross (3.88 net) operated wells.

Lease Operating Expenses. Lease operating expenses were $44.8 million and $45.3 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, lease operating expenses were $10.15 per Boe and $9.77 per Boe for the years ended December 31, 2025 and 2024, respectively. The increase year over year in lease operating expenses and on a per unit basis is primarily a result of an inflationary market increase in maintenance, power, and chemical costs.

Workover and Other Expenses. Workover and other expenses were $6.5 million and $5.2 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, workover and other expenses were $1.46 per Boe and $1.12 per Boe for the years ended December 31, 2025 and 2024, respectively. The increased workover and other expenses in 2025 compared to 2024 relate to increased workover activity during 2025 and includes costs related to a non-recurring well cleanout program that meaningfully increased production on wells in which workovers were completed combined with a higher volume of electric submersible pump (or “ESP”) maintenance during the year.

Taxes Other than Income. Taxes other than income were $9.8 million and $11.2 million for the years ended December 31, 2025 and 2024, respectively. Most production taxes are based on production volumes and realized prices at the wellhead. As revenues or volumes from oil and natural gas sales increase or decrease, production taxes on these sales also increase or decrease, as such, taxes other than income decreased due to the decrease in production volumes and revenues. On a per unit basis, taxes other than income were $2.23 per Boe and $2.42 per Boe for the years ended December 31, 2025 and 2024, respectively.

Gathering and Other Expenses. Gathering and other expenses were $43.7 million and $54.1 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, gathering and other expenses were $9.91 per Boe and $11.67 per Boe for the years ended December 31, 2025 and 2024, respectively. Our gathering and other expenses are primarily driven by the amount and location of natural gas production, the concentration of H2S in our sour gas produced and the amounts paid to treat our sour gas volumes. The decrease in gathering and other expenses in total and on a per unit basis for the year ended December 31, 2025 compared to the year ended December 31, 2024 is primarily related to progress made at the central production facilities yielding lower labor and repair costs as well as increased throughput and overall production volumes being treated by the AGI Facility during 2025. Although the AGI Facility ceased operations on August 11, 2025, we were able to secure favorable treating rates at alternative facilities. The AGI Facility treated natural gas production from March 2024 to August 11, 2025. In January 2026, we were able to secure long-term alternative processing for our high concentration H2S production.

General and Administrative Expense. General and administrative expense was $14.6 million and $18.2 million for the years ended December 31, 2025 and 2024, respectively. The decrease in general and administrative expense for 2025 compared to 2024 is primarily associated with a decrease in nonrecurring costs related to the terminated merger and lower professional fees offset by an increase payroll and employee benefits costs. On a per unit basis, general and administrative expense were $3.30 per Boe and $3.93 per Boe for the years ended December 31, 2025 and 2024, respectively.

Depletion, Depreciation, and Amortization Expense. Depletion expense was $50.7 million and $51.3 million for the years ended December 31, 2025 and 2024, respectively. On a per unit basis, depletion expense was $11.49 per Boe and $11.06 per Boe for the years ended December 31, 2025 and 2024, respectively. Depletion for oil and natural gas

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properties is calculated using the unit-of-production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. The decrease of $0.6 million in depletion expense for the year ended December 31, 2025 compared to 2024 is primarily due to the decrease in production. The increase in our depletion rate for the year ended December 31, 2025 compared to the year ended December 31, 2024 is primarily due to decreased proved reserves relative to the change in future development costs associated with those reserves when comparing 2025 to 2024.

Asset impairment. Asset impairment totaled $1.1 million and $18.5 million for the years ended December 31, 2025 and 2024, respectively. During the fourth quarter of 2025, we concluded that the fair value of our equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on our consolidated balance sheet and recorded an impairment of $1.1 million to reduce the carrying value of the investment in unconsolidated affiliate asset to zero as of December 31, 2025. During the fourth quarter of 2024, Caracara delivered a demand notice disputing our claims, indicating that the carrying value of the previously recorded 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.

Net gain on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with prior years, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in the consolidated statements of operations. We recorded a net derivative gain of $45.3 million ($29.5 million net gain on unsettled contracts and $15.8 million net gain on settled contracts) for the year ended December 31, 2025 and a net derivative gain of $2.3 million ($11.1 million net gain on unsettled contracts and $8.8 million net loss on settled contracts) for the year ended December 31, 2024. At December 31, 2025, we had a $23.5 million derivative asset, $16.1 million of which was classified as current, and we had a $2.3 million derivative liability, $0.6 million of which was classified as current.

Interest Expense and Other. Interest expense and other was $26.7 million and $15.0 million for the years ended December 31, 2025 and 2024, respectively. Interest expense and other was higher for the year ended December 31, 2025 compared to the year ended December 31, 2024 primarily due to interest expense and other including the receipt of a $10.0 million payment during 2024 for the merger termination. Our weighted average interest rate for the year ended December 31, 2025, was approximately 12.05%. For the first quarter of 2026, we anticipate our interest rate will be 11.57% on outstanding borrowings.

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 8. Consolidated Financial Statements and Supplementary Data—Note 1, “Financial Statement Presentation and Summary of Significant Accounting Policies.”

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil and natural gas prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include fixed-price swaps, costless collars, basis swaps and WTI NYMEX rolls. The total volumes that we hedge through the use of our derivative instruments varies from period to period, however, our requirement under our Amended Term Loan Agreement, is 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, when derivative contracts are available at terms and prices acceptable to us. Our hedge policies and objectives may change significantly

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as our operational profile and contractual obligations change but remain consistent with the requirements in effect under our 2024 Amended Term Loan Agreement. We do not enter into derivative contracts for speculative trading purposes.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as 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 account for our derivative activities under the provisions of ASC Topic 815, Derivatives and Hedging, (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 8, “Derivative and Hedging Activities,” for more details.

Fair Market Value of Financial Instruments

The estimated fair values for financial instruments under ASC 825, Financial Instruments, (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data—Note 7, “Fair Value Measurements,” for additional information.

Interest Rate Sensitivity

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are SOFR-based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations.

At December 31, 2025, the principal amount of our debt was $208.1 million, of which substantially all bears interest at floating and variable interest rates that are tied to SOFR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2025, the weighted average interest rate on our variable rate debt was 12.05% per year. If the balance of our variable interest rate debt at December 31, 2025 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $2.5 million per year.

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Management’s report on internal control over financial reporting		566
Report of independent registered public accounting firm (PCAOB ID No. 34)		57
Consolidated statements of operations		60
Consolidated balance sheets		61
Consolidated statements of stockholders’ (deficit) equity		62
Consolidated statements of cash flows		63
Notes to the consolidated financial statements		64
Supplemental oil and gas information (unaudited)		91

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Battalion Oil Corporation (the “Company”), including the Company’s Chief Executive Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, Management concluded that Battalion Oil Corporation’s internal control over financial reporting was effective as of December 31, 2025.

This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding the effectiveness of the Company’s internal control over financial reporting. Management’s report was not subject to attestation by its independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only Management’s report in this Annual Report on Form 10-K.

/s/ MATTHEW B. STEELE
Matthew B. Steele
Chief Executive Officer (Principal Executive Officer and Principal Financial Officer)

Houston, Texas
March 23, 2026

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Battalion Oil Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Battalion Oil Corporation and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholder's equity, and cash flows, for each of the two years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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Proved Oil and Natural Gas Property and Depletion — Oil and Natural Gas Reserve Quantities — Refer to Note 1 and 5 to the financial statements

Critical Audit Matter Description

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. The Company’s proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment by the full cost ceiling impairment test utilizing the Company’s oil and natural gas reserves in accordance with accounting principles generally accepted in the United States and SEC guidelines. The development of the Company’s oil and natural gas reserve quantities and the related net present value of future cash flows from the related proved reserves requires management to make significant estimates and assumptions related to the future production to be obtained from proved reserves, the intent and ability to complete proved undeveloped reserves within a five-year development period as prescribed by SEC guidelines, and the future development costs associated with proved undeveloped reserves. The Company engages an independent reservoir engineering firm, management’s specialist, to estimate oil and natural gas quantities using these assumptions and engineering data. Changes in these assumptions or engineering data could have a significant impact on the amount of depletion and impairment recorded for the Company’s proved oil and natural gas properties.

Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities and the related net cash flows, including management’s estimates and assumptions related to future proved reserves production volumes, the intent and ability to complete proved undeveloped reserves within the five-year development period, and future development costs, requires a high degree of auditor judgment and an increased extent of effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to evaluate management’s significant judgments and assumptions related to oil and natural gas reserves quantities and estimates of the future net cash flows included the following, among others:

●

We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to:

-

Historical conversions of proved undeveloped oil and natural gas reserves into proved developed oil and natural gas reserves.

-

Internal communications to management and the Board of Directors.

-

Prior year Reserve Reports to evaluate whether the forecasted date of development for each proved undeveloped location is within five years of the date of its original inclusion in proved reserves.

-

The financial ability of the Company to execute its drilling program.

●

We evaluated the reasonableness of management’s estimate of future development costs by comparing the estimate to:

-

Historical development of similar wells, including location of the well.

-

Internal data and internal communications to management and the Board of Directors.

-

Approval for expenditures.

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●

We evaluated the reasonableness of management’s estimated reserve quantities by performing the following:

-

Evaluating the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm.

-

Performing analytical procedures on the reserve quantities developed by management’s specialist.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 23, 2026

We have served as the Company’s auditor since 2012.

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)


	Years Ended December 31,
	2025		2024
Operating revenues:
Oil, natural gas and natural gas liquids sales:
Oil	$	142,951	$	174,607
Natural gas		3,665		(2,213)
Natural gas liquids		18,346		20,822
Total oil, natural gas and natural gas liquids sales		164,962		193,216
Other		1,081		677
Total operating revenues		166,043		193,893

Operating expenses:
Production:
Lease operating		44,804		45,275
Workover and other		6,454		5,215
Taxes other than income		9,842		11,238
Gathering and other		43,742		54,117
General and administrative		14,622		18,356
Depletion, depreciation and accretion		52,144		52,926
Asset impairment		1,072		18,511
Total operating expenses		172,680		205,638
Loss from operations		(6,637)		(11,745)

Other income (expenses):
Net gain on derivative contracts		45,263		2,308
Interest expense and other		(26,747)		(14,956)
Loss on extinguishment of debt		—		(7,489)
Total other income (expenses)		18,516		(20,137)
Income (loss) before income taxes		11,879		(31,882)
Income tax benefit (provision)		—		—
Net income (loss)	$	11,879	$	(31,882)
Preferred dividends		(48,706)		(32,219)
Net loss available to common stockholders	$	(36,827)	$	(64,101)

Net loss per share of common stock:
Basic	$	(2.24)	$	(3.90)
Diluted	$	(2.24)	$	(3.90)
Weighted average common shares outstanding:
Basic		16,457		16,457
Diluted		16,457		16,457

The accompanying notes are an integral part of these consolidated financial statements.

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BATTALION OIL CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)


	December 31, 2025		December 31, 2024
Current assets:
Cash and cash equivalents	$	27,965	$	19,712
Accounts receivable, net		12,071		26,298
Assets from derivative contracts		16,145		6,969
Restricted cash		91		91
Prepaids and other		892		982
Total current assets		57,164		54,052
Oil and natural gas properties (full cost method):
Evaluated		890,050		816,186
Unevaluated		48,025		49,091
Gross oil and natural gas properties		938,075		865,277
Less - accumulated depletion		(547,982)		(497,272)
Net oil and natural gas properties		390,093		368,005
Other operating property and equipment:
Other operating property and equipment		4,678		4,663
Less - accumulated depreciation		(2,807)		(2,455)
Net other operating property and equipment		1,871		2,208
Other noncurrent assets:
Assets from derivative contracts		7,350		4,052
Operating lease right of use assets		840		453
Other assets		3,360		2,278
Total assets	$	460,678	$	431,048

Current liabilities:
Accounts payable and accrued liabilities	$	39,734	$	52,682
Liabilities from derivative contracts		633		12,330
Current portion of long-term debt		22,510		12,246
Operating lease liabilities		764		406
Total current liabilities		63,641		77,664
Long-term debt, net		180,955		145,535
Other noncurrent liabilities:
Liabilities from derivative contracts		1,692		6,954
Asset retirement obligations		20,837		19,156
Operating lease liabilities		104		84
Commitments and contingencies (Note 10)
Temporary equity:
Redeemable convertible preferred stock: 138,000 shares
of $0.0001 par value authorized, issued and outstanding as of
December 31, 2025 and 2024		226,241		177,535
Stockholders' (deficit) equity:
Common stock: 100,000,000 shares of $0.0001 par value authorized;
16,456,563 shares issued and outstanding as of December 31, 2025 and 2024		2		2
Additional paid-in capital		240,202		288,993
Accumulated deficit		(272,996)		(284,875)
Total stockholders' (deficit) equity		(32,792)		4,120
Total liabilities, temporary equity and stockholders' (deficit) equity	$	460,678	$	431,048

The accompanying notes are an integral part of these consolidated financial statements.

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY

(In thousands)


									Retained
						Additional			Earnings
	Common Stock					Paid-In			(Accumulated			Stockholders'
	Shares		Amount			Capital			Deficit)			(Deficit) Equity
Balances at December 31, 2023	16,457		$	2		$	321,012		$	(252,993)		$	68,021
Net loss	—			—			—			(31,882)			(31,882)
Deemed dividends for preferred stock	—			—			(32,219)			—			(32,219)
Stock-based compensation	—			—			200			—			200
Balances at December 31, 2024	16,457			2			288,993			(284,875)			4,120
Net income	—			—			—			11,879			11,879
Deemed dividends for preferred stock	—			—			(48,706)			—			(48,706)
Stock-based compensation and other	—			—			(85)			—			(85)
Balances at December 31, 2025	16,457		$	2		$	240,202		$	(272,996)		$	(32,792)

The accompanying notes are an integral part of these consolidated financial statements.

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BATTALION OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Years Ended December 31,
	2025		2024
Cash flows from operating activities:
Net income (loss)	$	11,879	$	(31,882)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depletion, depreciation and accretion		52,144		52,926
Asset impairment		1,072		18,511
Stock-based compensation, net		(109)		152
Unrealized gain on derivative contracts		(29,433)		(11,116)
Amortization/accretion of financing related costs		1,569		6,418
Loss on extinguishment of debt		—		7,489
Accrued settlements on derivative contracts		(1,833)		403
Change in fair value of embedded derivative liability		—		(2,084)
Other expense		358		324
Change in assets and liabilities:
Accounts receivable		14,459		(2,765)
Prepaids and other		91		(75)
Accounts payable and accrued liabilities		(11,107)		(2,946)
Net cash provided by operating activities		39,090		35,355

Cash flows from investing activities:
Oil and natural gas capital expenditures		(74,556)		(64,625)
Proceeds received from sales of oil and natural gas assets		—		7,015
Acquisition of oil and natural gas properties		—		(47)
Other operating property and equipment capital expenditures		(15)		(23)
Contract asset		—		(7,737)
Other		(380)		(26)
Net cash used in investing activities		(74,951)		(65,443)

Cash flows from financing activities:
Proceeds from borrowings		63,000		162,000
Repayments of borrowings		(16,971)		(200,109)
Payment of deferred financing costs		(1,915)		(8,400)
Proceeds from issuance of preferred stock		—		38,781
Other		—		—
Net cash provided by (used in) financing activities		44,114		(7,728)

Net increase (decrease) in cash, cash equivalents and restricted cash		8,253		(37,816)

Cash, cash equivalents and restricted cash at beginning of period		19,803		57,619
Cash, cash equivalents and restricted cash at end of period	$	28,056	$	19,803

Supplemental cash flow information:
Cash paid for interest	$	27,230	$	22,317

Disclosure of non-cash investing and financing activities:
Asset retirement obligations	$	598	$	707
Capital expenditures in accrued liabilities and accounts payable		(2,237)		(7,526)
Deemed dividends on Series A preferred stock		48,706		32,219

The accompanying notes are an integral part of these consolidated financial statements.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. FINANCIAL STATEMENT PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

Battalion Oil Corporation (“Battalion” or the “Company”) is the successor reporting company to Halcón Resources Corporation (“Halcón”). On January 21, 2020, Battalion filed a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Halcón Resources Corporation to Battalion Oil Corporation.

Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States (“U.S.”). The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements. These consolidated financial statements of the Company have been presented in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”).

Liquidity and Capital Resources

The Company has incurred significant net losses available to common stockholders in recent years driven by primarily by deemed dividends on preferred stock resulting an accumulated deficit of $273.0 million and total stockholders’ deficit of $32.8 million as of December 31, 2025. For the years ended December 31, 2025 and 2024, the Company generated $39.1 million and $35.4 million, respectively, of cash flows from operating activities. As of December 31, 2025, the Company had cash and cash equivalents of $28.0 million. Historically, the Company has funded its operations principally through the sales of its oil, natural gas and NGLs production, issuance of preferred equity securities, debt financing and divestiture proceeds.

The Company’s financial statements have been prepared on the basis of the Company continuing as a going concern for the next 12 months. Management believes that the Company’s cash and cash equivalents will allow the Company to continue its planned operations for at least the next 12 months from the date of the issuance of these financial statements.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations and fair value estimates. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statement and the results presented in this Annual Report on Form 10-K are not necessarily indicative of future operating results.

Cash, Cash Equivalents and Restricted Cash

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

consolidated balance sheets included in “Cash and cash equivalents” and “Restricted cash” reconcile to the Company’s consolidated statements of cash flows as follows:


	2025		2024

Cash and cash equivalents	$	27,965	$	19,712
Restricted cash		91		91
Total cash, cash equivalents and restricted cash	$	28,056	$	19,803

Restricted cash consists primarily of funds to collateralize company credit cards.

Accounts Receivable and Allowance for Doubtful Accounts

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. Payment of the Company’s accounts receivable is typically received within 30-60 days. The Company’s historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of the Company’s counterparties.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company’s accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. The Company did not capitalize any interest for the years ended December 31, 2025 and 2024.

Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

Other Operating Property and Equipment

Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, five years; trailers, seven years; heavy equipment, eight to ten years and leasehold improvements, lease term. Land and artwork are not depreciated. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset.

The Company reviews its other operating property and equipment for impairment in accordance with the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification (“ASC”) Topic 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.

Concentrations of Credit Risk

The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable and of nonperformance by two counterparties under the Company’s derivative contracts. Each reporting period, the Company assesses the recoverability of material receivables using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions to determine expected collectability of its material receivables.

The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts from its oil and natural gas purchasers. In 2025 and 2024, two individual purchasers of the Company’s production, Western Refining Company L.P. and Sunoco Inc., each accounted for more than 10% of total sales for the year, collectively representing 83% and 86% of its total sales, respectively.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. Joint operating agreements govern the operations of an oil or natural gas well and, in most instances, provide for offsetting of amounts payable or receivable between the Company and its joint interest owners. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.

At December 31, 2025, the Company’s exposure to credit risk under its derivative contracts is currently limited to two counterparties – a major financial institution that is a lender under the 2024 Amended Term Loan Agreement (as defined in Note 6, “Debt”) and a large multi-strategy alternative investment manager, both of which have investment

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grade credit ratings. The Company has master netting agreements with both counterparties which provide for offsetting of amounts payable or receivable between the Company and the counterparty. To manage counterparty risk associated with derivative contracts, the Company selects and monitors counterparties based on an assessment of their financial strength and/or credit ratings.

Risk Management Activities

From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil and natural gas production. The Company recognizes all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

Income Taxes

The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets.

The evaluation of a tax position in accordance with ASC Topic 740, Income Taxes (“ASC 740”) is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement.

Asset Retirement Obligations

The Company records asset retirement obligations (“AROs”) to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred.

The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its

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ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis.

Recently Issued Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”), which focuses on the income tax rate reconciliation and income taxes paid. ASU 2023-09 requires an entity to disclose, on an annual basis, a tabular rate reconciliation using both percentages and currency amounts, broken out into specified categories, with certain reconciling items further broken out by nature and jurisdiction to the extent those items exceed a specified threshold. In addition, entities are required to disclose income taxes paid, net of refunds received disaggregated by federal, state/local, and foreign, and by jurisdiction if the amount is at least 5% of total income tax payments, net of refunds received. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. An entity may apply the amendments in ASU 2023-09 prospectively by providing the revised disclosures for the period ending December 31, 2025 and continuing to provide the pre-ASU disclosures for the prior periods, or may apply the amendments retrospectively by providing the revised disclosures for all period presented. The requirements of ASU 2023-09 are disclosure-related and did not have an impact on the Company’s consolidated financial position or results of operations. See Note 13, “Income Taxes” for the updated income tax disclosures resulting from the adoption of ASU 2023-09.

In November 2024, the FASB issued ASU 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”), which requires public entities to disclose additional information about specific expense categories in the notes to the financial statements on an interim and annual basis. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim periods within the fiscal year beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2024-03.

2. SEGMENTS

The Company has determined that it operates as one reportable segment which focuses on oil and natural gas acquisition, production, exploration and development. The Company evaluates performance based on consolidated income or loss from operations. The Company’s chief executive officer and chief operating officer together function as the Company’s chief operating decision maker (the “CODM”). The CODM evaluates and manages performance and resource allocation based on consolidated production and operating expenses. Significant expenses provided to the CODM for review consist of lease operating, workover and other, and gathering and other expenses. The Company’s significant segment expenses are derived from and can be found within the consolidated statement of operations. The measure of segment assets for the Company’s single reportable segment is “Total assets” as reported on the consolidated balance sheet.

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3. LEASES

The Company leases equipment and office space pursuant to operating leases. The Company determines if an arrangement is or contains a lease at inception and combines lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. Operating leases with a lease term greater than 12 months where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the consolidated balance sheets and recorded based on the present value of the future minimum lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The Company does not recognize right of use assets and lease liabilities for short-term leases that have a lease term of 12 months or less, but rather recognizes the lease payments associated with its short-term leases when incurred.

Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. Variable lease payments, if applicable, associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other” or “General and administrative” in the consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases.

The table below summarizes the Company’s leases for the periods indicated (in thousands, except years and discount rate):


	Years Ended December 31,
	2025			2024
Lease cost
Operating lease costs	$	719		$	668
Short-term lease costs		4,088			4,319
Total lease costs	$	4,807		$	4,987

Other information
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	729		$	688
Weighted-average remaining lease term - operating leases		1.2	years		1.0	years
Weighted-average discount rate - operating leases		12.35	%		12.17	%

The “Operating lease right of use assets” outstanding on the consolidated balance sheet as of December 31, 2025 and 2024 resulted from two operating leases initially entered into during the year ended December 31, 2023 with lease terms at inception of 1.9 years and 2.7 years. Both operating leases were extended during 2025 with one lease having an

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extension of 18 months with an effective date of June 27, 2025 and the other extended for 12 months beyond its original expiration of July 1, 2026.

Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2025, are presented in the table below (in thousands):


	December 31, 2025
2026	$	829
2027		107
Total operating lease payments		936
Less: discount to present value		(68)
Total operating lease liabilities		868
Less: current operating lease liabilities		764
Noncurrent operating lease liabilities	$	104

4. OPERATING REVENUES

Substantially all of the Company’s oil, natural gas, and NGLs revenues are derived from the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. Revenue is presented disaggregated in the statement of operations by major product, and depicts how the nature, timing and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations.

Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the performance obligation is satisfied. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of each unit (e.g. barrel of oil, Mcf of natural gas) of commodity to the customer. Revenue is measured based on contract consideration allocated to each unit of commodity and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue.

Since the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $8.5 million and $23.5 million as of December 31, 2025 and 2024, respectively, as “Accounts receivable, net” on the consolidated balance sheets. The Company utilizes the practical expedient exempting the disclosure of the transaction price of unsatisfied performance obligations for (i) contracts with an original expected duration of one year or less and (ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied).

The Company records revenue in the month its production is delivered to the purchaser. However, to the extent settlement statements and/or payments are not available, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Oil Sales

The Company recognizes revenue when control of the crude oil transfers at the delivery point at the net price received. Generally, this occurs when the Company (i) sells its crude oil production at the wellhead where control of the

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crude oil transfers to the customer at an index price, averaged over the daily settlement prices for a production month, and adjusted for pricing differentials and other deduction or (ii) when delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, averaged over the daily settlement prices for a production month, and net of applicable market-related adjustments. Settlement statements for the Company’s crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded.

Natural Gas and NGLs Sales

The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are treated as a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity’s processing plant, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as “Natural gas” or “Natural gas liquids” and any fees incurred to gather or process the natural gas are presented separately as “Gathering and other” on the consolidated statements of operations.

Under certain contracts, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “Gathering and other” on the consolidated statements of operations.

The majority of the Company’s natural gas and NGLs prices are based on daily average pricing for the month. Settlement statements for the Company’s natural gas and NGLs production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company’s estimates and the actual revenue received have not been material.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

5. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consisted of the following (in thousands):


	2025		2024

Subject to depletion	$	890,050	$	816,186
Not subject to depletion:
Other capital costs:
Incurred in 2024		1		1
Incurred in 2023		31		31
Incurred in 2022 and prior⁽¹⁾		47,993		49,059
Total not subject to depletion		48,025		49,091
Gross oil and natural gas properties		938,075		865,277
Less accumulated depletion		(547,982)		(497,272)
Net oil and natural gas properties	$	390,093	$	368,005

(1)	In 2019, with the adoption of fresh-start accounting, the Company’s unevaluated properties were recorded at fair value.

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $50.7 million and $51.3 million for the years ended December 31, 2025 and 2024, respectively. Depletion expense is recorded in “Depletion, depreciation and accretion” in the Company’s consolidated statements of operations.

The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense.

The ceiling test value of the Company’s reserves was calculated based on the following prices:


		West Texas Intermediate (per barrel) ⁽¹⁾			Henry Hub (per MMBtu) ⁽¹⁾
December 31, 2025		$	66.01		$	3.39
December 31, 2024			76.32		$	2.13

(1)	Unweighted average of the first day of the 12-months ended spot price, adjusted by lease or field for quality, transportation fees, and regional price differentials.

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The Company's net book value of oil and natural gas properties for both 2025 and 2024 did not exceed the ceiling amount. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods.

West Quito Divestiture

On December 18, 2025, the Company entered into an agreement of sale and purchase with MCM Delaware Resources, LLC (“MCM”) (the “West Quito Divestiture Agreement”) to sell substantially all of its oil and natural gas properties and related assets in the West Quito Draw area located in the Southern Delaware Basin in Ward County, Texas 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”).

6. DEBT

As of December 31, 2025 and 2024, the Company’s debt consisted of the following (in thousands):


	December 31, 2025		December 31, 2024
Term loan credit facility	$	208,125	$	162,000
Other		10		106
Total debt (Face Value)		208,135		162,106
Less:
Current Portion of Long-Term Debt⁽¹⁾		(22,510)		(12,246)
Other⁽²⁾		(4,670)		(4,325)
Long-Term Debt, net	$	180,955	$	145,535

(1)	Amounts primarily reflect payments due of $22.5 million and $12.2 million under the Company’s 2024 Amended Term Loan Agreement due within one year as of December 31, 2025 and December 31, 2024, respectively.

(2)

Amounts primarily reflect unamortized discount and debt issuance costs of approximately $4.7 million and $4.3 million at December 31, 2025 and 2024, respectively. For the years ended December 31, 2025 and 2024, we recorded, on a straight-line basis, approximately $1.6 million and $6.4 million, respectively, in interest expense reflecting the amortization/accretion of deferred financing costs and debt discount.

Amended and Restated Credit Agreement

On December 26, 2024 (the “Initial Closing Date”), Halcón Holdings, LLC (the “Borrower”), a wholly-owned subsidiary of the Company, entered into a 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. The 2024 Term Loan Agreement amends and restates in its entirety the Company’s 2021 Amended Term Loan Agreement (as defined below). Pursuant to the 2024 Term Loan Agreement, the lenders party thereto agreed to provide the Borrower 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 to be made available to the Borrower from January 3, 2025 until the date that is the earliest to occur of (x) the date on which such incremental term facility is fully drawn, (y) the date on which such incremental term facility is terminated and (z) January 11, 2025, subject to the satisfaction of certain conditions. On January 9, 2025, the Borrower entered into a first amendment (the “First Amendment”) to its 2024 Term Loan Agreement (as amended, the “2024 Amended Term Loan Agreement”). Pursuant to the First Amendment, the Borrower incurred incremental term loans in the aggregate principal amount of $63.0 million (the “Incremental Term Loans”).

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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. Upon extinguishment of the 2021 Amended Term Loan Agreement, the difference between the repayment amount of the extinguished debt and its respective carrying amount is recorded as a gain or loss on extinguishment of debt in the consolidated statement of operations. 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. Additionally, the Company deferred $4.3 million of original issue discount and financing costs on the consolidated balance sheet at December 31, 2024.

The maturity date of the 2024 Amended Term Loan Agreement is December 26, 2028.

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%.

On November 12, 2025, the Company entered into the Second Amendment to the Second Amended and Restated Senior Secured Credit Agreement (the “Second Amendment”), effective November 12, 2025, which amended the Applicable Margin (as defined in the 2024 Amended Term Loan Agreement) to be the rate per annum set forth below under the caption “SOFR Loans Spread” or “ABR Loans Spread”, as the case may be, based on the Total Net Leverage Ratio; provided that (a) until the Adjustment Date (the date of delivery of financial statements pursuant to the 2024 Amended Term Loan Agreement) following the Second Amendment effective date, the Applicable Margin shall be the applicable rate per annum set forth below in Category 1 and (b) the Applicable Margin shall be the applicable rate per annum set forth in Category 4 below at any time that an Event of Default (as defined in the 2024 Amended Term Loan Agreement) exists:


Total Net Leverage Ratio	SOFR Loans Spread	ABR Loans Spread
Category 1 ≤ 2.50 to 1.00	7.75%	6.75%
Category 2 > 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3 > 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4 > 3.25 to 1.00	8.50%	7.50%

The Applicable Margin shall be adjusted quarterly on a prospective basis on each Adjustment Date based upon the Total Net Leverage Ratio in accordance with the table above.

The Second Amendment provides that the Borrower shall not permit the Total Net Leverage Ratio, as of the last day of each fiscal quarter (commencing with the fiscal quarter ending March 31, 2025), to be greater than the levels set forth

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in the following table for the applicable quarter:


Fiscal Quarter	Total Net Leverage Ratio
Fiscal quarters ending March 31, 2025 through and including June 30, 2025	2.75 to 1.00
Fiscal quarter ending September 30, 2025	2.50 to 1.00
Fiscal quarter ending December 31, 2025	3.20 to 1.00
Fiscal quarter ending March 31, 2026	3.25 to 1.00
Fiscal quarter ending June 30, 2026	3.40 to 1.00
Fiscal quarter ending September 30, 2026	3.50 to 1.00
Fiscal quarter ending December 31, 2026	3.40 to 1.00
Fiscal quarter ending March 31, 2027	3.25 to 1.00
Fiscal quarter ending June 30, 2027	3.00 to 1.00
Fiscal quarter ending September 30, 2027 and each fiscal quarter thereafter	2.50 to 1.00

Additionally, the Second Amendment provides that the Borrower shall not permit the Asset Coverage Ratio, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2025) to be less than the applicable level set forth in the following table for the applicable fiscal quarter:


Fiscal Quarter	Asset Coverage Ratio
Fiscal quarters ending March 31, 2025 through and including December 31, 2026	1.85 to 1.00
Each fiscal quarter thereafter	2.00 to 1.00

The Second Amendment was accounted for as a debt modification in accordance with applicable accounting guidance.

The Borrower may elect, at its option, to prepay any borrowing outstanding under the 2024 Amended Term Loan Agreement. Such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:


Period			Premium
Months 0 - 12			Make-whole amount equal to 12 months of interest plus 4.00%
Months 13 - 30			2.00%
Thereafter			0.00%

In the event the Borrower shall receive a disapproval notice (as defined in the 2024 Term Loan Agreement) from the required lenders under the 2024 Amended Term Loan Agreement rejecting or otherwise disqualifying a proposed buyer in connection with a permitted change in control thereunder to be consummated within 12 months following the Initial Closing Date, such voluntary prepayments, certain mandatory prepayments and change of control prepayments are subject to the following prepayment premium, as applicable:


Period			Premium
Months 0 - 9			Make-whole amount equal to 9 months of interest plus 2.00%
Months 10 - 30			2.00%
Thereafter			0.00%

The Borrower is required to make scheduled quarterly amortization payments in an aggregate principal amount equal to 2.50% of the aggregate principal amount of the loans outstanding on the Initial Closing Date plus the Incremental Term Loans commencing with the fiscal quarter ending June 30, 2025. The Borrower may be required to make mandatory prepayments of the loans under the 2024 Amended Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales and with excess cash on hand in excess of certain maximum levels.

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Accordingly, upon closing of the West Quito Divestiture, the Company made a mandatory prepayment of $40.0 million on February 24, 2026.

Amounts outstanding under the 2024 Amended Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by the Company.

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

●

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; and

●

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, the Company is required to hedge approximately 85% to 50% of its anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. Entry into the 2024 Term Loan Agreement did not result in any material changes to the Company’s hedges. 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; judgments; change of control; and voluntary and involuntary bankruptcy.

In conjunction with entering into the 2024 Term Loan Agreement, the Company agreed to pay an exit fee equal to the amount resulting from multiplying 3.50% by the difference, if any, of (x) Total proved developed producing (“PDP”) PV-10 (the “PDP PV-10”) as of the date that is the earlier of (i) Payment in Full, (ii) the Maturity Date, or (iii) the loans and other obligations otherwise becoming immediately due and payable pursuant to Section 10.02 of the 2024 Term Loan Agreement (including whether, in the case of clauses (i) or (iii), such Payment in Full or acceleration, respectively, may be made in connection with a refinancing transaction or a disposition of all or substantially all of the assets of the Company) (such earlier date, the “Exit Fee Determination Date”), less (y) the Total PDP PV-10 reflected in the Initial Reserve Report (as defined in the 2024 Term Loan Agreement) (the “Exit Fee”). Upon evaluation of the payoff profiles associated with the Exit Fee, the Company concluded that such embedded features resulting from the application of this fee were not clearly and closely related to the host debt instrument. The fair value analysis for such derivative was performed and the fair value was deemed to be zero at commencement and at December 31, 2025. Refer to Note 7, “Fair Value Measurements,” for a discussion of the valuation approach used and the significant inputs to the valuation for the Exit Fee derivative.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Debt Maturities

Aggregate debt maturities under the 2024 Amended Term Loan Agreement due in future years as of December 31, 2025 are as follows (in thousands):


	Term Loan Credit Facility⁽¹⁾		Other			Total
2026	$	22,500	$	10		$	22,510
2027		22,500		—			22,500
2028		163,125		—			163,125
Total	$	208,125	$	10		$	208,135

(1)

Required quarterly debt maturities payments in the aggregate principal amount are $22.5 million in each of 2026 and 2027, $16.9 million in 2028 and a final payment at maturity on December 26, 2028 of $146.2 million. The final payment at maturity on December 26, 2028 decreased to $106.2 million subsequent to the $40.0 million prepayment of debt upon closing of the West Quito Divestiture on February 24, 2026.

7. FAIR VALUE MEASUREMENTS

The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company separates the fair value of its financial instruments using a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

A financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented.

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities associated with commodity-based derivative contracts that were accounted for at fair value as of December 31, 2025 and 2024 (in thousands):



		December 31, 2025
		Level 1			Level 2			Level 3		Total
Assets
Assets from derivative contracts		$	—		$	23,495		$	—	$	23,495

Liabilities
Liabilities from derivative contracts		$	—		$	2,325		$	—	$	2,325


		December 31, 2024
		Level 1			Level 2			Level 3			Total
Assets
Assets from derivative contracts		$	—		$	11,021		$	—		$	11,021

Liabilities
Liabilities from derivative contracts		$	—		$	19,284		$	—		$	19,284

Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain on derivative contracts” in the Company’s consolidated statements of operations. The Level 2 observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, “Derivative and Hedging Activities,” for additional discussion of derivatives.

The Company’s derivative contracts are with a major financial institution and a large multi-strategy alternative investment manager, both of which have investment grade credit ratings and are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance.

As discussed in Note 6, “Debt,” the Company evaluated the 2024 Amended Term Loan Agreement and identified the Exit Fee to be an embedded derivative not clearly and closely related to the host debt instrument. The fair value analysis for such derivative was performed and the fair value was deemed to be zero at commencement and at December 31, 2025. The fair value of the Exit Fee derivative will be subsequently remeasured each reporting period with fair value changes recorded in “Interest expense and other” on the consolidated statement of operations. The valuation of the Exit Fee derivative included significant inputs such as the timing of potential exit scenarios, forward NYMEX strip pricing, forecasted capital and other expenditures and discount rates. The fair value of the Exit Fee derivative is classified as Level 3 in the fair value hierarchy.

Estimated fair value amounts have been determined at discrete points in time based on relevant market information. The estimated fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of borrowings under the Company’s Amended Term Loan Agreement approximate carrying value because the interest rates approximate current market rates.

The Company follows the provisions of the FASB’s ASC Topic 820, Fair Value Measurement for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of AROs for which fair value is used. The ARO estimates are derived from historical costs and

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s AROs.

8. DERIVATIVE AND HEDGING ACTIVITIES

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the 2024 Amended Term Loan Agreement, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the consolidated statements of operations. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.

The Company’s purchaser, gathering and/or processing, or transportation contracts have no net settlement provisions and no market mechanism to facilitate net settlement. As such, those contracts qualify for the normal purchase and normal sale exception under ASC 815. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2025, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s 2024 Amended Term Loan Agreement.

The Company’s crude oil and natural gas derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls further described as follows:

●

Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas.

●

Costless collars consist of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price and are generally utilized less frequently by the Company than fixed-price swaps.

●

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.

The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets (in thousands):


	Years Ended December 31,					Years Ended December 31,
Balance sheet location	2025		2024		Balance sheet location	2025		2024
Current assets	$	16,145	$	6,969	Current liabilities	$	(633)	$	(12,330)
Other noncurrent assets		7,350		4,052	Other noncurrent liabilities		(1,692)		(6,954)
	$	23,495

BATTALION OIL CORP 10-K