10-K - BATL - Equibles

Table of Contents

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 Corp oration

(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.

			☐<br><br>
Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☒	Smaller reporting company ☒<br><br>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

Table of Contents 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;
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●	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;
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●	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;
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●	our ability to replace our oil and natural gas reserves and production;
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●	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;
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●	our ability to successfully develop our large inventory of undeveloped acreage;
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●	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;
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●	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;
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●	senior management’s ability to execute our plans to meet our goals;
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●	access to and availability of water, sand and other treatment materials to carry out fracture stimulations in our completion operations;
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●	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);
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●	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;
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●	our ability to pursue and integrate strategic mergers and acquisitions;
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●	divestitures could negatively impact our business and our results of operations may be adversely affected if we fail to manage and complete divestitures;
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●	the potential for production decline rates for our wells to be greater than we expect;
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●	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;
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●	our ability to retain key members of senior management, the board of directors and key technical employees;
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●	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;
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●	impacts of climate regulations or lawsuits;
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●	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;
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●	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;
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●	impacts and potential risks of extreme weather;
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●	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;
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●	our insurance coverage may not adequately cover all losses that we may sustain; and
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●	title to the properties in which we have an interest which may be impaired by title defects.
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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.

Table of Contents 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. 5

Table of Contents 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.

Table of Contents 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:

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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.
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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”.

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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.

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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.
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●	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.
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●	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.
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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 9

Table of Contents 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 10

Table of Contents 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.
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(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.
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(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.
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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.
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(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.
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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.

Table of Contents 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.
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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.
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(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.
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We had no exploratory or extension wells drilled for the years ended December 31, 2025 and 2024. 12

Table of Contents 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.
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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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Table of Contents

(2)	Total production for the years ended December 31, 2025 and 2024 from West Quito totaled 679 MBoe and 644 MBoe, respectively.
(3)	Cash paid on, or cash received from, settled derivative contracts are reflected as “Net gain (loss) on derivative contracts” in the consolidated statements of operations, consistent with our decision not to elect hedge accounting.
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(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.
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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 14

Table of Contents 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. 15

Table of Contents 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 16

Table of Contents 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 17

Table of Contents 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 18

Table of Contents private land use and could delay or prohibit land access or development. Further, the EPA and U.S. Army Corps of Engineers have proposed a new definition for regulated wetlands that is expected to reduce the scope of federal jurisdiction but may prove difficult to implement. Government entities or at times private parties may act to prevent or seek damages for any injury to protected species or other natural resources, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result.

Occupational Safety and Health Act

We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees.

Human Capital

Employees

At Battalion, our success is delivered through our highly capable and diverse workforce. Our team is comprised of individuals with extensive technical, industry and other professional experience. By recruiting, hiring and retaining an experienced and diverse team, we are able to leverage years of experience, new ideas and problem solving in a collaborative environment. As of December 31, 2025, we had 40 full-time employees. We also engage the services of independent contractors and consultants along with certain professional service firms to support our work in specific areas. We have no collective bargaining agreements with our employees. We believe that we have good relations with our employees.

Driving and Supporting a Safety First Culture

The safety of our employees, contractors and the communities in which we operate is one of our most critical responsibilities. We believe that driving a safety first culture requires daily prioritization and includes a multi-faceted approach to provide our employees with the tools, support, education and incentives to operate safely:

●	All employees, contractors and consultants performing work in the field participate in ongoing environmental, health and safety engagements, including training, routine meetings, and individual coaching;
●	Work stop authority – all of our employees and contractors have a responsibility to intercede and stop observed high hazard activities or conditions without proper controls;
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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.
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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 19

Table of Contents 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.

●	Oil and natural gas prices are volatile, and low prices could have a material adverse impact on our business.
●	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.
---	---
●	We may be required to take non-cash asset write-downs.
---	---
●	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.
●	Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted rates of return.
---	---
●	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.
---	---
●	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.
---	---
●	Increasing attention to environmental, social and corporate governance (“ESG”) matters may impact our business.
---	---
●	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.
---	---
●	We may not be able to drill wells on a substantial portion of our acreage.
---	---
●	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.
---	---
●	Our oil and natural gas activities are subject to various risks that are beyond our control.
---	---
●	Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.
---	---
●	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.
---	---
●	Title to the properties in which we have an interest may be impaired by title defects.
---	---
●	We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.
---	---
●	There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
---	---
●	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.
---	---
●	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 failure to meet the continued listing standards of NYSE American could result in a delisting of our common stock.
---	---
●	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.
---	---
●	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.
---	---
●	Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
---	---
●	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.
---	---
●	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.
---	---
●	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.
●	A financial downturn could negatively affect our business, results of operations, financial condition and liquidity.
---	---
●	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:

●	domestic and foreign supplies of oil, natural gas and NGLs and natural gas;
●	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;
---	---
●	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;
---	---
●	the level of consumer demand for oil and natural gas, including demand growth in developing countries, such as China and India;
---	---
●	labor unrest in oil and natural gas producing regions;
---	---
●	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand for oil and natural gas;
---	---
●	the price and availability of alternative fuels and energy sources;
---	---
●	the price and availability of foreign imports and domestic exports; and
---	---
●	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 22

Table of Contents 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.

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.

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:

●	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;
●	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;
---	---
●	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.
---	---

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. 23

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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<br>≤ 2.50 to 1.00	7.75%	6.75%
Category 2<br>> 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3<br>> 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4<br> > 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, 24

Table of Contents 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:

●	pay dividends on, redeem or repurchase shares of our common stock and any other capital stock we may issue;
●	make loans to others;
---	---
●	make investments;
---	---
●	incur additional indebtedness;
---	---
●	create certain liens;
---	---
●	sell assets;
---	---
●	enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
---	---
●	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;
●	increase our exposure to commodity price fluctuations;
---	---
●	create unrestricted subsidiaries; and
---	---
●	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.

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.

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:

●	personal injury;
●	bodily injury;
---	---
●	third party property damage;
---	---
●	medical expenses;
---	---
●	legal defense costs;
---	---
●	pollution in some cases;
---	---
●	well blowouts in some cases; and
---	---
●	workers compensation.
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Table of Contents 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 27

Table of Contents 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:

●	our production is less than expected;
●	there is a widening of price differentials between delivery points for our production; or
---	---
●	the counterparties to our hedging agreements fail to perform under the contracts.
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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:

●	unexpected drilling conditions;
●	pressure or irregularities in formations;
---	---
●	equipment failures or accidents and shortages or delays in the availability of drilling and completion equipment and services;
---	---
●	adverse weather conditions; and
---	---
●	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. 28

Table of Contents 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.

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.

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.

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.

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 29

Table of Contents 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.

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.

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:

●	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;
●	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;
●	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
---	---
●	the availability of alternative fuels and the price at which they become available.
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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. 31

Table of Contents 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.

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. 32

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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.

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:

●	market conditions in the broader stock market;
●	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.
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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. 33

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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. 34

Table of Contents Regulatory Risk Factors

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.

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:

●	water discharge and disposal permits for drilling operations;
●	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.
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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. 35

Table of Contents 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.

Table of Contents 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.

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.

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

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

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.

Table of Contents 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

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.

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 38

Table of Contents 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. 39

Table of Contents 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

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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

Table of Contents 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

Table of Contents 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) 42

Table of Contents 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. 43

Table of Contents 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. 44

Table of Contents 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%. 45

Table of Contents 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<br>≤ 2.50 to 1.00	7.75%	6.75%
Category 2<br>> 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3<br>> 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4<br> > 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%

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

Under the 2024 Amended Term Loan Agreement, we are required to hedge approximately 85% to 50% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years. The 2024 Amended Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; 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 47

Table of Contents 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 48

Table of Contents 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. 49

Table of Contents 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. 50

Table of Contents 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.

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.

Table of Contents 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.
---	---

Table of Contents 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 53

Table of Contents 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 54

Table of Contents 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

Table of Contents 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<br><br>(Principal Executive Officer and Principal Financial Officer)

Houston, Texas
March 23, 2026

Table of Contents 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.

Table of Contents

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.
---	---

Table of Contents

●	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.
---	---


<br><br>/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 23, 2026

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

Table of Contents 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.

Table of Contents 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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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.

Table of Contents 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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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 64

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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 65

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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 66

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 67

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 69

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 70

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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. 71

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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<br>≤ 2.50 to 1.00	7.75%	6.75%
Category 2<br>> 2.50 to 1.00 ≤ 3.00 to 1.00	8.00%	7.00%
Category 3<br>> 3.00 to 1.00 ≤ 3.25 to 1.00	8.25%	7.25%
Category 4<br> > 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 74

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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. 75

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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.

●	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
---	---
●	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. 76

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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. 77

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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 78

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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	$	11,021		$	(2,325)	$	(19,284)

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The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands):


	Location of gain or (loss)
	on derivative contracts on	Years Ended December 31,
Type	Statement of Operations	2025		2024
Commodity contracts:
Unrealized gain (loss)	Other income (expenses)	$	29,433	$	11,116
Realized gain (loss)	Other income (expenses)		15,830		(8,808)
Total net gain (loss)		$	45,263	$	2,308

At December 31, 2025, the Company had the following open crude oil and natural gas derivative contracts:


Instrument			2026			2027			2028		2029
Crude oil:
Fixed-price swap:
Total volumes (Bbls)			1,361,328			943,447			750,020		299,544
Weighted average price		$	64.05		$	62.01		$	62.37	$	61.40
Two-way collar:
Total volumes (Bbls)			—			—			41,678		131,099
Weighted average price (call)		$	—		$	—		$	62.35	$	63.15
Weighted average price (put)		$	—		$	—		$	59.00	$	59.00
Basis swap:
Total volumes (Bbls)			1,459,912			980,339			692,020		140,544
Weighted average price		$	0.50		$	0.55		$	0.66	$	0.68
WTI NYMEX roll:
Total volumes (Bbls)			1,459,912			980,339			692,020		140,544
Weighted average price		$	0.03		$	(0.04)		$	(0.23)	$	(0.29)
Natural gas:
Fixed-price swap:
Total volumes (MMBtu)			1,098,125			1,124,485			2,010,469		527,049
Weighted average price		$	3.97		$	3.74		$	3.36	$	3.84
Two-way collar:
Total volumes (MMBtu)			1,779,970			531,127			1,083,731		1,080,235
Weighted average price (call)		$	5.05		$	4.86		$	4.10	$	3.89
Weighted average price (put)		$	3.53		$	3.19		$	3.34	$	2.87
Basis swap:
Total volumes (MMBtu)			2,903,175			2,159,284			2,550,400		527,049
Weighted average price		$	(0.89)		$	(0.84)		$	(0.86)	$	(0.89)

The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2025 and 2024 (in thousands):


	Assets from Derivative Contracts				Liabilities from Derivative Contracts
	Years Ended December 31,				Years Ended December 31,
Offsetting of Derivative Assets and Liabilities	2025		2024		2025		2024

Gross amounts recognized in the Consolidated Balance Sheet	$	23,495	$	11,021	$	(2,325)	$	(19,284)
Amounts not offset in the Consolidated Balance Sheet		(2,325)		(11,021)		2,325		11,021
Net amount	$	21,170	$	—	$	—	$	(8,263)

The Company enters into an International Swap Dealers Association Master Agreement (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting 80

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of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

9. ASSET RETIREMENT OBLIGATIONS

The Company records an ARO on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records 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 recorded the following activity related to its ARO liability (inclusive of the current portion) (in thousands):


	For the Years Ended December 31,
	2025		2024
Asset retirement obligations at beginning of the period	$	19,156	$	17,458
Accretion expense		1,083		991
Liabilities incurred		118		223
Revisions to estimate		480		484
Asset retirement obligations at end of period		20,837		19,156
Less: current asset retirement obligations		—		—
Long-term asset retirement obligations at the end of the period	$	20,837	$	19,156

10. COMMITMENTS AND CONTINGENCIES

Commitments

In May 2022, the Company entered into a joint venture agreement to develop a strategic acid gas treatment and carbon sequestration facility and entered into a gas treating agreement. The Company had a minimum volume commitment of 20,000 Mcf per day under the gas treating agreement, with certain rollover rights and start-up flexibility, for an initial term of five years from the in-service date of the facility. Under the gas treating agreement, the Company paid a treating rate that varied based on volumes delivered to the facility. The gas treating agreement was terminated on January 19, 2026. For additional information on this joint venture, see Note 15, “Additional Financial Information.”

The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of December 31, 2025, the Company had in place multiple long-term crude oil and natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production.

Contingencies

In addition to the matters described below, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s consolidated operating results, financial position or cash flows.

Surface owners of properties in Louisiana, where the Company formerly operated, often file lawsuits or assert claims against oil and gas companies claiming that operators and working interest owners are liable for environmental 81

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

damages arising from operations conducted on the leased properties. These damages are frequently measured by the cost to restore the leased properties to their original condition. Currently and in the past, the Company has been party to such matters in Louisiana. With regard to pending matters, the overall exposure is not currently determinable. The Company intends to vigorously oppose these claims.

11. REDEEMABLE CONVERTIBLE PREFERRED STOCK

The table below summarizes the Company’s Redeemable Convertible Preferred Stock issuances as of December 31, 2025:


Preferred Stock ^(1)^		Issuance Date	Shares	Conversion Price		Net Equity Recorded ^(2)^^^(in thousands)		Cumulative Non-cash Deemed Dividends ^(2)^(in thousands)		Total Net Equity & Cumulative Deemed Dividends (in thousands)		Initial Deemed Dividend Date
Series A		March 28, 2023	25,000	$	9.03	$	23,541	$	22,745	$	46,286	March 31, 2023
Series A-1		September 6, 2023	38,000	$	7.63		36,941		28,693		65,634	September 30, 2023
Series A-2		December 15, 2023	35,000	$	6.21		34,006		23,902		57,908	December 31, 2023
Series A-3		March 27, 2024	20,000	$	6.83		19,397		9,092		28,489	March 31, 2024
Series A-4		May 13, 2024	20,000	$	6.42		19,385		8,539		27,924	June 30, 2024
			138,000			$	133,270	$	92,971	$	226,241
(1)	At the option of the Company, Series A through A-4 receive either annual dividends paid in cash at a fixed rate of 14.5% or accrued annually at a fixed PIK rate of 16.0% .
---	---
(2)	The preferred stock is originally recorded net of original issue discount and accrued offering costs as mezzanine equity (temporary equity) and subsequently PIK dividends and non-cash deemed dividends are recorded to increase the carrying value of the preferred stock to its redemption amount.
---	---

For accounting purposes, upon issuance of the preferred stock (collectively, the “Redeemable Convertible Preferred Stock”), the Company recorded the net proceeds as mezzanine equity (temporary equity) on the unaudited condensed consolidated balance sheets because it is not mandatorily redeemable but does contain a redemption feature at the option of the preferred holders that is considered not solely within the Company’s control.

The Company paid-in-kind its dividend on the preferred stock of $48.7 million and $31.0 million for the years ended December 31, 2025 and 2024, respectively. The carrying value of the preferred stock, inclusive of PIK dividends, is approximately $226.2 and $177.5 million for the years ended December 31, 2025 and 2024, respectively. PIK dividends are recognized first using the dividend date fair value and then adjusted to redemption value as long as the redemption value exceeds the initial dividend date fair value.

Voting Rights. Holders of shares of the Redeemable Convertible Preferred Stock have no voting rights with respect to the shares of Redeemable Convertible Preferred Stock.

Dividends. Holders of Redeemable Convertible Preferred Stock are entitled to receive cumulative dividends at a fixed rate of 14.5% per annum on the Liquidation Preference ($1,000 per share, or $98.0 million, increased for any PIK accruals), compounding and accruing quarterly in arrears. Dividends may be paid in cash or, if not declared and paid in cash, the amount of any such dividend shall automatically accrue at a fixed rate of 16.0% per annum on the Liquidation Preference and be added to the Liquidation Preference (a “PIK Accrual”). Currently, the Company’s Amended Term Loan Agreement prohibits the payment of cash dividends. Additionally, while the Company has not declared or paid dividends on its common stock since its inception, holders of preferred stock will be entitled to participate in any dividends or permitted distributions to holders of common stock on an as-converted basis should they occur. 82

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Conversion Features. In addition to the conversion rights noted in “Redemption Features (Change of Control)” below, holders of Redeemable Convertible Preferred Stock may convert their shares into common stock at the Conversion Ratio equal to the then applicable Liquidation Preference at the time of conversion divided by the then applicable Conversion Price (initially equal to an 18% premium to the volume weighted average price of common stock for the 20 trading days immediately preceding the closing date). Additionally, the Company has the right, at its option, to convert outstanding shares of Redeemable Convertible Preferred Stock into common stock at the Conversion Ratio should the Company meet certain calculated valuation metrics which when divided by the number of outstanding shares of common stock equals or exceeds 130% of the Conversion Price.

Redemption Features (Issuer). The Company has the option to redeem the preferred stock in cash for an amount per share of Preferred Stock equal to (the “Redemption Price”):

●	at any time after the first anniversary of the closing date but on or prior to the second anniversary of the closing date, 108% of the Liquidation Preference at such time; and
●	at any time after the second anniversary of the closing date, 120% of the Liquidation Preference at such time.
---	---

Redemption Features (Change of Control). In the event of a change of control, holders have the right to receive:

●

at any time after the one hundred fiftieth (150th) day following the issuance date, the Company shall offer each Holder a cash payment equal to the Redemption Price. Holders shall also have the ability to elect conversion into common stock at the Conversion Ratio. Until (i) a termination of or certain amendments to the Amended Term Loan Agreement or (ii) one year past the maturity date of the Amended Term Loan Agreement, an election of the cash payment option by holders in a change of control scenario is not permitted.

12. STOCKHOLDERS’ (DEFICIT) EQUITY

Common Stock

Pursuant to the Company’s amended and restated certificate of incorporation with the Delaware Secretary of State, , among other things, (i) the total number of shares of all classes of capital stock that Battalion has the authority to issue is 101,000,000 of which 100,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share and (ii) Battalion is restricted from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code.

Incentive Plans

The Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the “Plan”), as amended in 2021, in which an aggregate of approximately 1.8 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. As of December 31, 2025, a maximum of 1.3 million shares of the Company’s common stock remained reserved for issuance under the Plan. For the years ended December 31, 2025 and 2024, the Company recognized an expense of less than $0.1 million and approximately $0.2 million, respectively, related to stock-based compensation awards granted to employees and directors, primarily related to restricted stock unit grants. Stock-based compensation is recorded as a component of “General and administrative” on the consolidated statements of operations.

Restricted Stock Units

From time to time, the Company grants shares of restricted stock units (“RSUs”) under the Plan to employees of the Company. Under the Plan, employee RSUs will vest and convert to shares typically in equal amounts over a three or four year vesting period from the date of the grant, depending on award, or when the performance or market conditions 83

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

described below occur. At December 31, 2025, the Company had no unrecognized compensation expense of unrecognized compensation expense related to non-vested RSU awards. At December 31, 2024, the Company had less than $0.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of 0.1 years.

The following table sets forth the restricted stock unit transactions for the periods indicated:


		Number of Shares		Weighted Average Grant Date Fair Value Per Share			Aggregate Intrinsic Value^(1)^^^(In thousands)
Unvested outstanding shares at December 31, 2024		147,037		$	12.90		$	192
Granted		—			—
Vested		—			—
Forfeited		(111,618)			13.22
Unvested outstanding shares at December 31, 2025		35,419		$	—		$	—
(1)	The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2025 and 2024 of the underlying stock multiplied by the number of restricted shares that would be issuable. There were no shares vested during the year ended December 31, 2025.
---	---
(2)	Unvested outstanding shares at December 31, 2025 are performance-based RSUs that will vest in full only upon achievement of certain business combination goals, as defined in the awards agreements. The aggregate grant date fair value of these RSUs was $0.4 million. As of December 31, 2025, no expense had been recognized for these awards as a business combination, as defined in the award agreements, had not been consummated.
---	---

Equity Grant Units

During September and November 2024, the Company issued in aggregate 229,023 equity grant units (“EGUs”) to Company executives and certain eligible employees. Each EGU represented the right to receive a cash payment equivalent to the value of a share of the Company’s common stock upon the closing of a change of control event. In March 2025, all outstanding EGU awards were rescinded and cancelled. The Company did not record any expense related to the EGUs during the year ended December 31, 2025.

Stock Options

Prior to 2020, the Company granted stock options under the Plan covering shares of common stock to employees of the Company. Stock options, if exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. Stock option awards granted under the Plan vest over a four-year period at a rate of one-fourth on the annual anniversary date of the grant and expire seven years from the date of grant.

At December 31, 2025, the Company had 106,257 options outstanding (three equal tranches of 35,419 options at exercise prices of $18.91, $28.23, and $37.83 per share) with a weighted average exercise price of $28.32 per share and an expiration date of February 20, 2027. As of December 31, 2025, no options were either exercisable nor had intrinsic value due to service performance conditions and/or based on the exercise price of the option exceeding the closing market price. The weighted average remaining contractual life at December 31, 2025 was approximately 1.1 years. There is no unrecognized compensation expense remaining as the stock options were fully expensed as of December 31, 2025. ****

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

13. INCOME TAXES

Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands):


	Years Ended December 31,
	2025		2024
Current:
Federal	$	—	$	—
State		—		—
		—		—
Deferred:
Federal		—		—
State		—		—
		—		—
Total income tax benefit (provision)	$	—	$	—

The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the year ended December 31, 2025:


		Amount (in thousands)	Percent
U.S. Federal Statutory Rate	$	2,495	21.00%

State & Local Income Taxes, Net of Federal Income Tax Effect
State income taxes - Other, Net		—	0.00%
State Change in Valuation Allowance		—	0.00%
State income taxes - 2024 Return to Provision		—	0.00%

Changes in Valuation Allowances		(1,034)	(8.70)%
Nontaxable or Nonductible Items
Percentage Depletion in Excess of Basis		—	0.00%
Federal RTP - Capital Loss Utilized		(1,473)	(12.40)%
Other, net		12	0.10%
Effective Tax Rate	$	—	0.00%

The following table presents the required disclosures prior to the adoption of ASU 2023-09 and reconciles the actual income tax benefit (provision) to the expected income tax benefit (provision) as computed by applying the U.S. federal corporate income tax rate of 21% for the period presented (in thousands):


	Years Ended December 31, 2024
Expected tax benefit (provision)	$	6,695
Change in valuation allowance and related items		107,573
Permanent adjustments		(6)
Net operating loss write-off Section 382		(785)
Non-deductible compensation		—
Capital loss carryover expiration		(113,940)
Merger transaction costs		541
Other		(78)
Total income tax benefit (provision)	$	—

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):


	December 31, 2025		December 31, 2024
Deferred noncurrent income tax assets:
Net operating loss carry-forwards	$	203,791	$	188,971
Built in loss adjustment Section 382		693		693
Capital loss carryforward		—		—
Stock-based compensation expense		1,733		1,723
Asset retirement obligations		4,376		4,023
Book-tax differences in property basis		80,228		93,974
Unrealized hedging transactions		—		1,735
Disallowed interest Section 163(j)		28,811		25,011
Embedded derivative liability		—		—
Operating lease liability		182		103
Amortization of debt issuance costs		1,226		—
Loss on extinguishment of debt		1,573		1,573
Other		450		703
Gross deferred noncurrent income tax assets		323,063		318,509
Valuation allowance		(316,411)		(317,445)
Deferred noncurrent income tax assets	$	6,652	$	1,064

Deferred noncurrent income tax liabilities:
Basis difference in debt	$	(615)	$	(615)
Investment in unconsolidated subsidiary		(270)		(270)
Amortization of debt issuance costs		—		(84)
Embedded derivative liability		(1,145)		—
Unrealized hedging transactions		(4,446)		—
Lease right of use		(176)		(95)
Deferred noncurrent income tax liabilities	$	(6,652)	$	(1,064)
Net noncurrent deferred income tax assets (liabilities)	$	—	$	—

The amount of U.S. consolidated Net Operating Losses (“NOLs”) available as of December 31, 2025 after attribute reduction is estimated to be approximately $1.4 billion, but the amount after attribute reduction and the Section 382 limitation is $970.4 million. Of this amount, $88.9 million is subject to the 20-year carryforward period and will expire in 2037. The remaining $881.5 million may be carried forward indefinitely but is in part subject to a Section 382 limitation.

The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated 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 in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2025, a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2025 of $316.4 million, a decrease of $1.0 million from December 31, 2024. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized. 86

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the year ended December 31, 2025 and 2024. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations in “Interest expense and other” or consolidated balance sheets as of December 31, 2025 and 2024. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months.

Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.

Generally, the Company’s income tax years 2021 through 2025 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three-year statue expiration period for federal purposes.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBBA”) was enacted in the U.S. The OBBBA includes significant provisions, such as the permanent extension of certain expiring provisions of the Tax Cust and Jobs Act, modifications to the international tax framework and the restoration of favorable tax treatment for certain business provisions. The legislation has multiple effective dates, with certain provisions effective in 2025 and other implemented through 2027. These provisions had no impact on the Company’s consolidated financial statements for the year ended December 31, 2025. The Company is evaluating the impact of provisions required at future dates but does not expect such to have a material impact on its results of operations, cash flows or financial condition. 87

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

14. EARNINGS PER SHARE

The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts):


	Years Ended December 31,
	2025		2024
Basic:
Net income (loss)	$	11,879	$	(31,882)
Less: Preferred stock dividend		(48,706)		(32,219)
Net (loss) income available to common stockholders	$	(36,827)	$	(64,101)
Weighted average basic number of common shares outstanding basic		16,457		16,457
Basic net (loss) income per share of common stock	$	(2.24)	$	(3.90)

Diluted:
Net (loss) income available to common stockholders basic	$	(36,827)	$	(64,101)
Net (loss) income available to common stockholders diluted	$	(36,827)	$	(64,101)
Weighted average basic number of common shares outstanding		16,457		16,457
Common stock equivalent shares representing shares issuable upon:
Exercise of stock options		Anti-dilutive		Anti-dilutive
Vesting of restricted stock units		Anti-dilutive		Anti-dilutive
Weighted average diluted number of common shares outstanding diluted		16,457		16,457
Diluted net income (loss) per share of common stock	$	(2.24)	$	(3.90)

For the year ended December 31, 2025, common stock equivalents, including stock options and certain restricted stock units, totaling 0.1 million weighted-average shares were anti-dilutive and not included in the computation of diluted earnings per share of common stock. For the year ended December 31, 2024, common stock equivalents, including stock options and certain restricted stock units, totaling 0.2 million weighted-average shares were anti-dilutive and not included in the computation of diluted earnings per share of common stock. Additionally, the Company also has less than 0.1 million restricted stock units that vest only upon achievement of certain business combination goals as further described in Note 12, “Stockholder’s Equity”. 88

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

15. ADDITIONAL FINANCIAL STATEMENT INFORMATION

Certain balance sheet amounts are comprised of the following (in thousands) for the periods presents:


		2025		2024
Accounts receivable, net:
Oil, natural gas and natural gas liquids revenues		$	8,468	$	23,516
Joint interest accounts			1,383		2,140
Other			2,220		642
		$	12,071	$	26,298
Prepaids and other:
Prepaids		$	621	$	572
Funds in escrow			171		349
Other			100		61
		$	892	$	982
Other assets (Non-current):
Investment in unconsolidated affiliate		$	—	$	940
Funds in escrow			599		578
Other			2,761		760
		$	3,360	$	2,278
Accounts payable and accrued liabilities:
Trade payables		$	12,629	$	15,663
Accrued oil and natural gas capital costs			5,685		7,800
Revenues and royalties payable			10,901		19,816
Accrued interest expense			67		330
Accrued employee compensation			385		1,472
Accrued lease operating expenses			8,000		7,597
Other			2,067		4
		$	39,734	$	52,682

Investment in Unconsolidated Affiliate. In May 2022, the Company entered into a joint venture with Caracara Services, LLC (“Caracara”) to develop an acid gas treatment facility to remove hydrogen sulfide and carbon dioxide from its produced natural gas. Caracara provided the initial capital for the construction of the treatment facility. The Company contributed certain full cost pool assets to the related party joint venture in a non-cash exchange for a retained 5% equity interest in Wink Amine Treater, LLC (“WAT”), an unconsolidated subsidiary. For accounting purposes, since the Company does not control the key activities (e.g. operating and maintaining the facility) which most significantly impact economic performance, the Company is not the primary beneficiary of WAT. Accordingly, the Company accounted for its investment in WAT (a related party) using the equity method of accounting based on its ability to exercise significant influence, but not control, over the key activities of the joint venture. During the fourth quarter of 2025, as a result of the AGI Facility’s continued shut-down, the Company concluded that the fair value of its equity method investment in WAT was less than the carrying value of the investment in unconsolidated affiliate asset recorded on the 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. For more information related to this joint venture, see Note 10, “Commitments and Contingencies”. 89

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BATTALION OIL CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Certain income statement amounts are comprised of the following (in thousands) for the periods presents:


		December 31, 2025		December 31, 2024
Interest expense and other
Interest expense		$	28,835	$	29,009
Interest income			(2,260)		(2,122)
Mark-to-market of derivatives - change of control call option			—		(2,084)
Merger Termination Payment			—		(10,000)
Other			172		153
		$	26,747	$	14,956

SUBSEQUENT EVENTS

Subsequent events have been evaluated through the date of issuance of these financial statements and there have been no events subsequent to December 31, 2025, other than those items disclosed below, that would require additional adjustments to or disclosure in our financial statements during the period.

Pursuant to the West Quito Divestiture Agreement, on February 24, 2026, the Company completed the closing of the West Quito Divestiture and MCM acquired from the Company approximately 7,600 gross (6,100 net) acres of leasehold interests in the West Quito Draw area, including production from interests in producing wells, for net proceeds of approximately $60.1 million, reflecting adjustment for accounting effective date of December 1, 2025 and other customary adjustments. The Company will not record a gain or loss related to the divestiture as it was not significant to the full cost pool. Subsequent to closing, the Company 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.

On February 24, 2026, the Company 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 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) the Company was 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. The Company may retain the remaining net cash proceeds received from the West Quito Divestiture, subject to certain reinvestment requirements, set forth in the Third Amendment.

On March 3, 2026, the Company entered into a definitive agreement to sell in a private placement to an institutional investor 1,800,000 shares of its 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.

On March 10, 2026, the Company 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, and upon closing on March 19, 2026, the Company issued 485,000 shares of its common stock to RoadRunner in exchange for the assets. The acquired acreage is directly adjacent to the Company’s existing Monument Draw acreage. The transaction is subject to customary post-closing adjustments and will be accounted for as an asset acquisition for the quarterly period ending March 31, 2026, allocating the relative amounts of the purchase price to proved and unproved oil and natural gas properties. 90

Table of Contents SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

The reserves information in this Annual Report on Form 10-K represents only estimates. Reserve engineering 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. As a result, estimates of different engineers may vary. 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 the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates reported herein for the years ended December 31, 2025 and 2024 have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineering firm. For additional information regarding estimates of proved reserves and other information about our oil and gas reserves, see Item 1. Business and the report of NSAI which is included as an Exhibit to this Annual Report on Form 10-K.

The following tables illustrate changes in the Company’s estimated net proved developed and proved undeveloped reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2025 and 2024 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $66.01 per barrel and $76.32 per barrel, respectively. The natural gas prices as of December 31, 2025 and 2024 are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $3.39 per MMBtu and $2.13 per MMBtu, respectively. All prices are adjusted by lease or 91

Table of Contents field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.


		Total Proved Reserves
						Natural Gas
				Natural Gas		Liquids		Equivalent
		Oil (MBbls)		(MMcf)		(MBbls)		(MBoe)
Proved reserves, December 31, 2023		34,622		111,749		14,860		68,107
Extensions and discoveries		2,968		4,635		293		4,034
Production		(2,363)		(7,814)		(971)		(4,636)
Revision of previous estimates^(1)^		(442)		(3,157)		(1,589)		(2,558)
Proved reserves, December 31, 2024		34,785		105,413		12,593		64,947
Extensions and discoveries		1,196		3,106		373		2,087
Production		(2,251)		(7,451)		(922)		(4,415)
Revision of previous estimates^(1)^		(1,930)		(3,520)		(400)		(2,917)
Proved reserves, December 31, 2025		31,800		97,548		11,644		59,702


		Equivalent (Mboe)
		Proved		Proved
		Developed		Undeveloped		Total Proved
		Reserves		Reserves		Reserves
Proved reserves, December 31, 2023		40,129		27,978		68,107
Extensions and discoveries		—		4,034		4,034
Production		(4,636)		—		(4,636)
Transfers		2,951		(2,951)		—
Revision of previous estimates^(1)^		(2,140)		(418)		(2,558)
Proved reserves, December 31, 2024		36,304		28,643		64,947
Extensions and discoveries		25		2,062		2,087
Production		(4,415)		—		(4,415)
Transfers		5,489		(5,489)		—
Revision of previous estimates^(1)^		(1,754)		(1,163)		(2,917)
Proved reserves, December 31, 2025		35,649		24,053		59,702


		Proved Developed Reserves
						Natural Gas
				Natural Gas		Liquids		Equivalent
		Oil (MBbls)		(MMcf)		(MBbls)		(MBoe)
December 31, 2025		17,119		65,488		7,615		35,649
December 31, 2024		17,661		64,361		7,916		36,304


		Proved Undeveloped Reserves
						Natural Gas
				Natural Gas		Liquids		Equivalent
		Oil (MBbls)		(MMcf)		(MBbls)		(MBoe)
December 31, 2025		14,681		32,060		4,029		24,053
December 31, 2024		17,124		41,052		4,677		28,643

(1)	Downward revisions for 2025 and 2024 of 2.9 MMBoe and 2.6 MMBoe, respectively, were primarily due to decreased pricing and changes in differentials, deducts and marketing expenses.

Year Ended December 31, 2025

At December 31, 2025, the Company’s proved developed reserves of 35.7 MMBoe decreased approximately 0.7 MMBoe from December 31, 2024 primarily as a result of negative revisions of 1.8 MMBoe and production of 4.4 MMBoe offset by PUD reserve development of 5.5 MMBoe. 92

Table of Contents At December 31, 2025, the Company’s estimated proved undeveloped (PUD) reserves of 24.1 MMBoe decreased approximately 4.6 MMBoe from December 31, 2024 as a result of extensions of 2.1 MMBoe primarily associated with infill drilling activity offset by the transfer of 5.5 MMBoe to proved developed producing reserves and downward revisions of 1.2 MMBoe due to decreased SEC prices. All of the Company’s 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 proved undeveloped reserves, which includes drilling, completion and other facility costs.

Year Ended December 31, 2024

At December 31, 2024, the Company’s proved developed reserves of 36.3 MMBoe decreased approximately 3.8 MMBoe from December 31, 2023 primarily as a result of negative revisions of 2.1 MMBoe and production of 4.6 MMBoe offset by PUD reserve development of 2.9 MMBoe.

At December 31, 2024, the Company’s estimated proved undeveloped (PUD) reserves of 28.6 MMBoe increased approximately 0.7 MMBoe from December 31, 2023 as a result of extensions of 4.0 MMBoe primarily associated with infill drilling activity offset by the transfer of 2.9 MMBoe to proved developed producing reserves and downward revisions of 0.4 MMBoe due to decreased SEC prices. All of the Company’s PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2024, approximately $28.0 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

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, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic EURs from individual producing wells. The Company 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.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depletion, depreciation and accretion (in thousands):


	December 31, 2025		December 31, 2024
Evaluated oil and natural gas properties	$	890,050	$	816,186
Unevaluated oil and natural gas properties		48,025		49,091
		938,075		865,277
Accumulated depletion		(547,982)		(497,272)
	$	390,093	$	368,005

Table of Contents Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:


		Years Ended December 31,
		2025		2024

Property acquisition costs, proved		$	—	$	47
Property acquisition costs, unproved			—		—
Exploration and extension well costs			—		24,341
Development costs^(1)^			61,674		27,979
Total costs		$	61,674	$	52,367
(1)	Excludes $11.1 million and $5.5 million for the years ended December 31, 2025 and 2024, respectively, of development costs related to the Company’s treating equipment and gathering support facilities.
---	---

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractive Activities—Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

●	future costs and selling prices will probably differ from those required to be used in these calculations;
●	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
---	---
●	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
---	---
●	future net revenues may be subject to different rates of income taxation.
---	---

At December 31, 2025 and 2024, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure is as follows:


	Years Ended December 31,
	2025		2024
	(In thousands)
Future cash inflows	$	2,366,784	$	2,835,559
Future production costs		(1,310,134)		(1,492,390)
Future development costs		(308,272)		(435,809)
Future income tax expense		(15,680)		(20,655)
Future net cash flows before 10% discount		732,698		886,705
10% annual discount for estimated timing of cash flows		(389,180)		(439,002)
Standardized measure of discounted future net cash flows	$	343,518	$	447,703

Table of Contents Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2025:


	Years Ended December 31,
	2025		2024
	(In thousands)
Beginning of year	$	447,703	$	598,481
Sale of oil and natural gas produced, net of production costs		(75,827)		(98,327)
Sales of minerals in place		—		—
Extensions and discoveries		21,960		165,394
Changes in income taxes, net		2,581		3,964
Changes in prices and costs		(145,574)		(144,418)
Previously estimated development costs incurred		67,527		39,046
Net changes in future development costs		33,523		330
Revisions of previous quantities		(22,566)		(179,279)
Accretion of discount		45,850		61,324
Changes in production rates and other		(31,659)		1,188
End of year	$	343,518	$	447,703

Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(f) and 15d-15(f), of the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer, of the effectiveness of our disclosure controls and procedures based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer concluded that our disclosure controls and procedures were effective as of December 31, 2025 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Management has assessed our internal control over financial reporting as of December 31, 2025. The unqualified report of management thereon is included in Item 8. Consolidated Financial Statements and Supplementary Data of this Annual Report on Form 10-K and is incorporated by reference herein.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, during the three months ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B**.** OTHER INFORMATION

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

Table of Contents PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pursuant to General Instruction 6 to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.

The Company's Code of Conduct and Code of Ethics for the Principal Executive Officer and Senior Financial Officers can be found on the Company's website located at www.battalionoil.com. Any stockholder may request a printed copy of such materials by submitting a written request to the Company's Corporate Secretary. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least twelve months after the initial disclosure of such waiver.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS ****

Equity Compensation Plan Information

The following table sets forth certain information as of December 31, 2025 with respect to compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance.


							Number of Securities
							Remaining Available for
							Future Issuance Under
		Number of Securities			Weighted-Average		Equity Compensation
		to be Issued Upon Exercise			Exercise Price of		Plans (Excluding
		of Outstanding			Outstanding Options and		Securities Reflected in
Plan Category		Options and Rights(A)^(1)^			Rights		Column(A))
Equity compensation plans approved by security holders.		—		$	—		—
Equity compensation plans not approved by security holders^(2)^		141,676			28.32		1,310,648
		141,676		$	28.32		1,310,648
(1)	Consists of 35,419 unvested RSUs and outstanding 106,257 stock options.
---	---
(2)	The formation of the plan was approved by the Bankruptcy Court upon confirmation of our Plan of Reorganization in 2019 and further approved by our board with an effective date of January 1, 2020.
---	---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Table of Contents ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1)	Consolidated Financial Statements:

The consolidated financial statements of the Company and its subsidiaries and reports of independent registered public accounting firms listed in Section 8 of this Annual Report on Form 10-K are filed as a part of this Annual Report on Form 10-K.

(2)	Consolidated Financial Statements Schedules:

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

(3)	Exhibits:

---	---	---
2.1		Order of the Bankruptcy Court, dated September 24 2019, confirming the Joint Prepackaged Plan of Reorganization of Halcón Resources Corporation, et al, under Chapter 11 of the Bankruptcy Code, together with such Joint Prepackaged Plan of Reorganization (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed September 26, 2019).
3.1		Ninth Amended and Restated Certificate of Incorporation of Battalion Oil Corporation, dated June 12, 2025 (Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed June 18, 2025).
3.2		Seventh Amended and Restated Bylaws of Battalion Oil Corporation (Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed January 27, 2020).
4.1		Description of Battalion Oil Corporation’s securities registered under Section 12 of the Exchange Act. (Incorporated by reference to Exhibit 4.1 of our Annual Report on Form 10-K filed March 25, 2020).
4.2		Form of Pre-Funded Warrant (Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed March 9, 2026).
10.1		Second Amended and Restated Senior Secured Credit Agreement dated as of December 26, 2024, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 27, 2024).
10.1.1		First Amendment to Second Amended and Restated Senior Secured Credit Agreement dated as of January 9, 2025, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 10, 2025).
10.1.2		Second Amendment to Second Amended and Restated Senior Secured Credit Agreement dated as of November 12, 2025, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1.2 of our Quarterly Report on Form 10-Q filed November 13, 2025).

Table of Contents

10.1.3		Limited Consent and Third Amendment to Second Amended and Restated Senior Secured Credit Agreement dated as of February 24, 2026, by and among Battalion Oil Corporation, as holdings, Halcón Holdings LLC, as borrower, the subsidiary guarantors party thereto, Fortress Credit Corp., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed February 25, 2026).
10.2		Registration Rights Agreement, dated October 8, 2019, by and among Halcón Resources Corporation and each of the parties thereto, as investors (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed October 8, 2019).
10.2.1		First Amendment to Registration Rights Agreement dated March 28, 2023, by and among Battalion Oil Corporation and each of the parties thereto, as investors (Incorporated by reference to Exhibit 10.3.1 of our Annual Report on Form 10-K filed March 30, 2023).
10.2.2		Second Amendment to Registration Rights Agreement dated September 6, 2023, by and among Battalion Oil Corporation and each of the parties thereto, as investors (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed September 7, 2023).
10.2.3		Third Amendment to Registration Rights Agreement dated December 15, 2023, by and among Battalion Oil Corporation and each of the other parties thereto, as investors (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed December 18, 2023).
10.2.4		Fourth Amendment to Registration Rights Agreement dated March 27, 2024, by and among Battalion Oil Corporation and each of the other parties thereto, as investors. (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed March 28, 2024).
10.2.5		Fifth Amendment to Registration Rights Agreement dated May 13, 2024, by and among Battalion Oil Corporation and each of the other parties thereto, as investors. (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed May 14, 2024).
10.3	^†^	Battalion Oil Corporation 2020 Long-Term Incentive Plan, effective as of January 1, 2020 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 31, 2020).
10.3.1	^†^	Amendment No. 1 to the Battalion Oil Corporation 2020 Long-Term Incentive Plan, effective as of June 8, 2021 (Incorporated by reference to Exhibit 10.1.1 of our Current Report on Form 8-K filed June 14, 2021).
10.4	^†^	Merger Incentive Plan, adopted as of September 19, 2024 (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed November 12, 2024).
10.5	^†^	Employment Agreement between Daniel P. Rohling and Battalion Oil Corporation effective as of January 28, 2020 (Incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K filed March 25, 2020).
10.6		Purchase Agreement (Series A Preferred Stock), dated March 28, 2023, by and among Battalion Oil Corporation and each of the purchasers set forth on Schedule A thereto (Incorporated by reference to Exhibit 10.8 of our Annual Report on Form 10-K filed March 30, 2023).
10.7		Purchase Agreement (Series A-1 Preferred Stock), dated September 6, 2023, by and among Battalion Oil Corporation and each of the purchasers set forth on Schedule A thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 7, 2023).
10.8		Purchase Agreement (Series A-2 Preferred Stock), dated December 15, 2023, by and among Battalion Oil Corporation and each of the purchasers set forth on Schedule A thereto (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed December 18, 2023).
10.9		Purchase Agreement (Series A-3 Preferred Stock), dated March 27, 2024, by and among Battalion Oil Corporation and each of the purchasers set forth on Schedule A thereto. (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed March 28, 2024).
10.10		Purchase Agreement (Series A-4 Preferred Stock), dated May 13, 2024, by and among Battalion Oil Corporation and each of the purchasers set forth on Schedule A thereto. (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed May 14, 2024).
10.11	^†^	Material Terms of Employment Arrangements between Walter R. Mayer and Battalion Oil Corporation (Incorporated by reference to Exhibit 10.9 of our Annual Report Amendment on Form 10-K/A filed April 28, 2023).

Table of Contents

10.12	^†^	Form of Nonqualified Stock Option Award Agreement (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed January 31, 2020).
10.13	^†^	Form of Base Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed January 31, 2020).
10.14	^†^	Form of Performance-Based Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed January 31, 2020).
10.15	^†^	Form of M&A Restricted Stock Unit Award Agreement (Incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed January 31, 2020).
10.16	^†^	Form of Retention Letter Agreement (Incorporated by reference to Exhibit 10.16 of our Annual Report on Form 10-K filed March 31, 2025).
10.17	*	Agreement of Sale and Purchase, dated effective as of December 1, 2025, by and among certain subsidiaries of Battalion Oil Corporation and MCM Delaware Resources, LLC.
10.18		Securities Purchase Agreement, dated March 3, 2026 (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed March 9, 2026).
10.19		Registration Rights Agreement, dated March 3, 2026 (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed March 9, 2026).
10.20	^*^	Purchase and Sale Agreement, dated March 10, 2026, by and among Battalion Oil Corporation, Halcón Energy Properties, Inc. and RoadRunner Resource Holding LLC.
19		Amended and Restated Insider Trading Policy (Incorporated by reference to Exhibit 19 of our Annual Report on Form 10-K filed March 31, 2025).
21.1	^*^	List of Subsidiaries of Battalion Oil Corporation
31	^*^	Sarbanes-Oxley Section 302 certification of Principal Executive Officer and Principal Financial Officer
32	^*^	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
97		Incentive Compensation Recoupment Policy (Incorporated by reference to Exhibit 97 of our Annual Report on Form 10-K filed April 1, 2024).
99.1	^*^	Report of Netherland, Sewell & Associates, Inc.
101.INS	^*^	Inline XBRL Instance Document
101.SCH	^*^	Inline XBRL Taxonomy Extension Schema Document
101.CAL	^*^	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	^*^	Inline XBRL Taxonomy Extension Definition Document
101.LAB	^*^	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE	^*^	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	^*^	Cover Page Interactive Data File (embedded within the Inline XBRL document)

^*^	Attached hereto.
^†^	Indicates management contract or compensatory plan or arrangement.
---	---

The registrant has not filed with this report copies of the instruments defining rights of all holders of long-term debt of the registrant and its consolidated subsidiaries based upon the exception set forth in Item 601(b)(4)(iii)(A) of Regulation S-K. Copies of such instruments will be furnished to the SEC upon request.

ITEM 16. FORM 10-K SUMMARY

None.

100

Table of Contents SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BATTALION OIL CORPORATION


Date: March 23, 2026	By:	/s/ MATTHEW B. STEELE
		Matthew B. Steele<br><br>Chief Executive Officer
		(Principal Executive Officer and Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature		Title		Date


/s/ MATTEW B. STEELE<br><br>Matthew B. Steele		Director and Chief Executive Officer		March 23, 2026


/s/ JONATHAN BARRETT<br><br>Jonathan Barrett		Chairman of the Board		March 23, 2026


/s/ GREGORY HINDS<br><br>Gregory Hinds		Director		March 23, 2026


/s/ WILLIAM ROGERS<br><br>William Rogers		Director		March 23, 2026

101

Exhibit 10.17 Execution Version

AGREEMENT OF SALE AND PURCHASE

BY AND AMONG

HALCÓN ENERGY PROPERTIES, INC.,

HALCÓN PERMIAN, LLC,

HALC o N OPERATING CO., INC.

AND

HALCÓN FIELD SERVICES, LLC

AS SELLERS

AND

MCM DELAWARE RESOURCES, LLC

AS PURCHASER

DECEMBER 1, 2025

TABLE OF CONTENTS

Page Article 1 PURCHASE AND SALE‌1Section 1.1Purchase and Sale.‌1Section 1.2Assets.‌1Section 1.3Excluded Assets.‌3Section 1.4Effective Time; Proration of Costs and Revenues.‌4Section 1.5Delivery and Maintenance of Records.‌6Article 2 PURCHASE PRICE‌6Section 2.1Purchase Price.‌6Section 2.2Adjustments to Purchase Price.‌6Section 2.3Allocation of Purchase Price.‌8Section 2.4Deposit.‌8Section 2.5Tax Allocation.‌9Article 3 TITLE MATTERS‌9Section 3.1Sellers’ Title.‌9Section 3.2Definitions of Title Matters.‌10Section 3.3Definition of Permitted Encumbrances.‌12Section 3.4Notice of Title Defect Adjustments.‌13Section 3.5Casualty or Condemnation Loss.‌19Section 3.6Limitations on Applicability.‌19Section 3.7Government Approvals Respecting Assets.‌20Article 4 ENVIRONMENTAL MATTERS‌21Section 4.1Assessment.‌21Section 4.2NORM, Wastes and Other Substances.‌21Section 4.3Environmental Defects.‌22Section 4.4Inspection Indemnity.‌24Article 5 REPRESENTATIONS AND WARRANTIES OF SELLERS‌24Section 5.1Generally.‌24Section 5.2Existence and Qualification.‌25Section 5.3Power.‌25Section 5.4Authorization and Enforceability.‌25Section 5.5No Conflicts.‌26Section 5.6Liability for Brokers’ Fees.‌26Section 5.7Litigation.‌26Section 5.8Taxes and Assessments.‌26Section 5.9Compliance with Laws.‌27

Section 5.10Contracts.‌27Section 5.11Payments for Hydrocarbon Production.‌28Section 5.12Governmental Authorizations.‌28Section 5.13Preference Rights and Transfer Requirements.‌29Section 5.14Payout Balances.‌29Section 5.15Outstanding Capital Commitments.‌29Section 5.16Imbalances.‌29Section 5.17Condemnation.‌30Section 5.18Bankruptcy.‌30Section 5.19Production Allowables.‌30Section 5.20Foreign Person.‌30Section 5.21Drilling Obligations.‌30Section 5.22Plugging and Abandonment.‌30Section 5.23No Material Adverse Change.‌31Section 5.24Bonds.‌31Section 5.25Suspended Funds.‌31Section 5.26Reasonably Equivalent Value.‌31Section 5.27Liens.‌31Section 5.28Financial Statements.‌31Article 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER‌32Section 6.1Existence and Qualification.‌32Section 6.2Power.‌32Section 6.3Authorization and Enforceability.‌32Section 6.4No Conflicts.‌32Section 6.5Liability for Brokers’ Fees.‌33Section 6.6Litigation.‌33Section 6.7R&W Insurance Policy.‌33Section 6.8Limitation and Independent Evaluation.‌33Section 6.9SEC Disclosure.‌34Section 6.10Bankruptcy.‌34Section 6.11Qualification.‌34Section 6.12Financing.‌34Article 7 COVENANTS OF THE PARTIES‌34Section 7.1Access.‌34Section 7.2Government Reviews.‌36Section 7.3Notification of Breaches.‌36Section 7.4Letters in Lieu; Assignments; Operatorship.‌37Section 7.5Public Announcements.‌38Section 7.6Operation of Business.‌38Section 7.7Preference Rights and Transfer Requirements.‌39Section 7.8Tax Matters.‌40Section 7.9Representation and Warranty Insurance Policy.‌42Section 7.10Further Assurances.‌43

Section 7.11Notice of Claims.‌44Section 7.12Enforcement of Third Party Warranties, Guarantees and Indemnities.‌44Article 8 CONDITIONS TO CLOSING‌44Section 8.1Conditions of Sellers to Closing.‌44Section 8.2Conditions of Purchaser to Closing.‌45Article 9 CLOSING‌46Section 9.1Time and Place of Closing.‌46Section 9.2Obligations of Sellers at Closing.‌46Section 9.3Obligations of Purchaser at Closing.‌47Section 9.4Closing Adjustments.‌48Article 10 TERMINATION‌50Section 10.1Termination.‌50Section 10.2Remedies.‌51Article 11 POST-CLOSING OBLIGATIONS; Survival; LIMITATIONS; DISCLAIMERS AND WAIVERS‌52Section 11.1Receipts.‌52Section 11.2Expenses.‌52Section 11.3Assumed Seller Obligations.‌53Section 11.4Survival; Exclusive Remedy; Release.‌53Section 11.5Indemnification by Each Seller‌55Section 11.6Indemnification by Purchaser.‌55Section 11.7Indemnification Proceedings.‌56Section 11.8Release.‌58Section 11.9Disclaimers.‌58Section 11.10Recording.‌60Article 12 MISCELLANEOUS‌60Section 12.1Counterparts.‌60Section 12.2Notice.‌60Section 12.3Sales or Use Tax Recording Fees and Similar Taxes and Fees.‌61Section 12.4Transaction Expenses.‌61Section 12.5Change of Name.‌61Section 12.6Replacement of Bonds, Letters of Credit and Guarantees.‌62Section 12.7Governing Law and Venue.‌62Section 12.8Captions.‌62Section 12.9Waivers.‌62Section 12.10Assignment.‌62Section 12.11Entire Agreement.‌63

iii

Section 12.12Amendment.‌63Section 12.13No Third-Party Beneficiaries.‌63Section 12.14References.‌63Section 12.15Construction.‌64Section 12.16Conspicuousness.‌64Section 12.17Severability.‌64Section 12.18Time of Essence.‌64Section 12.19Limitation on Damages.‌64Section 12.20Suspended Funds.‌65Section 12.21Joint and Several Liability.‌65Section 12.22Seller Representative.‌65

EXHIBITS

Exhibit A-1		Leases
Exhibit A-2		Wells and Units
Exhibit A-3		Fee Lands
Exhibit B		Conveyance
Exhibit C		Deed
Exhibit D		Representation and Warranty Insurance Policy

SCHEDULES

Schedule 1.2(d)		Contracts
Schedule 1.2(e)		Surface Contracts
Schedule 1.2(f)		Equipment
Schedule 1.2(j)		Proprietary Seismic Data
Schedule 1.2(k)		Vehicles
Schedule 1.3(d)		Excluded Assets
Schedule 1.4		Overhead Costs
Schedule 5.1		Identification of Certain Officers and Employees of Seller and Identification of Certain Officers and Employees of Purchaser
Schedule 5.7(a)		Party Proceedings
Schedule 5.7(b)		Non-Party Proceedings
Schedule 5.8		Taxes and Assessments

	Schedule 5.9		Compliance with Laws
Schedule 5.10		Contract Matters
Schedule 5.11		Hydrocarbon Production Payments
Schedule 5.12		Governmental Authorizations
Schedule 5.13(a)		Preference Rights
Schedule 5.13(b)		Transfer Requirements
Schedule 5.14		Payout Balances
Schedule 5.15		Outstanding Capital Commitments
Schedule 5.16		Imbalances
Schedule 5.22		Plugging and Abandonment
Schedule 5.24		Bonds
Schedule 5.25		Suspended Funds
Schedule 5.27		Liens
Schedule 7.6		Operation of Business
Schedule 9.4(d)		Account Information

DEFINITIONS

“1031 Assets” has the meaning set forth in Section 7.8(c).

“Actual Knowledge” means information actually and personally known to an officer, director or manager of the applicable party to this Agreement.

“Adjusted Purchase Price” shall mean the Purchase Price after calculating and applying the adjustments set forth in Section 2.2.

“Adjustment Period” has the meaning set forth in Section 2.2(a).

“AEA” has the meaning set forth in the definition of Hazardous Materials.

“AFE” means authority for expenditure or other written capital commitments.

“Affiliates” with respect to any Person, means any Person that directly or indirectly controls, is controlled by or is under common control with such Person. The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.

“Aggregate Benefit Deductible” has the meaning set forth in Section 3.4(m).

“Aggregate Defect Deductible” has the meaning set forth in Section 3.4(l).

“Agreed Accounting Firm” has the meaning set forth in Section 9.4(c).

“Agreement” means this Agreement of Sale and Purchase.

“Allocated Value” has the meaning set forth in Section 3.4(a).

“Assets” has the meaning set forth in Section 1.2.

“Assumed Seller Obligations” has the meaning set forth in Section 11.3.

“Bonds” has the meaning set forth in Section 5.24.

“Break-Up Fee” has the meaning set forth in Section 10.2(b).

“Business Day” means each calendar day except Saturdays, Sundays, and federal holidays.

“CERCLA” has the meaning set forth in the definition of Hazardous Materials.

“Claim” means any demand, claim, action or proceeding arising under Law.

“Claim Notice” has the meaning set forth in Section 11.7.

“Closing” has the meaning set forth in Section 9.1(a).

“Closing Date” has the meaning set forth in Section 9.1(b).

“Closing Payment” has the meaning set forth in Section 9.4(a).

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Company” means Battalion Oil Corporation, a Texas corporation.

“Confidentiality Agreement” has the meaning set forth in Section 7.1(a).

“Contracts” has the meaning set forth in Section 1.2(d).

“Conveyance” has the meaning set forth in Section 3.1(a).

“COPAS” has the meaning set forth in Section 1.4(c).

“Cure Period” has the meaning set forth in Section 3.4(c).

“Deed” has the meaning set forth in Section 3.1(a).

“Defensible Title” has the meaning set forth in Section 3.2.

“Delegated Matters” has the meaning set forth in Section 12.22.

“Deposit” has the meaning set forth in Section 2.4.

“DOJ” means the Department of Justice.

“earned” has the meaning set forth in Section 1.4(c).

“Effective Time” has the meaning set forth in Section 1.4(a).

“Environmental Claim Date” has the meaning set forth in Section 4.3(a).

“Environmental Defect” has the meaning set forth in Section 4.3(a).

“Environmental Defect Amount” has the meaning set forth in Section 4.3(a).

“Environmental Defect Notice” has the meaning set forth in Section 4.3(a).

“Environmental Laws” means, as the same may have been amended, any federal, state or local Law and that of any Governmental Body having jurisdiction over the property in question, which exists as of the date of this Agreement and relates to (i) the control of any potential pollutant or protection of the environment, including air, water or land, (ii) the generation, handling, treatment, storage, or disposal or transportation of Hazardous Materials or waste materials, (iii) the regulation of or exposure to Hazardous Materials, or (iv) the cleanup, restoration, remediation of, or other environmental response to Hazardous Materials on, at, or migrating from, any property. The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Body pursuant to the foregoing.

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“Environmental Liabilities” shall mean any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, and other liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body, (in each case) to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets prior to the Closing or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources, remediation or response costs, (in each case) to the extent arising out of any violation of, or any remediation obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets prior to the Closing.

“Equipment” has the meaning set forth in Section 1.2(f).

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Escrow Agent” means Petroleum Strategies, Inc., a Texas corporation.

“Escrow Agreement” means an Escrow Agreement to be entered into by and among Seller Representative, Purchaser and the Escrow Agent, on a form mutually agreed to by such parties.

“Event” has the meaning set forth in the definition of Material Adverse Effect.

“Excluded Assets” has the meaning set forth in Section 1.3.

“Excluded Seller Obligations” has the meaning set forth in Section 11.3.

“Final Settlement Date” has the meaning set forth in Section 9.4(c).

“Final Purchase Price” has the meaning set forth in Section 9.4(b).

“Final Settlement Statement” has the meaning set forth in Section 9.4(b).

“Fraud” means an actual, knowing and deliberate false representation of a material fact by a Party, made with such Party’s Knowledge of the falsity, in a representation or warranty set forth in Article 5 or Article 6 of this Agreement (as modified by the Schedules, as applicable), with the specific intent of such Party of inducing any other Party to enter into this Agreement and upon which such other Party, without prior actual knowledge that such representation was false, has justifiably relied to its resulting actual and material loss. “Fraud” does not include any claim based on (x) constructive fraud, promissory fraud, equitable fraud or unfair dealings fraud or (y) constructive knowledge, recklessness, negligent misrepresentation or a similar theory.

“FTC” means the Federal Trade Commission.

“Fundamental Representations” means those representations and warranties contained in Section 5.2, Section 5.3, Section 5.4, Section 5.6, Section 6.1, Section 6.2, Section 6.3, and Section 6.5.

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“GAAP” means generally accepted accounting principles in effect in the United States as amended from time to time.

“Governmental Authorizations” has the meaning set forth in Section 5.12.

“Governmental Body” or “Governmental Bodies” means any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body, arbitrator or arbitration panel or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Material” means (i) any “hazardous substance,” as defined by Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9602 et seq. (“CERCLA”), (ii) any “hazardous waste” or “solid waste,” in either case as defined by the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. (“RCRA”), and any analogous state statutes, and any regulations promulgated thereunder, (iii) any solid, hazardous, dangerous or toxic chemical, material, waste or substance, within the meaning of and regulated by any applicable Environmental Laws, (iv) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in the Atomic Energy Act, 42 U.S.C. § 2011 et seq. (“AEA”) and any amendments or authorizations thereof, (v) any regulated asbestos-containing materials in any form or condition, (vi) any regulated polychlorinated biphenyls in any form or condition, and (vii) petroleum, petroleum hydrocarbons or any fraction or byproducts thereof.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“Hydrocarbons” means oil, gas, casinghead gas, condensate, natural gas liquids, and other gaseous and liquid hydrocarbons or any combination thereof and sulphur and other minerals extracted from or produced with the foregoing.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether such over-production, under-production, over-delivery, under-delivery or similar imbalance arises at the wellhead, pipeline, gathering system, transportation system, processing plant or other location.

“incurred” has the meaning set forth in Section 1.4(c).

"Indemnified Party" has the meaning set forth in Section 11.7.

"Indemnifying Party" has the meaning set forth in Section 11.7.

“Independent Expert” has the meaning set forth in Section 4.3(b).

“Individual Environmental Threshold” has the meaning set forth in Section 4.3(c).

“Individual Title Benefit Threshold” has the meaning set forth in Section 3.4(m).

“Individual Title Threshold” has the meaning set forth in Section 3.4(l).

“Lands” has the meaning set forth in Section 1.2(a).

“Law” or “Laws” means all statutes, laws, rules, regulations, ordinances, orders, decrees and codes of Governmental Bodies.

“Leases” has the meaning set forth in Section 1.2(a).

“Like-Kind Exchange” has the meaning set forth in Section 7.8(c).

“Loss” or “Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding).

“Lowest Cost Response” means the response required or allowed under Environmental Laws that timely addresses the condition present at the lowest cost (considered as a whole after taking into consideration any negative impact such response may have on the operations of the relevant assets and any potential additional costs or liabilities that could reasonably be expected to arise as a result of or in connection with such response) as compared to any other response that is required or allowed under Environmental Laws.

“Material Adverse Effect” means any change, inaccuracy, circumstance, effect, event, result, occurrence, condition or fact (each an “Event”) (whether or not (i) foreseeable or known as of the date of this Agreement or (ii) covered by insurance) that has had, or could reasonably be expected to have, a material adverse effect on (i) the ownership, operation or value of the Assets, taken as a whole, or (ii) the ability of Seller to consummate the transactions contemplated hereby. Excluded from such Events for the purposes of determining whether a “Material Adverse Effect” has occurred or could reasonably be expected to occur are (A) Events resulting from entering into this Agreement or the announcement of the transactions contemplated by this Agreement, (B) Events resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war or terrorist events, (C) Events that affect the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally (including changes in commodity prices or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally), (D) any effect resulting from a change in Laws or regulatory policies, (E) matters that are cured by the Closing at no cost or liability to Purchaser and no material diminution in value of any affected Asset, and (F) the depletion or watering out of any Well(s), collapsed casing or sand infiltration of any Well(s), drilling results of any Well(s), and/or the depreciation of personal property due to ordinary wear and tear with respect to the Assets, other than, in the case of subsections (B), (C) and (D), as may disproportionately impact any Seller relative to other Persons in the same industry.

“Material Contracts” has the meaning set forth in Section 5.10.

“Net Mineral Acres” means, as computed separately with respect to each Lease, (a) the number of gross acres in the lands covered by such Lease, multiplied by (b) the undivided percentage interest in oil, gas or other minerals covered by such Lease, as applicable, in such lands, multiplied by (c) the applicable Seller’s working interest in such Lease.

“Net Revenue Interest” has the meaning set forth in Section 3.2(a).

“NORM” means naturally occurring radioactive material.

"Notice Period" has the meaning set forth in Section 11.7(a).

“Permitted Encumbrances” has the meaning set forth in Section 3.3.

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Body or any other entity.

“Phase I” or “Phase I Assessment” has the meaning set forth in Section 4.1.

“Preference Property” has the meaning set forth in Section 7.7(b).

“Preference Right” means any right or agreement that enables any Person (other than Purchaser) to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (i) the sale, assignment or other transfer of any Asset or any interest therein or portion thereof or (ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Preliminary Settlement Statement” has the meaning set forth in Section 9.4(a).

“Proceeding” or “Proceedings” has the meaning set forth in Section 5.7.

“Properties” has the meaning set forth in Section 1.2(c).

“Property Costs” has the meaning set forth in Section 1.4(d).

“Purchase Price” has the meaning set forth in Section 2.1.

“Purchaser” has the meaning set forth in the preamble hereto.

“Purchaser Indemnified Persons” has the meaning set forth in Section 11.5.

“Purchaser’s knowledge” (and any similar knowledge qualification with respect to Purchaser) means matters within the Actual Knowledge of the officers and employees of Purchaser or its Affiliates identified on Schedule 5.1.

“Purchaser’s Representatives” has the meaning set forth in Section 7.1(a).

“Qualified Intermediary” has the meaning set forth in Section 7.8(c).

“RCRA” has the meaning set forth in the definition of Hazardous Materials.

“Records” has the meaning set forth in Section 1.2(i).

“REGARDLESS OF FAULT” means WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY LOSS, EVEN THOUGH A LOSS IS CAUSED IN WHOLE OR IN PART BY:

THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), STRICT LIABILITY, OR OTHER FAULT OF ANY INDEMNIFIED PERSON; BUT SPECIFICALLY EXCLUDING THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY INDEMNIFIED PERSON; AND/OR

THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), GROSS NEGLIGENCE, STRICT LIABILITY, OR OTHER FAULT OF UN-AFFILIATED THIRD PARTIES, INCLUDING WILLFUL MISCONDUCT; AND/OR

A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, IN, ON, UNDER OR WITH RESPECT TO PURCHASER’S PROPERTY OR SELLERS’ PROPERTY (INCLUDING WITHOUT LIMITATION THE ASSETS) OR THE PREMISES THERETO OR THE UNSEAWORTHINESS OF ANY VESSEL OR UNAIRWORTHINESS OF ANY AIRCRAFT OR MECHANICAL FAILURE OF ANY VEHICLE OF A PARTY WHETHER CHARTERED, LEASED, OWNED, FURNISHED OR PROVIDED BY ANY OF THE PURCHASER INDEMNIFIED PERSONS, SELLER INDEMNIFIED PERSONS, AND/OR THIRD PARTIES.

“Representation and Warranty Insurance Policy” means an insurance policy to be issued for coverage of any inaccuracy in or breach of any of Sellers’ representations and warranties contained in this Agreement.

“Representation and Warranty Insurance Policy Conditional Binder” has the meaning set forth in Section 6.7.

“Representatives” means, with respect to any Person, such Person’s directors, managers, partners, officers, employees, duly authorized agents, or professional advisors (including attorneys, accountants, consultants, bankers, financial advisors and any representatives of such advisors).

“Retained Asset” has the meaning set forth in Section 7.7(c).

“Retained Employee Liabilities” means any liabilities (i) to employees of a Seller arising under the Worker Adjustment Retraining Notification Act of 1988 or otherwise for severance, notice of termination pay or similar entitlements, in any case as a result of actions taken by such Seller at or prior to the Closing, (ii) arising out of claims by Sellers’ employees that relate to their employment with, or the termination of their employment from, the applicable Seller, (iii) with respect to employees of a Seller arising under any “employee benefit plan” (as defined in Section 3(3) of ERISA) or any other plan, program, policy, practice or arrangement providing compensation or employee benefits that is sponsored by, contributed to, required to be contributed

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to or maintained by, such Seller, or (iv) arising under ERISA for which Purchaser may have any liability under ERISA with respect to the Assets or Sellers’ employees as a result of the consummation of the transactions contemplated by this Agreement.

“Retained Liabilities” means (a) all obligations, liabilities and Losses to the extent that they are attributable to, or arise out of (i) the Retained Employee Liabilities, (ii) the actions, suits or proceedings, if any, set forth on (or required to be set forth on) Schedule 5.7(a) or **** Schedule 5.7(b), (iii) the disposal or transportation of any Hazardous Materials from the Assets attributable to the time prior to the Closing Date to any location not on the Assets, (iv) the payment of proceeds or other amounts owed to working interest, royalty, overriding royalty and other interest owners relating to the properties and assets underlying the Assets, including with respect to any amounts held in suspense (other than the Suspended Funds), and attributable to the period of time prior to the Closing Date, including any mispayments or allegations of mispayments of such proceeds or amounts attributable to the period of time prior to the Closing Date, (v) actual or claimed personal injury or death or property damage relating to the Assets or operations thereon and attributable to the period of time prior to the Closing Date, (vi) the gross negligence or willful misconduct of any Seller (or an Affiliate of any Seller) in its capacity as operator of the Assets (as distinguished from the duties of any Seller (or Affiliate thereof) as a cotenant in the properties and assets comprising the Assets), (vii) any fines or penalties imposed by any Governmental Body relating to the Assets, or the ownership or operation thereof, with respect to the period prior to the Closing, excluding any such fines or penalties imposed by any Governmental Body relating to or arising from any Environmental Liability (other than those fine or penalties relating to or arising from (x) the actions, suits or proceedings and other matters set forth on Schedule 5.7(a) or **** Schedule 5.7(b) or (y) the matters covered by subsection (iii) in this definition of “Retained Liabilities”), and/or (viii) any indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bond, letter of credit or similar financial contract of any Seller or of any its Affiliates, and (b) any Losses, liabilities or obligations of Sellers, or otherwise imposed on the Assets, in respect of any Tax, but excluding any ad valorem, property, production, severance or similar Taxes to the extent specifically allocated to Purchaser pursuant to Section 1.4 or Section 7.8, and any Transfer Taxes specifically allocated to Purchaser pursuant to Section 12.3.

“RWI Coverage Obligations” has the meaning set forth in Section 11.4.

“Scheduled Closing Date” has the meaning set forth in Section 9.1(a).

“Schedules” means the schedules attached to this Agreement.

“SEC” **** means the U.S. Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Seller” and “Sellers” has the meaning set forth in the preamble hereto.

"Seller Indemnified Persons" has the meaning set forth in Section 11.6.

“Seller Operated Assets” means Assets operated by a Seller or an Affiliate of a Seller.

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“Seller Representative” has the meaning set forth in Section 12.22.

“Sellers’ knowledge” (and any similar knowledge qualification with respect to Sellers) means matters within the Actual Knowledge of the specific officers and employees of Seller or its Affiliates identified on Schedule 5.1.

“Soft Consents” has the meaning set forth in Section 7.7(a).

“Straddle Period” means any taxable period that begins before the Effective Time and ends after the Effective Time, including any taxable period that includes, but does not end on or before, the Effective Time. For the avoidance of doubt, Taxes for any Straddle Period shall be allocated between the portion ending at the Effective Time and the portion beginning after the Effective Time in accordance with Section 1.4 and Section 7.8.

“Subject Representatives” has the meaning set forth in Section 1.5.

“Surface Contracts” has the meaning set forth in Section 1.2(e).

“Suspended Funds” means all funds which Sellers are holding as of the Closing Date which are owing to third party owners of royalty, overriding royalty, working or other interests in respect of past production of oil, gas or other hydrocarbons attributable to the properties and assets underlying Assets.

“Tax” or “Taxes” means (i) all taxes, assessments, charges, duties, fees, levies, surcharges, withholdings or other charges imposed by any Governmental Body (in each case in the nature of a tax), including all U.S. and non-U.S. federal, state, county, local, municipal and other income, franchise, profits, gross receipts, capital gains, capital stock, transfer, sales, use, value added, occupation, property, excise, severance, windfall profits, stamp, license, payroll, social security, escheat and unclaimed property, withholding and estimated taxes and other taxes, assessments, charges, duties, fees, levies, surcharges, withholdings or other charges of any kind whatsoever (in each case in the nature of a tax) (whether payable directly or by withholding or as a representative, whether or not requiring the filing of a Tax Return or whether disputed or not), and (ii) all interest, penalties, additions to tax or other additional amounts imposed by any Governmental Body in connection with any item described in clause (i).

“Tax Allocation” has the meaning set forth in Section 2.5.

“Tax Representations” means those representations and warranties contained in Section 5.8 and Section 5.20.

“Tax Returns” has the meaning set forth in Section 5.8(a).

“Termination Date” has the meaning set forth in Section 10.1(b)(i).

"Third Party Claim" has the meaning set forth in Section 11.7.

“Title Benefit” has the meaning set forth in Section 3.2.

“Title Benefit Amount” has the meaning set forth in Section 3.4(e).

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“Title Benefit Notice” has the meaning set forth in Section 3.4(b).

“Title Claim Date” has the meaning set forth in Section 3.4(a).

“Title Defect” has the meaning set forth in Section 3.2.

“Title Defect Amount” has the meaning set forth in Section 3.4(d).

“Title Defect Notice” has the meaning set forth in Section 3.4(a).

“Title Defect Property” has the meaning set forth in Section 3.4(a).

“Title Expert” has the meaning set forth in Section 3.4(k).

“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein; provided, however, that “Transfer Requirement” shall not include any consent of, notice to, filing with, or other action by, any Governmental Body in connection with the sale or conveyance of oil and/or gas leases or interests therein or Surface Contracts or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Contracts or interests or they are customarily obtained subsequent to such sale or conveyance (including consents from state agencies).

“Transfer Taxes” has the meaning set forth in Section 12.3.

“Treasury Regulations” means the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed, or final Treasury Regulations.

“Units” has the meaning set forth in Section 1.2(c).

“Unscheduled (Negative) Imbalance” shall mean, respectively as to each Property and without duplication, the sum (expressed in mcf) of (i) the aggregate make-up, prepaid or other volumes of natural gas, not described on Schedule 5.16, that Sellers were obligated as of the Effective Time, on account of prepayment, advance payment, take-or-pay, gas balancing or similar obligations, to deliver from such Property after the Effective Time without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Sellers are entitled to receive partial payment therefor) and (ii) the aggregate pipeline or processing plant Imbalances or underdeliveries, not described in Schedule 5.16, for which Sellers are obligated as of the Effective Time to pay or deliver natural gas or cash to any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any other natural gas attributable to each Property without then or thereafter being entitled to receive full payment therefor (proportionately reduced to the extent Sellers are entitled to receive partial payment therefor).

“Unscheduled (Positive) Imbalance” shall mean, respectively as to each Property and without duplication, the sum (expressed in mcf) of (i) the aggregate make-up or other volumes of

natural gas, not described on Schedule 5.16, that Sellers were entitled as of the Effective Time, on account of gas balancing or similar obligations, to receive from such Property after the Effective Time **** and (ii) the aggregate pipeline or processing plant Imbalances or overdeliveries, not described in Schedule 5.16, for which Sellers are entitled as of the Effective Time to receive natural gas or cash from any pipeline, gatherer, transporter, processor, co-owner or purchaser in connection with any other natural gas attributable to each Property.

“Wells” has the meaning set forth in Section 1.2(b).

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AGREEMENT OF SALE AND PURCHASE

This Agreement of Sale and Purchase is executed on December 1, 2025, by and among Halcón Energy Properties, Inc., a Delaware corporation (“HEPI”), Halcón Permian, LLC, a Delaware limited liability company (“Halcón Permian”), Halcon Operating Co., Inc., a Texas corporation (“HOCI”), and Halcón Field Services, LLC, a Delaware limited liability company (“HFS”) (each of HEPI, Halcón Permian, HOCI and HFS a “Seller” and collectively “Sellers”), and MCM Delaware Resources, LLC, a Texas limited liability company (“Purchaser”).

RECITALS

A. Each Seller owns certain interests in the Assets as more fully described in Section 1.2 and the exhibits hereto.

B. Sellers desire to sell to Purchaser and Purchaser desires to purchase from Sellers the properties and rights of each Seller hereafter described, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound by the terms hereof, agree as follows:

Article 1 PURCHASE AND SALE

Section 1.1Purchase and Sale.

At the Closing, and upon the terms and subject to the conditions of this Agreement, each Seller agrees to sell, assign, transfer and convey its interests in the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the interest of each Seller in the Assets and to assume the Assumed Seller Obligations.

Section 1.2Assets.

As used herein, the term “Assets” means, subject to the terms and conditions of this Agreement, all of the Sellers’ right, title, interest and estate, in and to the following (but excluding the Excluded Assets):

(a)All of the oil and/or gas leases; subleases and other leaseholds; interests in fee; carried interests; reversionary interests; net profits interests; royalty interests; overriding royalty interests; forced pooled interests; farmout rights; options; mineral interests and other properties and interests described on Exhibit A-1, subject to such depth limitations, if any, set forth on Exhibit A-1 under the column “Rights Being Reserved”, together with all rights, privileges, benefits and powers conferred upon the holder of said interests with respect to the use and occupation of the lands covered thereby (collectively, the “Leases”), together with each and every kind and character of right, title, claim, interest and estate that each Seller has in and to the lands 1

covered by the Leases and the interests currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

(b)All oil, gas, water or injection wells located on the Lands, whether producing, shut-in, or temporarily abandoned, and the interests in the wells shown on Exhibit A-2 attached hereto (collectively, the “Wells”);

(c)All interests of Sellers in or to any currently existing pools or units which include any Lands or all or a part of any Leases or include any Wells, including those pools or units related to the Properties and associated with the Wells shown on Exhibit A-2 (the “Units”; the Units, together with the Leases, Lands, and Wells, being hereinafter referred to as the “Properties”), and including all interests of Sellers in the production of Hydrocarbons from any such Units, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(d)All contracts, agreements and instruments by which the Properties or any other Assets are bound or subject, or that relate to or are otherwise applicable to the Properties or such Assets, (in each case) to the extent and only to the extent applicable to the Properties (including Hydrocarbons produced therefrom), or such Assets (and not to the extent applicable to Sellers’ or any of their Affiliates’ other properties), including operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exploration agreements, participation agreements, area of mutual interest agreements, exchange agreements, transportation or gathering agreements, saltwater disposal, treatment or transportation agreements, agreements for the sale and purchase of oil, gas or casinghead gas and processing agreements, including those identified on Schedule 1.2(d) (collectively, “Contracts”), provided that “Contracts” shall not include the instruments constituting the Leases;

(e)All easements (including subsurface easements), permits, licenses, servitudes, rights-of-way, saltwater disposal leases, surface leases, surface use agreements and other surface rights appurtenant to, and used or held for use in connection with the Properties or other Assets, whether part of the premises covered by the Leases or Units or otherwise, including those identified on Schedule 1.2(e) (collectively, “Surface Contracts”), but excluding any permits and similar rights to the extent transfer would result in a violation of applicable Law;

(f)All owned or leased personal property, equipment, fixtures, physical facilities, and surface and subsurface machinery used or held for use in connection with the operation, production, treating, storing, or transportation of Hydrocarbons from the Properties, including all such tanks, boilers, buildings, improvements, injection facilities, saltwater disposal facilities, compression facilities, treatment and processing facilities, flow lines, pipelines, gathering systems, Christmas trees, derricks, platforms, separators, compressors, gun barrels, overhead electric lines, poles, transformers, meters and similar items and including all rolling stock, pipes, casing, tubing, fittings and other spare parts, supplies, tools, warehouse stock, and material held as operating inventory, including those identified on Schedule 1.2(f) (collectively, “Equipment”);

(g)to the extent transferable, all Governmental Authorizations that have been granted or issued as of the Closing Date in connection with ownership or operation of the Properties;

(h)All Hydrocarbons in, on, or under, or that may be produced from or attributable to the Leases, Lands, or Wells from and after the Effective Time, including any such Hydrocarbons in inventory, storage, tanks, or lines, together with and subject to Imbalances associated with the Properties;

(i)Except to the extent constituting data covered by Section 1.2(j), all lease files, land files, well files, gas and oil sales contract files, gas processing and transportation files, division order files, abstracts, title opinions, land surveys, logs, maps, engineering data and reports, interpretive data, technical evaluations and technical outputs, and other books, records, data, files, and accounting and Tax records, including, but not limited to, records showing all funds payable to owners of working interests, royalties and overriding royalties and other interests in the Properties held in suspense by a Seller as of the Closing Date, in each case to the extent related to the Properties, or used or held for use in connection with the maintenance or operation thereof and in Sellers’ possession (the “Records”);

(j)To the extent transferable, and subject to Purchaser’s agreement to pay and the payment by Purchaser of all third party transfer and license fees, all geological and geophysical data (including all seismic data, as well as reprocessed data) related exclusively to the Properties, including those items identified in Schedule 1.2(j);

(k)All vehicles identified on Schedule 1.2(k);

(l)All Suspended Funds held by any Seller as of the Closing Date;

(m)all liens and security interests securing payment for the sale or other disposition of Hydrocarbons produced from or allocated to the Properties, including the security interests granted under applicable Uniform Commercial Code provisions, but only to the extent that such liens and security interests relate to the period from and after the Effective Time;

(n)to the extent transferable, all rights, claims and causes of action to the extent, and only to the extent, that such rights, claims or causes of action are associated with the Properties or other Assets as of the Closing Date and (i) relate to the period from and after the Effective Time or (ii) relate to both the period prior to the Effective Time and the Assumed Seller Obligations for which Purchaser is responsible, provided that, at Purchaser’s request, Sellers shall use their reasonable efforts to enforce, for the benefit of Purchaser, at Purchaser’s cost and expense, any right, claim or cause of action that would otherwise be transferred hereunder but is not transferable; and

(o)that certain tract of fee estate real property described on Exhibit A-3 (the “Fee Lands”).

Section 1.3Excluded Assets.

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the transaction contemplated hereby (collectively, the “Excluded Assets”):

(a)except to the extent necessary to satisfy Sellers’ obligations under Section 7.1, (i) all corporate, financial, income and franchise tax and legal records of each Seller that relate to

such Seller’s business generally (whether or not relating to the Assets), (ii) all books, records and files that relate to the Excluded Assets (but only to the extent related to the Excluded Assets), (iii) all geological and geophysical data not transferred by a Seller pursuant to Section 1.2(j), (iv) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the extent disclosure or transfer would result in a violation of applicable Law, (v) computer or communications software or intellectual property (including tapes, codes, data and program documentation and all tangible manifestations and technical information relating thereto), (vi) attorney-client privileged communications and work product of each Seller’s or any of such Seller’s Affiliates’ legal counsel (other than title opinions), (vii) reserve studies and evaluations, (viii) records relating to the marketing, negotiation, and consummation of the sale of the Assets and (ix) copies of any other Records retained by a Seller pursuant to Section 1.5;

(b)except to the extent related to any Assumed Seller Obligation, all rights to any refund attributable to periods prior to the Effective Time related to the Excluded Seller Obligations or Taxes or other costs or expenses borne by Sellers or Sellers’ predecessors in interest;

(c)a Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of such Seller’s business generally;

(d)those items listed in Schedule 1.3(d);

(e)except to the extent related to any Assumed Seller Obligation, all trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable, pre-paid expenses and deposits, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time;

(f)all exchange traded futures contracts and over-the-counter derivative or hedge contracts of a Seller;

(g)all right, title and interest of Sellers in and to vehicles used in connection with the Assets, other than those identified on Schedule 1.2(k);

(h)all rights, titles, claims and interests of a Seller or any Affiliate of a Seller (i) to or under any policy or agreement of insurance or any insurance proceeds, except to the extent provided in Section 3.5, and (ii) to or under any bond or bond proceeds;

(i)subject to Section 12.5, any patent, patent application, logo, service mark, copyright, trade name or trademark of or associated with a Seller or any Affiliate of a Seller or any business of a Seller or of any Affiliate of a Seller; and

(j)all Retained Assets not conveyed to Purchaser pursuant to Section 7.7 and any Asset excluded pursuant to Section 3.4, Section 4.3(b) or Section 4.3(d).

Section 1.4Effective Time; Proration of Costs and Revenues.

(a)Subject to Section 1.5, possession of the Assets shall be transferred from Sellers to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be

transferred and assumed effective as of 7:00 A.M., local time, where the respective Assets are located, on December 1, 2025 (the “Effective Time”), as described below.

(b)Purchaser shall be entitled to all Hydrocarbon production from or attributable to the Properties at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at or after the Effective Time, and Purchaser shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred at and after the Effective Time. Sellers shall be entitled to all Hydrocarbon production from or attributable to the Properties prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time, and Sellers shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred prior to the Effective Time.

(c)As used in this Agreement, the terms “earned” and “incurred” shall be interpreted in accordance with GAAP and Council of Petroleum Accountants Society (“COPAS”) standards, as applicable.

(d)As used in this Agreement, the term “Property Costs” means all costs attributable to the ownership and operation of the Assets incurred in the ordinary course of business (including without limitation costs of insurance relating specifically to the Assets and ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, but excluding any other Taxes) and capital expenditures incurred in the ordinary course of business attributable to ownership and operation of the Assets (excluding lease bonuses, broker fees, other lease acquisition costs) and, where applicable, in accordance with the relevant operating or unit agreement, if any, overhead costs charged by an un-Affiliated third party to the Assets under the relevant operating or unit agreement, if any, and, to the extent a Seller or an Affiliate of a Seller operates a particular Asset, the amount set forth on Schedule 1.4 for such Asset; provided, however, that Property Costs shall exclude Losses attributable to (a) personal injury or death, property damage, or violation of any Law, (b) Assumed Seller Obligations related to Hazardous Materials and Environmental Liabilities, (c) plugging and abandonment obligations, (d) obligations with respect to Imbalances, and (e) Suspended Funds.

(e)For purposes of this Section 1.4, determination of whether Property Costs are attributable to the period before or after the Effective Time shall be based on when services are rendered, when the goods are delivered, or when the work is performed. For clarification, the date an item or work is ordered is not the date of a pre-Effective Time transaction for settlement purposes, but rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, shall be the relevant date. For purposes of allocating Hydrocarbon production (and accounts receivable with respect thereto), under this Section 1.4, (x) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Properties when such Hydrocarbons are placed into the storage facilities and (y) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Properties when such Hydrocarbons pass through the delivery point sales meters on the pipelines through which they are transported.

(f)Sellers shall utilize reasonable interpolative procedures to arrive at an allocation of Hydrocarbon production when exact meter readings or gauging and strapping data is not available.

Sellers shall provide to Purchaser, no later than five (5) Business Days prior to Closing, all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the Purchase Price pursuant to Section 2.2 hereof that will be used to determine the Closing Payment. Property Costs (including for the avoidance of doubt, ad valorem Taxes that are not determined based upon units of Hydrocarbon produced and property taxes) that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at or after the Effective Time, except that Hydrocarbon production, severance and similar Taxes (including ad valorem Taxes that are determined based upon units of Hydrocarbon produced) shall be prorated based on the number of units actually produced, purchased or sold or proceeds of sale, as applicable, before, and at or after, the Effective Time. In each case, Purchaser shall be responsible for the portion allocated to the period at and after the Effective Time and Sellers shall be responsible for the portion allocated to the period before the Effective Time.

Section 1.5Delivery and Maintenance of Records.

Sellers shall deliver the Records (FOB at Sellers’ office) to Purchaser within five (5) Business Days following Closing. Purchaser shall be entitled to all original Records maintained by Sellers. Sellers shall be entitled to keep copies of all Records; provided, however, that from and after the Closing and except in connection with its obligations under this Agreement, each Seller shall not, and shall cause its respective Affiliates and its and their respective officers, directors, employees, agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (with respect to each Seller, the “Subject Representatives”) not to, disclose, permit to be disclosed, use, permit to be used, copy or permit to be copied, the Records or any trade secrets or proprietary or confidential information to the extent relating to the Assets, except for (i) disclosures and uses required by applicable Law or stock exchange rules or of information that has become part of the public domain through no action of any Seller or any Subject Representative after the Closing, and (ii) disclosures to financial institutions or other third party in connection with the evaluation of financing or a sales or acquisition transaction provided that such financial institution or other third party is bound by a reasonable obligation of confidentiality covering such information. Purchaser shall preserve the Records in Purchaser’s offices in accordance with Purchaser’s record retention policy following the Closing and, subject to the foregoing confidentiality obligations, will allow each Seller and their respective representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records in order for a Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute with an un-Affiliated third party for which such Seller is responsible. Any such access shall be at the sole cost and expense of such Seller.

Article 2 PURCHASE PRICE

Section 2.1Purchase Price.

The purchase price for the Assets (the “Purchase Price”) shall be $62,589,000, adjusted as provided in Section 2.2.

Section 2.2Adjustments to Purchase Price.

The Purchase Price for the Assets shall be adjusted in the manner specified below (without duplication), with all such amounts being determined in accordance with GAAP and COPAS standards, as applicable, in order to reach the “Adjusted Purchase Price”:

(a)Reduced by the aggregate amount of the following proceeds actually received by Sellers between (and including) the Effective Time and the Closing Date (with the period between and including the Effective Time up to the Closing Date referred to as the “Adjustment Period”): (i) all proceeds from the sale of Hydrocarbons and all products attributable thereto (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Sellers by the purchaser of production) produced from or attributable to the Properties for the period after the Effective Time, and (ii) all other income, proceeds, receipts and credits earned with respect to the Assets for the period after the Effective Time;

(b)Reduced by the amount of all Property Costs and other costs attributable to the ownership and operation of the Assets for the period prior to the Effective Time which are paid by Purchaser, except any costs incurred as a result of any breach by Purchaser of this Agreement;

(c)Increased by the aggregate amount of the following proceeds actually received by Purchaser during the Adjustment Period: (i) all proceeds from the sale of Hydrocarbons and all products attributable thereto (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Purchaser by the purchaser of production) produced from or attributable to the Properties for the period before the Effective Time, and (ii) all other income, proceeds, receipts and credits earned with respect to the Assets for the period before the Effective Time;

(d)Increased by the amount of all Property Costs and other costs attributable to the ownership and operation of the Assets for the period after the Effective Time which are paid by Sellers (including any overhead costs listed on Schedule 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except (i) any Property Costs and other such costs already deducted in the determination of proceeds in Section 2.2(a), (ii) any costs incurred by Sellers in connection with curing any Title Defect or Environmental Defect or with respect to any casualty loss and (iii) any costs incurred as a result of any breach by any Sellers of this Agreement;

(e)Reduced to the extent provided in Section 7.7 with respect to Preference Rights and Retained Assets;

(f)(i) subject to the Individual Title Threshold and the Aggregate Defect Deductible, reduced by the Title Defect Amount with respect to each Title Defect for which the Title Defect Amount has been determined prior to Closing and (ii) subject to the Individual Title Benefit Threshold and Aggregate Benefit Deductible, increased by the Title Benefit Amount with respect to each Title Benefit for which the Title Benefit Amount has been determined prior to Closing;

(g)Reduced to the extent provided in Section 4.3 for Environmental Defects or Assets retained by Sellers pursuant to Section 4.3;

(h)Reduced to the extent provided in Section 3.5 in connection with a casualty loss or governmental taking;

(i)Increased or reduced as mutually agreed upon in writing prior to Closing by Sellers and Purchaser;

(j)To the extent the proceeds from the sale thereof have not been received by Sellers, increased by the value of the amount of any and all Hydrocarbons stored in tanks above the load level and in pipelines above the sales meter attributable to the ownership and operation of the Assets that belong to Sellers as of the Effective Time (which value shall be computed by Sellers at the applicable third-party contract prices for the month of November 2025 for such stored Hydrocarbons);

(k)(i) Reduced by the product obtained by multiplying the aggregate amount of Unscheduled (Negative) Imbalances by $1.00 **** per mcf; and (ii) increased by the product obtained by multiplying the aggregate amount of Unscheduled (Positive) Imbalances by $1.00 **** per mcf;

(l)Reduced by the Deposit (as described in Section 2.4 below);

(m)Reduced by an amount equal to all Suspended Funds; and

(n)Each adjustment made pursuant to Section 2.2(a) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable to the Properties during the Adjustment Period, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and as such, Purchaser shall not have any separate rights to receive any Hydrocarbon production or income, proceeds, receipts and credits with respect to which an adjustment has been made. Similarly, the adjustment described in Section 2.2(d) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s obligation under Section 1.4 to pay Property Costs and other costs attributable to the ownership and operation of the Assets which are incurred during the Adjustment Period.

Section 2.3Allocation of Purchase Price.

The Allocated Values are contained in Exhibit A-1 **** and **** Exhibit A-2. Purchaser shall be responsible for assigning the Allocated Values included on Exhibit A-1 **** and **** Exhibit A-2, subject to each Seller’s right to review the Allocated Values for reasonableness.

Section 2.4Deposit.

A deposit in the amount of $6,258,900 (together with all interest earned thereon, the “Deposit”) shall be paid to the Escrow Agent by wire transfer in immediately available funds on or before two (2) Business Days after execution of this Agreement by Purchaser, to be held in accordance with the Escrow Agreement and this Agreement. The Deposit shall be credited to the Purchase Price to be paid by Purchaser at the Closing. Except as provided in the following sentence, in the event the transaction contemplated hereby is not consummated in accordance with the terms hereof, Seller Representative and Purchaser shall instruct the Escrow Agent to release the Deposit to Sellers as liquidated damages and Sellers’ sole and exclusive remedy for the failure

of the transaction to be consummated in accordance with the terms hereof. If the transaction contemplated hereby is not consummated due to (i) material breach of Sellers’ obligations hereunder, (ii) the failure of the conditions precedent to the obligations of Purchaser in Section 8.2 to be satisfied or waived in writing by Purchaser (and not caused by Purchaser’s actions or inactions), (iii) Sellers’ termination of this Agreement pursuant to Section 10.1(e), (iv) termination of the Agreement pursuant to Section 10.1(a), (v) Purchaser’s termination of this Agreement in accordance with Section 10.1(b), Section 10.1(d) or Section 10.1(f), **** or (vi) termination of the Agreement by Purchaser in accordance with Section 10.2(b), then Seller Representative and Purchaser shall instruct the Escrow Agent to release the Deposit to Purchaser. Notwithstanding anything in this Agreement to the contrary, if Purchaser fails to deliver the Deposit to the Escrow Agent within two (2) Business Days following the execution of this Agreement, Sellers shall be entitled to immediately terminate this Agreement and pursue one or more of any and all remedies as may be available to Sellers at law or in equity, including specific performance.

Section 2.5Tax Allocation.

The Allocated Value shall apply to Sellers and Purchaser for purposes of Section 1060 of the Code and the Treasury Regulations promulgated thereunder (and any similar provision of state, local or foreign law, as appropriate) and shall be determined in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder (the “Tax Allocation”). If the Purchase Price or Adjusted Purchase Price is adjusted (or further adjusted) pursuant to this Agreement, the Tax Allocation shall be adjusted (or further adjusted) in a manner consistent with the procedures set forth in this Section 2.5 by Purchaser. Purchaser and Sellers shall file all Tax Returns (including, but not limited to, Internal Revenue Service Form 8594) consistent with the Tax Allocation. Neither Purchaser nor Sellers shall take any Tax position inconsistent with such Tax Allocation and neither Purchaser nor Sellers shall agree to any proposed adjustment to the Tax Allocation by any Governmental Body without first giving the other party prior written notice; provided, however, that nothing contained herein shall prevent Purchaser or Sellers from settling any proposed deficiency or adjustment by any Governmental Body based upon or arising out of the Tax Allocation, and neither Purchaser nor Sellers shall be required to litigate before any court any proposed deficiency or adjustment by any Governmental Body challenging such Tax Allocation. Sellers and Purchaser shall promptly inform the other of any challenge by any Governmental Body to the Tax Allocation and agree to consult and keep the other informed with respect to the status of, and any discussion, proposal or submission with respect to, such challenge.

Article 3 TITLE MATTERS

Section 3.1Sellers’ Title.

(a)Except for the special warranty of title contained in the assignment and conveyance documents substantially in the form attached hereto as Exhibit B **** (the “Conveyance”) **** and **** Exhibit C (the “Deed”) to be delivered by Sellers to Purchaser at Closing, SELLERS MAKE NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, WITH RESPECT TO SELLERS’ TITLE TO ANY OF THE ASSETS AND PURCHASER HEREBY ACKNOWLEDGES AND AGREES THAT PURCHASER’S SOLE REMEDY FOR ANY DEFECT OF TITLE, INCLUDING ANY TITLE DEFECT,

WITH RESPECT TO ANY OF THE ASSETS SHALL BE PURSUANT TO THE PROCEDURES SET FORTH IN THIS ARTICLE 3 AND UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND THE DEED.

(b)If the Closing occurs, then effective as of the Closing Date, each Seller, jointly and severally, warrants Defensible Title to the Properties and the Fee Lands unto Purchaser against every Person whomsoever lawfully claiming by, through and under such Seller, but not otherwise, subject, however, to the Permitted Encumbrances.

Section 3.2Definitions of Title Matters*.*

As used in this Agreement, the term “Defensible Title” means that title of Sellers with respect to the Leases, Wells or other Assets, except for and subject to Permitted Encumbrances that as of the Effective Time and the Closing:

(a)Entitles Sellers to receive an interest (expressed as a percentage or decimal fraction) of the Hydrocarbons produced, saved and marketed from any Lease, Well or other Asset shown in Exhibit A-1 **** or **** Exhibit A-2, **** including the formation(s) set forth on Exhibit A-1 **** or **** Exhibit A-2 for such Lease, Well or other Asset (after satisfaction of all royalties, overriding royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “Net Revenue Interest”), throughout the period when such Lease, Well or other Asset is producing (including the formation(s) set forth on Exhibit A-1 **** or **** Exhibit A-2 for such Lease, Well or other Asset), of not less than the Net Revenue Interest shown in Exhibit A-1 **** or **** Exhibit A-2 **** for such Lease, Well or other Asset, except (solely to the extent that such actions do not cause a breach of Sellers’ covenants under Section 7.6(a)) for decreases in connection with those operations in which Sellers may from and after the date hereof become non-consenting co-owners, decreases resulting from the establishment or amendment from and after the date hereof of pools or units, and decreases required to allow other working interest owners to make up past underproduction of Hydrocarbons or pipelines to make up past underdeliveries of Hydrocarbons, and except as stated in Exhibit A-1 **** or **** Exhibit A-2;

(b)Obligates Sellers to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, any Lease, Well or other Asset shown in Exhibit A-1 **** or **** Exhibit A-2 **** (including the formation(s) set forth on Exhibit A-1 **** or **** Exhibit A-2 for such Lease, Well or other Asset) not greater than the “working interest” percentage shown in Exhibit A-1 **** or **** Exhibit A-2 **** for such Lease, Well or other Asset, without increase throughout the period when such Lease, Well or other Asset is producing (including the formation(s) set forth on Exhibit A-1 **** or **** Exhibit A-2 for such Lease, Well or other Asset), except as stated in Exhibit A-1 **** or **** Exhibit A-2 and except for increases from and after the date hereof resulting from contribution requirements with respect to non-consenting or defaulting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in such Seller’s Net Revenue Interest;

(c)Entitles Sellers to Net Mineral Acres of not less than the Net Mineral Acres shown in Exhibit A-1 for such Lease;

(d)Is free and clear of liens, encumbrances, obligations, security interests, irregularities, pledges, or other defects; and

(e)Entitles Sellers to such rights that a reasonably prudent operator would believe are necessary for ownership, operation or economic benefit of such Leases, Wells or other Assets shown on Exhibit A-1 **** or **** Exhibit A-2 and are free and clear of any term, burden, restriction, requirement or imperfection that would result in a Material Adverse Effect.

As used in this Agreement, the term “Title Defect” means any of the following: any lien, charge, encumbrance, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or working interest) that causes the applicable Seller not to have Defensible Title. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i)defects based solely on (1) lack of information in such Seller’s files, or (2) references to a document(s) if such document(s) is not in such Seller’s files, (in each case) unless information in the records of the applicable county reflect that any information in Seller’s files is incorrect;

(ii)defects arising out of lack of corporate or similar entity authorization unless Purchaser provides affirmative written evidence that causes Purchaser to reasonably believe that the action was not authorized and results in another Person’s superior claim of title;

(iii)defects based on failure to record any Lease issued by any state or federal Governmental Body, or any assignments of such Lease, (in each case) in the real property, conveyance or other records of the county in which such Lease is located;

(iv)defects based on a gap in a Seller’s chain of title in the county records as to a Lease or Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice;

(v)defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(vi)defects in the chain of title consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Purchaser provides affirmative evidence that causes Purchaser to reasonably believe that such failure or omission has resulted in another Person’s superior claim of title; and

(vii)defects that have been cured by applicable Laws of limitation or prescription.

As used in this Agreement, the term “Title Benefit” shall mean any right, circumstance or condition that operates to increase the Net Mineral Acres or Net Revenue Interest of Sellers in any Lease, Well or other Asset shown on Exhibit A-1 **** or **** Exhibit A-2, without causing a greater than proportionate increase in Sellers’ working interest above that shown in Exhibit A-1 **** or **** Exhibit A-2 **** as of the Effective Time.

Section 3.3Definition of Permitted Encumbrances.

As used herein, the term “Permitted Encumbrances” means any or all of the following:

(a)Royalties and any overriding royalties, reversionary interests, net profit interests, production payments, carried interests, and other burdens on production, to the extent that any such burden does not reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 **** or **** Exhibit A-2 **** or increase Sellers’ working interest above that shown in Exhibit A-1 **** or **** Exhibit A-2 **** without a proportionate increase in the corresponding Net Revenue Interest;

(b)All Leases, unit agreements, pooling agreements, operating agreements, Hydrocarbon production sales contracts, division orders and other contracts, agreements and instruments applicable to or affecting the Assets, to the extent that they do not, individually or in the aggregate, (i) reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 **** or **** Exhibit A-2 or increase Sellers’ working interest above that shown in Exhibit A-1 **** or **** Exhibit A-2 **** without a proportionate increase in the corresponding Net Revenue Interest, (ii) reduce the Net Mineral Acres for any Lease below the Net Mineral Acres set forth on Exhibit A-1 for such Lease or (iii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(c)Preference Rights applicable to this or any future transaction;

(d)Transfer Requirements applicable to this or any future transaction;

(e)Liens for current Taxes not yet due and payable;

(f)Any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing oil, gas or other hydrocarbons therefrom or therein and (ii) materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business to construction, maintenance, development, production or operation of the Assets or the production or processing of oil, gas or other hydrocarbons therefrom, (in each case) that are not delinquent (including any amounts being withheld as provided by Law) and that will be paid in the ordinary course of business;

(g)All rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or interests therein pursuant to this or to any future transaction if they are not required and are not customarily obtained prior to such a sale or conveyance;

(h)Excepting circumstances where such rights have already been triggered, rights of notice or reassignment (or granting an opportunity to receive a reassignment) of a leasehold interest to the holders of such reassignment rights prior to surrendering or releasing such leasehold interest;

(i)Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, to the extent that they do not (i) reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 **** or **** Exhibit A-2 **** or increase Sellers’ working interest above that shown in Exhibit A-1 **** or **** Exhibit A-2 **** without a proportionate increase in the corresponding Net Revenue Interest or (ii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be considered acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(j)Calls on Hydrocarbon production under existing Contracts that are listed on Schedule 1.2(d);

(k)All rights reserved to or vested in any Governmental Body to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable Laws or under any franchise, grant, license or permit issued by any such Governmental Body;

(l)Any depth limitation expressly shown on Exhibit A-1 **** under the headings “Rights Being Reserved” or “Assigned Depths” to the extent that such depth limitation does not reduce Sellers’ Net Revenue Interest below that shown in Exhibit A-1 **** or **** Exhibit A-2 or increase Sellers’ working interest above that shown in Exhibit A-1 **** or **** Exhibit A-2 **** without a proportionate increase in the corresponding Net Revenue Interest;

(m)Imbalances associated with the Assets; and

(n)Liens granted under applicable joint operating agreements and other similar agreements for amounts that are not delinquent.

Section 3.4Notice of Title Defect Adjustments.

(a)To assert a claim of a Title Defect prior to Closing, Purchaser must deliver claim notices to Sellers (each a “Title Defect Notice”) on or before February 16, 2026 **** at 5:00 p.m. C.D.T. (the “Title Claim Date”); provided, however, that Purchaser agrees that, starting on the 30th day after execution of this Agreement, it shall furnish Sellers once at the end of every two (2) week period until the Title Claim Date with a preliminary Title Defect Notice if any officer of Purchaser or its Affiliates discovers or learns of any Title Defect during such two (2) week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Title Claim Date; provided further that failure to provide preliminary notice of a Title Defect shall not prejudice Purchaser’s right to assert any Title Defect hereunder on or before the Title Claim Date. To be effective, each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s), (ii) Leases, Units, Wells or other Assets in Exhibit A-1 **** or **** Exhibit A-2, as applicable, affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of and extent of the alleged Title Defect(s) and the amount by which the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s), and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. EXCEPT FOR

PURCHASER’S RIGHTS UNDER THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND DEED, AND PURCHASER’S RIGHTS FOR ANY BREACH BY SELLERS OF THEIR REPRESENTATIONS, WARRANTIES OR COVENANTS HEREUNDER , Purchaser shall be deemed to have waived its right to assert Title Defects of which SellerS haVE not been given A TITLE DEFECT notice PURSUANT TO THIS SECTION 3.4( a ) on or before the Title Claim Date . For purposes hereof, the “Allocated Value” of an Asset shall mean the portion of the Purchase Price that has been allocated to a particular Lease, Unit, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2 as prepared by Purchaser and reviewed for reasonableness by Sellers.

(b)Sellers shall have the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date, with respect to each Title Benefit, a notice (a “Title Benefit Notice”), which notice to be effective shall include (i) a description of the alleged Title Benefit, (ii) the Leases, Wells or other Assets in Exhibit A-1 **** or **** Exhibit A-2 **** affected by such Title Benefit, (iii) the Allocated Value of each Lease, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2 **** subject to such Title Benefit, (iv) supporting documents reasonably necessary for Purchaser (as well as any title attorney or examiner hired by Purchaser) to verify the existence of and extent of such Title Benefit and the amount by which the Allocated Value of each affected Asset is increased by such Title Benefit, and (v) the amount by which Sellers reasonably believe the Allocated Value of each affected Asset is increased by such Title Benefit and the computations and information upon which Sellers’ belief is based.

(c)Sellers shall have the right, but not the obligation, to attempt, at their sole cost, to cure or remove Title Defects which Sellers have been advised in writing by Purchaser at any time prior to Closing (the “Cure Period”), unless the parties otherwise agree. Any asserted Title Defects which are cured within the Cure Period or waived in writing by Purchaser shall be deemed Permitted Encumbrances hereunder.

(d)Subject to the Individual Title Threshold and the Aggregate Defect Deductible, the Purchase Price shall be reduced by an amount agreed upon (“Title Defect Amount”) pursuant to Section 3.4(g) by Purchaser and Sellers as being the value of such Title Defect, taking into consideration the Allocated Value of the Property affected by such Title Defect, the portion of the Property affected by such Title Defect and the legal effect of such Title Defect on the Property affected thereby; provided, however, that the methodology, terms and conditions of Section 3.4(g) shall control any such determination. In the event that any Title Defect is not waived by Purchaser in writing or cured on or before Closing, and Sellers and Purchaser are unable to agree on the Title Defect Amount by the Scheduled Closing Date, then unless the Parties otherwise mutually agree in writing the dispute shall be resolved pursuant to the provisions of Section 3.4(k).

(e)Subject to the Individual Title Benefit Threshold and the Aggregate Benefit Deductible, with respect to each Lease, Unit, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2, as applicable, **** affected by Title Benefits reported under Section 3.4(b), the Purchase Price shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Lease, Unit, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2, as applicable, **** caused by such Title Benefits, as determined pursuant to Section 3.4(j). In the event that Purchaser and Sellers are unable to agree on the Title Benefit Amount, the affected Assets will nevertheless

be conveyed to Purchaser at Closing with no increase to the Purchase Price for such Title Benefit, subject to Sellers’ right to a subsequent adjustment in the Purchase Price for such Title Benefit as may result under the provisions of Section 3.4(k), or as may otherwise be agreed to by the parties. Notwithstanding anything else herein to the contrary, Title Benefits shall exclusively be offset against the Title Defect Amount such that, to the extent that the Title Benefit Amount exceeds the Title Defect Amount, there shall be no increase to the Purchase Price by virtue of the Title Benefits.

(f)Section 3.4(d) shall be the exclusive right and remedy of Purchaser with respect to Title Defects asserted by Purchaser pursuant to Section 3.4(a). Section 3.4(e) shall be the exclusive right and remedy of Sellers with respect to Title Benefits asserted by Sellers pursuant to Section 3.4(b). ****

(g)The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i)if Purchaser and Sellers agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii)if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect affecting the Title Defect Property;

(iii)if the Title Defect results from a Seller having a lesser Net Revenue Interest in such Title Defect Property than the Net Revenue Interest specified therefor in Exhibit A-1 **** or **** Exhibit A-2 **** and there is a proportional decrease in the working interest for the affected Title Defect Property, the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Title Defect Property on Exhibit A-1 **** or **** Exhibit A-2 **** by a fraction, the numerator of which is the reduction in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Title Defect Property in Exhibit A-1 **** or **** Exhibit A-2;

(iv)if the Title Defect results from a Seller owning fewer Net Mineral Acres in a Title Defect Property than represented on Exhibit A-1, the Title Defect Amount shall be equal to the portion of the Purchase Price allocated to such Title Defect Property on Exhibit A-1 multiplied by a fraction, (A) the numerator of which is the difference between the represented aggregate number of Net Mineral Acres shown on Exhibit A-1 covered by such Title Defect Property, and the actual aggregate number of Net Mineral Acres covered by such Title Defect Property, and (B) the denominator of which shall be the represented aggregate number of Net Mineral Acres shown on Exhibit A-1 for such Title Defect Property.

(v)if the Title Defect results from any matter not described in subsections (i), (ii) or (iii) above, the Title Defect Amount shall be an amount equal to the difference between the value of the Title Defect Property affected by such Title Defect with such Title Defect and the value of such Title Defect Property without such Title Defect (taking into

account the portion of the Purchase Price allocated in Exhibit A-1 and **** Exhibit A-2 to such Title Defect Property and the cost to cure such Title Defect if such Title Defect is reasonably susceptible of being cured);

(vi)if a Title Defect is not effective or does not affect a Title Defect Property throughout the entire remaining productive life of such Title Defect Property, such fact shall be taken into account in determining the Title Defect Amount; and

(vii)notwithstanding anything to the contrary in this Article 3, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(h)The Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder. For example, if a lien affects more than one Title Defect Property or the curative work with respect to one Title Defect results (or is reasonably expected to result) in the curing of any other Title Defect affecting the same or another Title Defect Property, the amount necessary to discharge such lien or the cost and expense of such curative work shall be allocated among the Title Defect Properties so affected (in the ratios of the respective portions of the Purchase Price allocated to such Title Defect Properties) and the amount so allocated to a Title Defect Property shall be included only once in the Title Defect Amount.

(i)No Title Defect Amount shall be allowed on account of and to the extent that an increase in a Seller’s working interest in a Property has the effect of proportionately increasing such Seller’s Net Revenue Interest in such Property;

(j)The Title Benefit Amount for any Title Benefit shall mean, with respect to an affected Lease, Well or other Asset, the amount by which the value of the affected Lease, Well or other Asset is enhanced by virtue of such Title Benefit, which amount shall be determined as follows:

(i)If Purchaser and Sellers agree on the Title Benefit Amount, that agreed amount shall be the Title Benefit Amount.

(ii)If the Title Benefit results from a Seller having a greater Net Revenue Interest in such Lease, Well or other Asset than the Net Revenue Interest specified therefor in Exhibit A-1 **** or **** Exhibit A-2with a proportional increase in the working interest of the affected Lease, Well or other Asset, the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Lease, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2 by a fraction, the numerator of which is the increase in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Lease, Well or other Asset in Exhibit A-1 **** or **** Exhibit A-2.

(iii) if the Title Benefit results from a Seller owning greater Net Mineral Acres in such Lease, Well or other Asset than represented on Exhibit A-1, the Title Benefit Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such affected **** Lease, Well or other Asset **** in **** Exhibit A-1 by a fraction, the numerator of which is the increase in the Net Mineral Acres and the denominator of which

is the Net Mineral Acres specified for such Lease, Well or other Asset in Exhibit A-1.

(iv)If the Title Benefit results from any matter not described in subsections (i), (ii) or (iii) above, the Title Benefit Amount shall be an amount equal to the difference between the value of the Property affected by such Title Benefit and the value of such Property without such Title Benefit (taking into account the portion of the Purchase Price allocated in Exhibit A-1 **** or **** Exhibit A-2 to such Property).

(v)In determining the amount of Title Benefit Amounts, the principles and methodology set forth in Section 3.4(g) shall generally be applied, mutatis mutandis.

(k)Sellers and Purchaser shall attempt in good faith to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to the Scheduled Closing Date. If Seller and Purchaser are unable to agree by the Scheduled Closing Date, the Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k); in addition, should the parties dispute whether or not any Title Defect has been cured by Sellers, such dispute shall be exclusively and finally resolved pursuant to this Section 3.4(k), in each case as follows:

(i)There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years’ experience in oil and gas titles involving properties in the regional area in which the relevant Properties are located and who shall not have performed professional services for either party or any of their respective Affiliates during the previous three (3) years, as selected by mutual agreement of Purchaser and Sellers within fifteen (15) Business Days after the Scheduled Closing Date (and absent such agreement, by the Houston office of the American Arbitration Association) (the “Title Expert”). Within ten (10) Business Days following the selection of the Title Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Title Expert written explanations of their respective positions in the disputed title matters. The Title Expert’s determination shall be made within fifteen (15) Business Days after submission of the title matters in dispute and shall be final and binding upon all parties, without right of appeal. In making his determination, the Title Expert shall be bound by the provisions of this Article 3, and may consider such other matters as in the opinion of the Title Expert are necessary or helpful to make a proper determination. The Title Expert may allow the parties to make written submissions of their positions in the manner and to the extent the Title Expert deems appropriate, and the Title Expert may call on the parties to submit such other materials as the Title Expert deems helpful and appropriate to resolution of the dispute. Additionally, the Title Expert may consult with and engage disinterested third parties to advise the Title Expert, including without limitation petroleum engineers. The Title Expert shall act as an expert for the limited purpose of determining the specific disputed title matters submitted by either party and may not award damages, interest or penalties to any party with respect to any matter. Sellers and Purchaser shall each bear their own legal fees and other costs of presenting its case. The costs and expenses of the Title Expert shall be borne and paid one-half by Sellers and one-half by Purchaser, including any costs incurred by the Title Expert that are attributable to such third party consultation.

(ii)Any Title Defect Amounts alleged by Purchaser that are applicable to the disputed title matters that are not resolved prior to the Scheduled Closing Date will nevertheless be conveyed to Purchaser at Closing with no reduction in the Purchase Price for any such Title Defect and a portion of the Purchase Price equal to the disputed Title Defect Amount alleged by Purchaser shall be placed in escrow by Purchaser pursuant to an escrow agreement substantially in the same form as the Escrow Agreement among Purchaser, Seller Representative and Escrow Agent. Sellers shall have one hundred twenty (120) days after Closing in which to cure the Title Defect with respect to such retained Property and related Assets. If the Title Defect(s) related to such Title Defect Properties is timely cured to the reasonable satisfaction of Purchaser, then ten (10) Business Days following the date that the Title Defect is cured Purchaser and Sellers shall instruct the Escrow Agent to pay to Sellers the full Title Defect Amount for such Assets held in escrow. In the event that Sellers are unable to cure the Title Defect with respect to any Property and related Assets within one hundred twenty (120) days after Closing to the reasonable satisfaction of Purchaser, then Purchaser shall retain the Property and related Assets affected thereby and, subject to Section 3.4(k)(iii), Purchaser and Sellers shall instruct the Escrow Agent to pay to Purchaser the full Title Defect Amount for such Assets held in escrow. The Purchase Price shall be subject to a further subsequent adjustment for any such Title Defect upon the resolution of such disputed title matters pursuant to Section 3.4(k)(i) or as may be otherwise be mutually agreed by the parties. Upon such resolution of such disputed title matters pursuant to Section 3.4(k)(i), then (A) Purchaser and Seller Representative shall instruct Escrow Agent to deliver to Sellers the amount, if any, so awarded by the Title Expert to Sellers, plus interest accrued on such amount pursuant to the terms of the Escrow Agreement, if any, and (B) Purchaser and Seller Representative shall instruct Escrow Agent to pay to Purchaser the amount, if any, so awarded by the Title Expert to Purchaser, plus interest accrued on such amount pursuant to the terms of the Escrow Agreement, if any.

(iii)If any title disputed matter under this Article 3 relates to whether or not any Title Defect has been cured post-Closing pursuant to Section 3.4(k)(ii), then such title disputed matter shall be resolved pursuant to the determination of the Title Expert pursuant to Section 3.4(k)(i).

(l)Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for any individual uncured Title Defect affecting a Title Defect Property for which the Title Defect Amount therefor does not exceed $35,000 (“Individual Title Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Sellers for uncured Title Defects unless the aggregate Title Defect Amounts attributable to all uncured Title Defects, taken together with the aggregate Environmental Defect Amounts attributable to all uncured Environmental Defects, exceeds a deductible in an amount equal to 1.5% of the unadjusted Purchase Price (“Aggregate Defect Deductible”), after which point adjustments to the Purchase Price or other remedies shall be made available to Purchaser only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title

Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible. ****

(m)Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual Title Benefit for a Property for which the Title Benefit Amount therefor does not exceed $35,000 (“Individual Title Benefit Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price for Title Benefits unless the aggregate Title Benefits attributable to all Title Benefits exceeds a deductible in an amount equal to 1.5% of the unadjusted Purchase Price (“Aggregate Benefit Deductible”), after which point adjustments to the Purchase Price shall be made available to Sellers only with respect to Title Benefits where the aggregate Title Benefit Amounts are in excess of such Aggregate Benefit Deductible; for the avoidance of doubt, Title Benefit Amounts which do not meet the Individual Title Benefit Threshold shall not be included in reaching the Aggregate Benefit Deductible. ****

Section 3.5Casualty or Condemnation Loss.

(a)From and after the Effective Time, but subject to the provisions of Section 3.5(b), Purchaser shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including but not limited to the watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

(b)If, prior to the Closing Date, all or a material part of any of the Assets are damaged or destroyed by fire, flood, storm or other casualty or are taken in condemnation or under the right of eminent domain, or if proceedings for such purposes shall be pending or threatened, Sellers shall promptly notify Purchaser in writing of the nature and extent of such casualty loss or government taking and Sellers’ estimate of the cost required to repair or replace that portion of the Assets affected by the casualty loss or value of the Assets taken or threatened to be taken by the government. If all or any portion of the Assets are affected by a casualty loss or government taking, the Purchase Price will be adjusted downward by the agreed cost required to repair or replace that portion of the Assets affected by the casualty loss or the agreed value of the Assets taken or threatened to be taken by the government, and the parties will proceed with Closing, subject to the other terms and conditions of this Agreement; provided that if the parties mutually agree, in lieu of adjustments to the Purchase Price, Sellers shall (i) pay over to Purchaser: (A) all insurance proceeds payable to Sellers with respect to any such casualty loss (if applicable), (B) all sums paid to Sellers by third parties by reason of any such casualty loss (if applicable), and (C) all compensation paid to Sellers with respect to any such government taking (if applicable), and (ii) assign to Purchaser any and all claims that Seller may have against any third party with respect to such casualty loss or government taking, as applicable.

Section 3.6Limitations on Applicability.

The right of Purchaser to assert a Title Defect under this Agreement and Sellers’ rights to assert a Title Benefit under this Agreement shall terminate as of the Title Claim Date, provided there shall be no termination of (a) Purchaser’s or Sellers’ rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit Claim properly reported in a Title Benefit Notice on or before the Title Claim Date, and (b)

Purchaser’s rights under the special warranty of title contained in the Conveyance or Deed, or with respect to any breach by Sellers of any of their representations, warranties or covenants hereunder.

Section 3.7Government Approvals Respecting Assets.

(a)Federal and State Approvals. Purchaser shall, within thirty (30) days after Closing and at Purchaser’s own expense, file for approval with the applicable Governmental Bodies all assignment documents and other state and federal transfer documents required to effectuate the transfer of the Assets representing state or federal Leases or other Lands. Purchaser further agrees, promptly after Closing, to take all other actions reasonably required of Purchaser by federal or state agencies having jurisdiction to obtain all requisite regulatory approvals with respect to this transaction with respect to Assets representing state or federal Leases or other Lands, and to use its commercially reasonable efforts to obtain such approval by such federal or state agencies, as applicable, of Sellers’ assignment documents requiring such federal or state approval in order for Purchaser to be recognized by the federal or state agencies as the owner of the Assets representing state or federal Leases or other Lands. Purchaser shall provide each Seller with approved copies of such assignment documents and other state and federal transfer documents, as soon as they are available.

(b)Title Pending Governmental Approvals. Until all of the governmental approvals provided for in Section 3.7(a) have been obtained, the following shall occur with respect to the affected portion of the Assets representing state or federal Leases or other Lands:

(i)Sellers shall continue to hold record title to the affected Leases and other affected portion of the Assets as nominee for Purchaser;

(ii)Purchaser shall be responsible for all Assumed Seller Obligations with respect to the affected Leases and other affected portion of the Assets as if Purchaser was the record owner of such Leases and other portion of the Assets as of the Effective Time;

(iii)Sellers shall act as Purchaser’s nominee but shall be authorized to act only upon and in accordance with Purchaser’s instructions, and Sellers shall have no authority, responsibility or discretion to perform any tasks or functions with respect to the affected Leases and other affected portion of the Assets other than those which are purely administrative or ministerial in nature, unless otherwise specifically requested and authorized by Purchaser in writing;

(iv)Sellers shall not be obligated to incur any expenses in Sellers’ capacity as nominee for the benefit of Purchaser under this Section 3.7(b), and, provided that Sellers give Purchaser prior written notice of any expenses that Sellers are required to incur to comply with their obligations under the applicable Leases or applicable Law, Purchaser agrees to pay or reimburse Sellers for any such expenses promptly upon receiving notice thereof; and

(v)For purposes of Article 11, Sellers and Purchaser shall treat and deal with such affected Leases and other affected portions of the Assets as if full legal and equitable title to the same had passed from Sellers to Purchaser at Closing.

Article 4 ENVIRONMENTAL MATTERS

Section 4.1Assessment.

From and after the date of execution of this Agreement until the Closing Date, each Seller shall afford to Purchaser and Purchaser’s Representatives access to the Assets, including the Records in accordance with Section 7.1. Upon reasonable notice to Sellers, Purchaser shall be entitled to conduct a Phase I environmental property assessment of the Assets that satisfies the basic assessment requirements set forth under the current American Society for Testing and Material Standard Practice for Phase I environmental property assessments but such Phase I environmental property assessment shall not include any environmental sampling or testing (the “Phase I Assessment” or “Phase I, “ whether one or more). The Phase I Assessment and Purchaser’s other diligence activities shall be conducted at the sole cost, risk and expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4. Each Seller or its respective designee shall have the right to accompany Purchaser and Purchaser’s Representatives whenever they are onsite on Assets. Notwithstanding anything herein to the contrary, Purchaser shall not have access to, and shall not be permitted to conduct any environmental due diligence (including all or any part of the Phase I Assessments) with respect to any Assets where Sellers or their Affiliates do not have the authority to grant access for such due diligence; provided, however, Sellers and their Affiliates shall use their commercially reasonable efforts to obtain permission from any other Person to allow Purchaser and Purchaser’s Representatives such access and the ability to conduct environmental due diligence in accordance herewith and as long as Sellers and their Affiliates have exercised such commercially reasonable efforts, Sellers shall have no liability to Purchaser for failure to obtain any such other Person’s permission. Notwithstanding anything herein to the contrary, Purchaser shall not have the right to conduct any Phase II environmental property assessments or such other activities intended to constitute the conduct of “all appropriate inquiries” under 30 CFR Part 312. Purchaser and Sellers shall maintain, and shall cause their respective officers, employees, representatives, consultants and advisors to maintain, all information obtained by Purchaser pursuant to any Phase I or other due diligence activity as strictly confidential until the Closing occurs (and thereafter, with respect to Sellers if Closing occurs), unless disclosure of any facts discovered through such Phase I or other due diligence activity is required under any Laws. Purchaser shall provide each Seller with a copy of the final version of all environmental reports prepared by, or on behalf of, Purchaser with respect to any Phase I activity conducted on the Properties and Fee Lands. In the event that any necessary disclosures under applicable Laws are required with respect to matters discovered by any Phase I activity conducted by, for or on behalf of Purchaser, Purchaser agrees that Sellers shall be the responsible parties for disclosing such matters to the appropriate Governmental Bodies; provided that, if Sellers fail to promptly make such disclosure and Purchaser or any of its Affiliates is legally obligated to make such disclosure, Purchaser or any such Affiliate shall have the right to fully comply with such legal obligation.

Section 4.2NORM, Wastes and Other Substances.

Purchaser acknowledges that the Assets have been used for the exploration, development, and production of Hydrocarbons and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Properties or associated with the Assets.

Equipment and sites included in the Assets may contain Hazardous Materials, including NORM. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on, in or under the Properties or included in the Assets may contain Hazardous Materials, including NORM. Hazardous Materials, including NORM, may have come in contact with various environmental media, including without limitation, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media and Hazardous Materials, including NORM, from the Assets.

Section 4.3Environmental Defects.

(a)If, as a result of its investigation pursuant to Section 4.1, Purchaser determines that with respect to the Assets, there exists an Environmental Liability with respect to any Asset (other than with respect to NORM) (in each case an “Environmental Defect”), then on or prior to February 16, 2026 at 5:00 p.m. C.D.T. (the “Environmental Claim Date”), Purchaser may notify each Seller in writing of such Environmental Defect (an “Environmental Defect Notice”). EXCEPT WITH RESPECT TO PURCHASER’S RIGHTS FOR ANY BREACH BY SELLERS OF THEIR REPRESENTATIONS SET FORTH IN SECTION 5.7 OR SECTION 5.9 OR ANY BREACH BY SELLERS OF THEIR COVENANTS HEREUNDER, FOR ALL PURPOSES OF THIS AGREEMENT, PURCHASER SHALL BE DEEMED TO HAVE WAIVED ANY ENVIRONMENTAL DEFECT WHICH PURCHASER FAILS TO ASSERT AS AN ENVIRONMENTAL DEFECT BY AN ENVIRONMENTAL DEFECT NOTICE RECEIVED BY EACH SELLER ON OR BEFORE THE ENVIRONMENTAL CLAIM DATE. To be effective, each such notice must set forth (i) a description of the matter constituting the alleged Environmental Defect, (ii) the Leases, Wells and associated Assets affected by the Environmental Defect, (iii) the estimated Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”), and (iv) supporting documents reasonably necessary for Sellers to verify the existence of the alleged Environmental Defect and the Environmental Defect Amount. Purchaser agrees that, starting on the 30th day after execution of this Agreement, it shall furnish Sellers once at the end of every two (2) week period until the Environmental Claim Date with a preliminary Environmental Defect Notice if any officer of Purchaser or any of its Affiliates discovers or learns of any Environmental Defect during such two (2) week period, which notice may be preliminary in nature and supplemented prior to the expiration of the Environmental Claim Date; provided further that failure to provide preliminary notice of an Environmental Defect shall not prejudice Purchaser’s right to assert any Environmental Defect hereunder on or before the Environmental Claim Date.

(b)Sellers shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the parties shall have mutually agreed to the general plan of remediation with respect to such Environmental Defect and the time period by which such remediation shall take place, after Closing. If Sellers disagree with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the Environmental Defect Amount or the cure thereof prior to the Scheduled Closing Date, Purchaser and Sellers will attempt to resolve the dispute prior to the Scheduled Closing Date. If such dispute or any dispute among the parties on whether or not any Environmental Defect has been cured by Sellers by the Scheduled Closing Date (unless the parties have mutually agreed to allow Sellers to cure such Environmental Defect

after Closing), then such matters remaining in dispute shall be exclusively and finally resolved pursuant to this Section 4.3(b) as follows:

(i)The parties shall submit such dispute to an environmental consultant approved in writing by Sellers and Purchaser (and absent such mutual approval, appointed by the Houston office of the American Arbitration Association) that is experienced in environmental corrective action at oil and gas properties in the regional area where the relevant Properties are located and that shall not have performed professional services for either party or any of their respective Affiliates during the previous three (3) years (the “Independent Expert”). Within ten (10) Business Days following the selection of the Independent Expert, each of Purchaser, on the one hand, and Sellers, on the other hand, shall submit to the Independent Expert written explanations of their respective positions in the disputed environmental matters. The Independent Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Sellers with exhibits, including interrogatories, supplemented with appearances by Purchaser and Sellers, if necessary, as the Independent Expert may deem necessary. After the parties and Independent Expert have had the opportunity to review all such submissions, the Independent Expert shall call for a final, written offer of resolution from each party. The Independent Expert shall render its decision within fifteen (15) Business Days of receiving such offers by selecting one or the other of the offers, or by crafting a decision that represents a compromise between the two offers.

(ii)The Environmental Defect Amounts alleged by Purchaser that are applicable to the disputed Environmental matters that are not resolved prior to the Scheduled Closing Date shall be retained by Sellers at Closing, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Assets. If the Allocated Value of the Asset so held back from the initial Closing is greater than the Environmental Defect Amount determined by the Independent Expert or agreed by the parties, then such Asset will be conveyed to Purchaser (subject to the satisfaction of the conditions set forth in Section 8.2 with respect to such Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Asset) within ten (10) Business Days following the date that the Independent Expert delivers written notice to Purchaser and Sellers of his award with respect to such Environmental Defect and/or Environmental Defect Amount, at which time Purchaser shall pay to Sellers the full Allocated Value of the Asset less such Environmental Defect Amount (as adjusted pursuant to Section 2.2 through the new Closing Date therefor with respect to such Asset). If the Allocated Value of the Asset so held back from the initial Closing is less than the Environmental Defect Amount determined by the Independent Expert, then such Asset will be retained by Seller, such Asset will become an Excluded Asset hereunder and Purchaser shall have no further obligation to purchase such Asset.

(c)The Independent Expert may not award damages, interest or penalties to either party with respect to any matter. The decision of the Independent Expert shall be final and binding upon all parties, without right of appeal. Sellers and Purchaser shall each bear its own legal fees and other costs of presenting its case to the Independent Expert. The costs and expenses of the Independent Expert shall be borne and paid one-half by Sellers and one-half by Purchaser.

(d)Subject to Section 4.3(b) and the following provisions of this Section 4.3(d), the parties shall adjust the Purchase Price to reflect the Environmental Defect Amounts, as agreed by the parties or as determined by the Independent Expert, as applicable, for all uncured Environmental Defects; provided that, notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual uncured Environmental Defect (affecting one or more Assets) for which the Environmental Defect Amounts therefor do not exceed $35,000 (“Individual Environmental Threshold”); (ii) if the parties agree or the Independent Expert determines that the Environmental Defect Amount with respect to any Asset exceeds the Allocated Value thereof, then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, (iii) if the Environmental Defect Amounts for all Environmental Defects affecting any Asset, when combined with the Title Defect Amounts for all Title Defects affecting the same Asset, exceeds the Allocated Value of such affected Asset then Sellers shall retain the affected Asset, such Asset will become an Excluded Asset hereunder, the Purchase Price shall be reduced by the Allocated Value of such Asset and Purchaser shall have no further obligation to purchase such Asset, and (iv) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental Defect Amounts attributable to all such Environmental Defects, taken together with the aggregate Title Defect Amounts attributable to all uncured Title Defects, exceed the Aggregate Defect Deductible, after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts attributable thereto are in excess of such Aggregate Defect Deductible; for the avoidance of doubt, Title Defect Amounts and Environmental Defect Amounts which do not meet the Individual Title Threshold and the Individual Environmental Threshold shall not be included in reaching the Aggregate Defect Deductible.

Section 4.4Inspection Indemnity.

PURCHASER HEREBY AGREES TO DEFEND, INDEMNIFY, RELEASE, PROTECT, SAVE AND HOLD HARMLESS THE SELLER INDEMNIFIED PERSONS FROM AND AGAINST ANY AND ALL LOSSES ARISING OUT OF, OR RELATING TO, ANY DUE DILIGENCE ACTIVITY CONDUCTED ON THE ASSETS BY PURCHASER OR ITS AGENTS OR REPRESENTATIVES, WHETHER BEFORE OR AFTER THE EXECUTION OF THIS AGREEMENT, REGARDLESS OF FAULT. The indemnity obligation set forth in this Section 4.4 shall survive the Closing or termination of this Agreement.

Article 5 REPRESENTATIONS AND WARRANTIES OF SELLERS

Section 5.1Generally.

(a)Inclusion of a matter on a Schedule to a representation or warranty which addresses matters possibly having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on

such Schedule. Matters may be disclosed on a Schedule or Exhibit to this Agreement for purposes of information only. Nothing in the Schedules of Sellers is intended to broaden the scope or effect of any representation or warranty contained in this Agreement. Nothing in the Schedules constitutes an admission of any liability or obligation to any third party, or an admission to any third party against the interest of Sellers. In disclosing information pursuant to the Schedules, no Seller waives any attorney-client privilege associated with such information or any protection afforded by the work-product doctrine.

(b)Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in Sections 11.9 and the other terms and conditions of this Agreement, Sellers, jointly and severally, represent and warrant to Purchaser the matters set out in the remainder of this Article 5.

Section 5.2Existence and Qualification.

HEPI is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as corporation where the Assets it owns are located. Halcón Permian is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as corporation where the Assets it owns are located. HOCI is a corporation duly organized, validly existing and in good standing under the laws of the State of Texas and is duly qualified to do business as a corporation where the Assets it owns are located. HFS is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as corporation where the Assets it owns are located.

Section 5.3Power.

Each Seller has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 5.4Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of each Seller. This Agreement has been duly executed and delivered by each Seller (and all documents required hereunder to be executed and delivered by any Seller at Closing will be duly executed and delivered by such Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of each Seller, enforceable against each Seller in accordance with their terms subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium, and other similar Laws of general application with respect to creditors and (ii) general principles of equity.

Section 5.5No Conflicts.

Subject to compliance with or waiver of the Preference Rights and Transfer Requirements set forth in Schedule 5.13(a) **** and Schedule 5.13(b) **** and the HSR Act (if applicable), the execution, delivery and performance of this Agreement by each Seller, and the transactions contemplated by this Agreement will not (i) violate any provision of the certificate of formation or incorporation, as applicable, bylaws or limited liability company agreement or any similar governing document of any Seller, (ii) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license, contract or agreement to which any Seller is a party or which affect the Assets, (iii) violate any judgment, order, ruling, or decree applicable to any Seller as a party in interest, (iv) violate any Laws applicable to any Seller or any of the Assets, except for (a) rights to consent by, required notices to, filings with, approval or authorizations of, or other actions by any Governmental Body where the same are not required prior to the assignment of the related Asset and that are customarily obtained subsequent to the sale or conveyance thereof and (b) any matters described in clauses (ii), (iii) or (iv) above which would not have a Material Adverse Effect.

Section 5.6Liability for Brokers’ Fees.

Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of any Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 5.7Litigation.

With respect to the Assets and any Seller’s or any of its Affiliates’ ownership, operation, development, maintenance, or use of any of the Assets, except as set forth in: (i) Schedule 5.7(a), no proceeding, arbitration, action, suit, pending settlement, or other legal proceeding of any kind or nature before or by any Governmental Body (each, a “Proceeding,” and collectively “Proceedings”) (including any take-or-pay claims) to which such Seller or any of its Affiliates is a party is pending or, to such Seller’s Actual Knowledge, threatened in writing against such Seller or any of its Affiliates; and (ii) Schedule 5.7(b), to Sellers’ Actual Knowledge, no Proceeding or investigation to which such Seller is not a party which relates to the Assets is pending or threatened.

Section 5.8Taxes and Assessments.

(a)All Tax reports, returns, statements (including estimated reports, returns or statements), and other similar filings related to the Assets (the “Tax Returns”) with respect to such Taxes have been timely filed with the appropriate Governmental Body in all jurisdictions in which such Tax Returns are required to be filed, all such Tax Returns are true and correct in all material respects, and all such Taxes have been timely paid in full, and no Seller is delinquent in the payment of such Taxes.

(b)Except for the matters listed under Schedule 5.8 (and any related Proceedings), with respect to all Taxes related to the Assets, (i) there are not currently in effect any extensions or waivers of any statute of limitations of any jurisdiction regarding the assessment or collection

of any such Tax; (ii) there are no Proceedings pending or, to Sellers’ knowledge, threatened against the Assets or such Seller by any Governmental Body; (iii) there are no claims by any Governmental Body having or purporting to exercise jurisdiction with respect to any Tax in a jurisdiction where any Seller does not file Tax Returns that the applicable Seller is or may be subject to taxation by that jurisdiction; and (iv) there are no Tax liens on any of the Assets except for statutory liens for Taxes not yet due and payable. No Asset is subject to any tax partnership agreement or provisions requiring a partnership income tax return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute.

Section 5.9Compliance with Laws.

(a)Except as disclosed on Schedule 5.9, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are, in compliance with the provisions and requirements of all Laws applicable to the Assets, except where the failure to so comply would not have a Material Adverse Effect. Except as disclosed on Schedule 5.9, (i) no Seller has received any written notice that the Assets are not in compliance with any Environmental Laws, except for such non-compliance which would not have a Material Adverse Effect, and (ii) no Seller has received any written notice of any claims with respect to Environmental Liabilities with respect to the Assets or any demands to clean-up any portion of the Assets, except for such claims or demands which would not have a Material Adverse Effect. Notwithstanding the foregoing, except as set forth in Section 5.7 and this Section 5.9, Seller makes no representation or warranty, express or implied, relating to any Environmental Liabilities or Environmental Laws.

(b)With respect to the Assets, (i) no Seller has entered into, and no Seller became subject to, any material agreements, consents, orders, decrees, judgments, license or permit conditions, or other directives of any Governmental Body based on any Environmental Laws that relate to the current or future use of any of the Assets and that require any remediation or other change in the present conditions of any of the Assets, and (ii) no Seller nor, to Seller’s knowledge, any other prior owner of any of the Assets has entered into or become subject to any material agreements, consents, orders, decrees, judgments, license or permit conditions, or other directives of any Governmental Body based on any Environmental Laws that relate to the current or future use of any of the Assets and that require any remediation or other change in the present conditions of any of the Assets.

Section 5.10Contracts.

All Material Contracts are included within the list of Contracts in Schedule 1.2(d). Sellers are in material compliance with and, to Sellers’ knowledge, all counterparties are in material compliance with, all Material Contracts, except as disclosed on Schedule 5.10. Except as set forth on Schedule 5.10 and except for such matters that would not, individually or in the aggregate, have a Material Adverse Effect, no event has occurred that with notice or lapse of time or both would constitute any default under any such Material Contract by any Seller or, to Sellers’ knowledge, by any other Person who is a party to such Material Contract related to the Assets. Prior to the execution of this Agreement, Sellers made available to Purchaser true and complete copies of each Material Contract and all amendments thereto. No Seller has received or given any unresolved written notice of default, amendment, waiver, price redetermination, market out, curtailment or termination with respect to any Material Contract related to the Assets. “Material

Contracts” means any of the following types of Contracts: (a) any Contract that could reasonably be expected to result in aggregate payments or receipts of revenues by Sellers or Purchaser with respect to the Assets of more than $100,000 during the current or any subsequent year (based solely on the terms thereof and without regard to any expected increase in volumes or revenues); (b) any Hydrocarbon purchase and sale, gathering, transportation, processing or similar Contract unless terminable by each party without penalty on 30 days or less notice; (c) any Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, any Seller conducts business, including area of mutual interest Contracts; (d) any Contract with any Affiliate of any Seller which will be binding on Purchaser after the Effective Time and will not be terminable by Purchaser within 30 days or less notice; (e) any Contract that contains a call on production; (f) any Contract that is a joint venture agreement, partnership agreement, contribution agreement, joint operating agreement, unit operating agreement, farmout agreement, farmin agreement, participation agreement, exploration agreement, development agreement, or similar agreement; (g) any Contract that contains any take-or-pay, advance payment or other similar provisions that would require the delivery of Hydrocarbons, or the proceeds from the sale thereof, attributable to the Assets at some future time without receiving payment therefor at the time of delivery; (h) any Contract that requires the posting of material bonds, letters of credit, guarantees, and other forms of financial assurance; (i) any Contract that constitutes a lease under which a Seller is the lessor or the lessee of real or personal property which lease (A) cannot be terminated by Seller without penalty upon thirty (30) days or less notice and (B) involves an annual base rental of more than $50,000 (net to Seller’s interest); and (j) any Contract to sell, lease, exchange, transfer, or otherwise dispose of all or any part of the Assets.

Section 5.11Payments for Hydrocarbon Production.

Except as set forth on Schedule 5.11,

(a)All rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by any Seller to overriding royalty interest holders and other interest owners under or with respect to the Assets and the Hydrocarbons produced therefrom or attributable thereto, have been paid, or if not paid, Sellers are otherwise entitled under applicable Law and the terms of any applicable Lease to withhold payment, without penalty or interest, while resolving questions of title or obtaining division orders; and

(b)Sellers are not obligated under any contract or agreement for the sale of Hydrocarbons from the Assets containing a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering, transmission, or any other contract or agreement with respect to any of the Assets to gather, deliver, process, or transport any Hydrocarbons attributable to the Assets without then or thereafter receiving full payment therefor.

Section 5.12Governmental Authorizations.

Except as disclosed on Schedule 5.12, each Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the “Governmental Authorizations”) that are presently necessary or required for the

ownership and operation of the Seller Operated Assets operated by such Seller as currently owned and operated (excluding Governmental Authorizations required by Environmental Law). Except as disclosed in Schedule 5.7(a), Schedule 5.7(b) or Schedule 5.12, (i) each Seller has operated its Seller Operated Assets in all material respects in accordance with the conditions and provisions of such Governmental Authorizations, and (ii) no written notices of material violation have been received by any Seller, and no Proceedings are pending or, to Sellers’ knowledge, threatened in writing that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any material corrective or remedial action by any Seller.

Section 5.13Preference Rights and Transfer Requirements.

(a)Schedule 5.13(a) sets forth all Preference Rights applicable to the Assets, including Preference Rights contained in easements, rights-of-way or equipment leases included in the Assets. None of the Assets, or any portion thereof, is subject to any Preference Right which may be applicable to the transactions contemplated by this Agreement, except for Preference Rights as are set forth on Schedule 5.13(a).

(b)Except as set forth in Schedule 5.13(b), there are no Transfer Requirements that would be applicable in connection with the transfer of the Assets (assuming the various limitations “to the extent assignable” or “to the extent transferable” are not present in the definition of “Assets” for this purpose) or the consummation of the transactions contemplated by this Agreement by Sellers.

Section 5.14Payout Balances.

Schedule 5.14 contains a complete and accurate list of the status as of September 1, 2025, of any “payout” balance for the Wells, Leases and Units listed on Exhibit A-1 **** or **** Exhibit A-2 that are subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms). Other than the Wells, Leases and Units on Schedule 5.14, no other Well, Lease or Unit is subject to any reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 5.15Outstanding Capital Commitments.

As of the date hereof, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which any Seller reasonably anticipates will individually require expenditures by the owner of the Assets after the Effective Time in excess of $100,000 **** other than those shown on Schedule 5.15.

Section 5.16Imbalances.

Schedule 5.16 accurately sets forth in all material respects all of the Imbalances of Sellers arising with respect to the Assets or production therefrom and, except as disclosed in Schedule 5.16 , (i) no Person is entitled to receive any material portion of any Sellers’ Hydrocarbons produced from the Assets or to receive material cash or other payments to “balance” any disproportionate allocation of Hydrocarbons produced from the Assets under any operating

agreement, gas balancing or storage agreement, gas processing or dehydration agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, (ii) Sellers are not obligated to deliver any material quantities of Hydrocarbons or to pay any material penalties or other material amounts, in connection with the violation of any of the terms of any gas contract or other agreement with shippers with respect to the Assets, and (iii) Sellers are not obligated to pay any material penalties or other material payments under any gas transportation or other agreement as a result of the delivery of quantities of Hydrocarbons from the Wells in excess of the contract requirements. Except as set forth on Schedule 5.16, Sellers have not received, or are not obligated to receive, prepayments (including payments for gas not taken pursuant to “take-or-pay” arrangements) for any of Sellers’ share of the Hydrocarbons produced from the Properties, as a result of which the obligation exists to deliver Hydrocarbons produced from the Properties after the Effective Time without then or thereafter receiving payment therefor.

Section 5.17Condemnation.

There is no actual, and no Seller has received any written threatened taking (whether permanent, temporary, whole or partial) of any part of the Assets by reason of condemnation or the threat of condemnation.

Section 5.18Bankruptcy.

There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Sellers’ knowledge, being contemplated by or threatened against any Seller. Each Seller is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

Section 5.19Production Allowables.

Since the Effective Time, no Seller has received written notice that there has been any change proposed in the production allowables for any Wells listed on Exhibit A-2 **** or otherwise with respect to production from the Leases.

Section 5.20Foreign Person.

No Seller is a “foreign person” within the meaning of Section 1445 of the Code.

Section 5.21Drilling Obligations.

Except to the extent of those obligations previously fulfilled by Sellers or any of their predecessors, none of the Leases or Contracts contain express provisions obligating Sellers or their successors to drill any wells on the Properties (other than provisions requiring optional drilling as a condition of maintaining or earning all or a portion of a presently non-producing Lease).

Section 5.22Plugging and Abandonment.

Except as set forth on Schedule 5.22, (a) there are no wells located on the Leases or Lands pooled therewith that any Seller is currently obligated by law or contract to plug and abandon and

(b) no Seller has abandoned any wells (or removed any material items of equipment, except those replaced by items of materially equal suitability) on the Assets since the Effective Time.

Section 5.23No Material Adverse Change.

Since the Effective Time up to the date of this Agreement, there has been no:

(a)material damage, destruction or loss to the Assets; or

(b)Material Adverse Effect.

Section 5.24Bonds.

Schedule 5.24 lists all of the bonds, letters of credit and guarantees, if any, posted by Sellers or any of their Affiliates with Governmental Bodies or other third parties and relating to the Assets (the “Bonds”). No event has occurred that with notice or lapse of time, or both, would constitute a material breach or default of any of the same.

Section 5.25Suspended Funds.

Schedule 5.25 lists all Suspended Funds (including funds held in suspense for unleased interests) held by any Seller or its Affiliates as of the date of this Agreement that are attributable to the Assets, a description of the source of such funds and the reason they are being held in suspense, and, if known, the name or names of the Persons claiming such funds or to whom such funds are owed.

Section 5.26Reasonably Equivalent Value.

Receipt of the Purchase Price constitutes reasonably equivalent value (meaning, for purposes of this Agreement, that such value is within the range of value for which Sellers would sell the Assets to an individual or entity other than Purchaser, in an arms’ length transaction) in exchange for the transfer of the Assets; (b) the sale and transfer of the Assets have not been contemplated to, nor will it be consummated with the intent to, defraud, hinder, or delay any of its creditors; and (c) the transfer of the Assets has not been concealed from any of Sellers’ creditors.

Section 5.27Liens.

Schedule 5.27 lists all liens, encumbrances or mortgages covering any of the Assets, and there are no rights in any third parties which, upon the passage of time, would permit the filing of any liens or encumbrances on the Assets, other than the Permitted Encumbrances.

Section 5.28Financial Statements.

The audited financial statements of the Company for the fiscal year ended December 31, 2024 and the unaudited financial statements of the Company as of September 30, 2025, together with the related statements of income or operations, equity and cash flows for the fiscal years ended on such dates, (a) are true, accurate and complete in all material respects with respect to the Assets; (b) were prepared in accordance with GAAP consistently applied throughout the period

covered thereby; (c) fairly present the results of operations of the Assets for the period covered thereby; and (d) show all material indebtedness and other liabilities, direct or contingent, of the Company and the Sellers, to the extent relating to the Assets, including liabilities for taxes, material commitments and contingent obligations.

Article 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to each Seller the following:

Section 6.1Existence and Qualification.

Purchaser is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Texas and Purchaser is duly qualified to do business as a foreign limited partnership in every jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to so qualify would not have a material adverse effect on Purchaser; and Purchaser is or will be as of Closing duly qualified to do business as a foreign limited partnership in the respective jurisdictions where the Assets are located.

Section 6.2Power*.*

Purchaser has the power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 6.3Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar Laws of general application with respect to creditors and (ii) general principles of equity.

Section 6.4No Conflicts.

Subject to compliance with the HSR Act, the execution, delivery and performance of this Agreement by Purchaser, and the transactions contemplated by this Agreement will not (i) violate any provision of the organizational documents of Purchaser, (ii) result in a default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license, contract or agreement to which Purchaser is a party, (iii) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, or (iv) violate any Law applicable to Purchaser or any of its assets, or (v) require any filing with, notification of or consent, approval or authorization of any Governmental Body or authority, except any matters described in clauses (ii), (iii), (iv) or (v) above which would not have a material

adverse effect on Purchaser or Purchaser’s ability to perform its obligations with respect to the transactions contemplated hereby.

Section 6.5Liability for Brokers’ Fees.

Sellers shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.6Litigation.

There are no Proceedings pending, or to the Actual Knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to materially impair Purchaser’s ability to perform its obligations under this Agreement.

Section 6.7R&W Insurance Policy.

Purchaser has obtained and conditionally bound the Representation and Warranty Insurance Policy Conditional Binder, which is attached hereto as Exhibit D (the “Representation and Warranty Insurance Policy Conditional Binder”).

Section 6.8Limitation and Independent Evaluation.

Except for the representations and warranties expressly made by each Seller in Article 5 of this Agreement, or in the Conveyance and Deed, or in any certificate furnished or to be furnished to Purchaser pursuant to this Agreement, and EXCEPT IN THE CASE OF ANY SELLER’S FRAUD, INTENTIONAL MISREPRESENTATION OR WILLFUL MISCONDUCT, Purchaser acknowledges that (a) there are no representations or warranties, express, statutory or implied, as to the Assets or prospects thereof made by any Seller, and (b) Purchaser has not relied upon any oral or written information provided by Sellers. Without limiting the generality of the foregoing, subject to Section 5.9, Purchaser acknowledges that no Seller has made nor will make any representation or warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment or any other environmental condition of the Assets. Purchaser further acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller, and that it has retained and taken advice concerning the Assets and transactions herein from advisors and consultants which are knowledgeable about the oil and gas business, and that is aware of the risks inherent in the oil and gas business. Subject to Sellers’ compliance with Section 4.1, Purchaser acknowledges that it has or will have access to the Assets, the officers and employees of Sellers, and the books, records and

files made available by Sellers relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the representations of Sellers contained in Article 5 and the basis of its own independent evaluation and due diligence investigation of the Assets, and its own independent evaluation of the business, economic, legal, tax, or other consequences of this transaction including its own estimate and appraisal of the extent and value of the oil, natural gas, and other reserves attributable to the Properties.

Section 6.9SEC Disclosure.

Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act and applicable state securities Laws. Purchaser understands and acknowledges that: (i) an investment in the Properties involves certain risks; and (ii) neither the SEC nor any federal, state or foreign agency has passed upon the Properties or made any finding or determination as to the fairness of an investment in the Properties or the accuracy or adequacy of the disclosures made to Purchaser.

Section 6.10Bankruptcy.

There are no bankruptcy, reorganization or receivership proceedings pending against, or, to the knowledge of Purchaser, being contemplated by, or threatened against Purchaser. Purchaser is, and will be immediately after giving effect to the transactions contemplated by this Agreement, solvent.

Section 6.11Qualification.

As of Closing, Purchaser will be qualified to own and assume operatorship of the Leases in the jurisdictions where the Assets to be transferred to Purchaser are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser to be disqualified as such an owner or operator. To the extent required by applicable Law, as of the Closing, Purchaser will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, such Law (or other requirements) governing the ownership and operation of the Assets.

Section 6.12Financing.

Purchaser has, or will have at Closing, sufficient cash, available lines of credit or other sources of immediately available funds to enable it to pay the Purchase Price to Sellers at Closing.

Article 7 COVENANTS OF THE PARTIES

Section 7.1Access.

(a)From and after the date of this Agreement up to and including the date the Records are delivered to Purchaser pursuant to Section 1.5 (or the earlier termination of this Agreement), Sellers shall cooperate with Purchaser and provide Purchaser and its officers, directors, employees,

agents, accountants, attorneys, investment bankers, consultants, advisors and other authorized representatives (“Purchaser’s Representatives”), access to the Assets and access to the Records, but only to the extent that Sellers may do so without violating any obligations to any un-Affiliated third party or any Laws and to the extent that Sellers have authority to grant such access without breaching any restriction legally or contractually binding on Sellers; provided, however, that each Seller shall use its commercially reasonable efforts to obtain any necessary consents or approvals from un-Affiliated third parties or applicable Governmental Bodies in order to provide Purchaser and Purchaser’s Representatives such access. Purchaser shall conduct all such inspections and other information gathering described above only (i) (x) during regular business hours and (y) during any weekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, and (ii) in a manner which will not unduly interfere with Sellers’ operation of the Assets. All information obtained by Purchaser and its representatives pursuant to this Section 7.1 shall be subject to the terms of that certain Confidential Information Agreement dated October 7, 2025 (the “Confidentiality Agreement”), by and between Sellers and Purchaser; provided, however, that if the Closing should occur, the foregoing confidentiality restriction on Purchaser, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets). Sellers shall also make available to Purchaser and Purchaser’s Representatives, upon reasonable notice during normal business hours, Sellers’ personnel knowledgeable with respect to the Assets in order that Purchaser may make such diligence investigation as Purchaser considers necessary or appropriate.

(b)ALL MATERIALS, DOCUMENTS, AND OTHER INFORMATION, MADE AVAILABLE TO PURCHASER AT ANY TIME IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY, WHETHER MADE AVAILABLE PURSUANT TO THIS SECTION OR OTHERWISE, ARE MADE AVAILABLE TO PURCHASER AS AN ACCOMMODATION, AND, EXCEPT TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 5 OF THIS AGREEMENT OR THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND DEED, ARE MADE WITHOUT REPRESENTATION OR WARRANTY OF ANY KIND, WHETHER EXPRESS, IMPLIED OR STATUTORY, AS TO THE ACCURACY AND COMPLETENESS OF SUCH MATERIALS, DOCUMENTS, AND OTHER INFORMATION OR AS TO WHETHER SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION CONTAINS A MISREPRESENTATION FOR THE PURPOSES OF APPLICABLE SECURITIES LAWS (WHETHER NOW OR HEREAFTER IN EFFECT). TO THE MAXIMUM EXTENT PERMITTED BY LAW, EXCEPT FOR PURCHASER’S RIGHTS WITH RESPECT TO THE REPRESENTATIONS SET FORTH IN ARTICLE 5 OF THIS AGREEMENT OR THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND DEED, AND EXCLUDING FRAUD BY ANY SELLER, ANY RELIANCE UPON OR CONCLUSIONS DRAWN BY PURCHASER FROM SUCH MATERIALS, DOCUMENTS AND OTHER INFORMATION SHALL BE AT PURCHASER’S RISK AND SHALL NOT GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLERS, AND PURCHASER HEREBY ACKNOWLEDGES THAT IT IS NOT RELYING ON ANY REPRESENTATIONS OTHER THAN THOSE REPRESENTATIONS AND WARRANTIES SET FORTH IN ARTICLE 5 OF THIS AGREEMENT AND THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND DEED. EXCEPT FOR PURCHASER’S RIGHTS WITH RESPECT TO THE REPRESENTATIONS AND WARRANTIES OF THE SELLERS SET FORTH

IN ARTICLE 5 OF THIS AGREEMENT, THE SPECIAL WARRANTY OF TITLE CONTAINED IN THE CONVEYANCE AND DEED, AND THE INDEMNITY OBLIGATIONS SET FORTH IN THIS AGREEMENT, AND EXCLUDING FRAUD BY ANY SELLER, PURCHASER HEREBY WAIVES AND RELEASES ANY CLAIMS ARISING UNDER THIS AGREEMENT, COMMON LAW OR ANY STATUTE (WHETHER NOW OR HEREAFTER IN EFFECT) ARISING OUT OF OR RELATED TO ANY MATERIALS, DOCUMENTS OR INFORMATION PROVIDED TO PURCHASER IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 7.2Government Reviews.

(a)Sellers and Purchaser shall in a timely manner (i) make all required filings, if any, with, prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations by such party are necessary or appropriate in connection with the consummation of the transactions contemplated hereby and (ii) provide such information to the other parties hereto as Sellers or Purchaser, as applicable, may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each party to this Agreement shall cooperate with and use all commercially reasonable efforts to assist the other parties hereto with respect to such filings, applications and negotiations.

(b)If compliance with the HSR Act is required in connection with the transactions contemplated by this Agreement, within ten Business Days following the execution by Purchaser and Sellers of this Agreement, Purchaser, on the one hand, and Sellers, on the other hand, will each prepare and simultaneously file with the DOJ and the FTC the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early termination of the waiting period thereunder. Purchaser and Sellers agree to respond promptly to any inquiries from the DOJ or the FTC concerning such filings and to comply in all material respects with the filing requirements of the HSR Act. Purchaser and Sellers shall cooperate with each other and, subject to the terms of the Confidentiality Agreement, shall promptly furnish all information to the other parties hereto that is necessary in connection with Purchaser’s and Sellers’ compliance with the HSR Act. Purchaser and Sellers shall keep each other fully advised with respect to any requests from or communications with the DOJ or FTC concerning such filings and shall consult with each other with respect to all responses thereto. Each Seller and Purchaser shall use its reasonable efforts to take all actions reasonably necessary and appropriate in connection with any HSR Act filing to consummate the transactions consummated hereby. Any fees or expenses related to filings required to this Section 7.2(b) shall be shared equally by Sellers, on the one hand, and Purchaser, on the other hand.

Section 7.3Notification of Breaches.

Until the Closing,

(a)Purchaser shall notify Sellers promptly after Purchaser obtains Actual Knowledge that any representation or warranty of a Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or

agreement to be performed or observed by a Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b)Sellers shall notify Purchaser promptly after any Seller obtains Actual Knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c)If any of Purchaser’s or Sellers’ representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Sellers’ covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing, then, so long as the non-breaching party does not incur any costs of liabilities on account of such breach (and, if the non-breaching party is Purchaser, no Asset suffers a diminution in value on account of such breach), such breach shall be considered not to have occurred for all purposes of this Agreement.

(d)No notification by a party of any breach pursuant to this Section shall affect the representations, warranties or covenants of the parties or the conditions to their respective obligations hereunder.

Section 7.4Letters in Lieu; Assignments; Operatorship.

(a)Sellers will execute on the Closing Date letters in lieu of division and/or transfer orders relating to the Assets, on forms prepared by Sellers and reasonably satisfactory to Purchaser, to reflect the transactions contemplated hereby.

(b)Sellers will prepare and execute, and Purchaser will execute, on the Closing Date, all assignments or other instruments of conveyance necessary to convey to Purchaser all federal and state Leases in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Sellers.

(c)Except as set forth in Article 5 and the special warranty of title contained in the Conveyance and Deed, Sellers make no representations or warranties to Purchaser, express, implied or by statute, as to transferability or assignability of operatorship of any Seller Operated Assets. Rights and obligations associated with operatorship of any such Seller Operated Assets may be governed by operating and similar agreements that control the appointment of a successor operator, and in such case, whether Purchaser will succeed as operator of the subject Seller Operated Assets (or portions thereof) will be determined in accordance with the terms of such agreements. However, Sellers will assist Purchaser in Purchaser’s efforts to succeed Sellers or Sellers’ Affiliate(s) as operator of any Properties included in the Assets, including designating and/or appointing by assignment, to the extent legally possible, Purchaser as successor operator or taking any other actions permitted or required under the applicable operating agreement or other governing document (including executing letters whereby the applicable Seller resigns as operator of all Seller Operated Assets). Purchaser shall, promptly following Closing, to the extent required

by Law, file all appropriate forms, declarations or bonds with the applicable federal and/or state agencies relative to its assumption of operatorship with respect to the Properties. For all Seller Operated Assets, Sellers and Purchaser shall execute appropriate change or transfer of operator forms on the Closing Date, and the applicable Seller shall thereafter promptly file said forms with the applicable Governmental Body transferring operatorship of such Assets to Purchaser.

Section 7.5Public Announcements.

Until the Closing, neither Sellers nor Purchaser shall make or issue, or cause or permit any agent or Affiliate to make or issue, any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the other parties hereto; provided, however, that the foregoing shall not restrict disclosures by Purchaser or Sellers which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates. At or after Closing, each party hereto shall be permitted to issue press releases or other public announcements concerning the existence of this Agreement, the contents hereof and the transactions contemplated hereby; provided, however, that the content of any such press release or public announcement shall be subject to the prior review and reasonable approval of Sellers and Purchaser; and provided further, however, that the foregoing shall not restrict disclosures by Purchaser or Sellers which are required by applicable securities or other Laws or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates.

Section 7.6Operation of Business.

(a)Except as set forth on Schedule 7.6, from and after the date of this Agreement until the Closing, Sellers: (i) will operate and maintain the Seller Operated Assets and the business thereof as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (ii) shall use their commercially reasonable efforts to cause the applicable un-Affiliated third party to operate and maintain any Assets not operated by a Seller (or an Affiliate of a Seller) as a reasonably prudent operator, consistent with past practices and in accordance with applicable Contracts and applicable Laws, (iii) shall maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of the applicable Seller, (iv) shall notify Purchaser of any AFEs relating to the Assets that are received by any Seller or an Affiliate of any Seller, and keep Purchaser reasonably informed of ongoing operations and capital projects with respect to the Assets, (v) shall not propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by Purchaser as owner of the Assets in excess of $100,000, or make any capital expenditures with respect to any operation, or series of related operations, in respect of the Assets in excess of $100,000 (net to Sellers’ or its Affiliates’ interest), (vi) shall not terminate (other than by failing to renew an existing term), amend or waive any material right under any Contract, Surface Contract or Lease, extend the terms of any Surface Contracts or Contracts or enter into any contracts or agreements that if entered into prior to the date of this Agreement would be required to be listed in a Schedule attached to this Agreement, (vii) shall maintain insurance coverage on the Assets presently furnished by un-Affiliated third parties in the amounts and of the types presently in force as of the date of this Agreement, (viii) shall use commercially reasonable efforts to maintain in full force and effect all Leases and all Surface Contracts, (ix) shall maintain all material Governmental Authorizations applicable to

the Assets, (x) will not abandon, transfer, farmout, sell, hypothecate, mortgage, pledge, encumber or otherwise dispose of any of the Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices and/or (B) sales of equipment that is no longer necessary in the operation of the Assets or for which replacement equipment has been obtained, (xi) will not enter into any settlement, compromise or other agreement with respect to Taxes with any Governmental Body, or make or change any election with respect to Taxes, relating to the Assets, or consent to any extension or waiver of the limitation period applicable to any claim or assessment with respect to Taxes relating to the Assets, (xii) shall not (A) settle or compromise any claim relating to the Assets for which the Purchaser would have liability or (B) settle or compromise any claim relating to the Assets against a third party that would compromise or waive any claim in excess of $200,000, (xiii) shall notify Purchaser if Sellers obtain knowledge of any casualty loss or Claim by an unaffiliated third party affecting the Assets, or notice from a third party of any default by Sellers under any Contract, (xiv) shall pay all lease rentals or renewal or extension payments on undeveloped Leases where the failure to pay such rentals or payments could result in the forfeiture or termination of such Lease, (xv) act in conformity with and fulfill all obligations to make payments under all Contracts, Surface Contracts and Leases and (xvi) will not commit to do any of the items described in Section 7.6(a)(v), Section 7.6(a)(vi), Section 7.6(a)(x), Section 7.6(a)(xi) and Section 7.6(a)(xii) above. In the event of an emergency, Sellers may take such action as a prudent operator would take without the prior written consent of Purchaser; provided, however, that Sellers shall notify Purchaser of such action promptly thereafter.

(b)Purchaser acknowledges that Sellers may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners who are not a Seller or an Affiliate of a Seller shall not constitute a violation of the provisions of this Section 7.6 nor shall any action required by a vote of working interest owners constitute such a violation so long as each Seller (and any Affiliate of Sellers) has voted its interest in a manner consistent with the provisions of this Section 7.6.

Section 7.7Preference Rights and Transfer Requirements.

(a)The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements. Within 10 Business Days following the execution of this Agreement, Sellers shall send to the holders of all such Preference Rights and Transfer Requirements a notice in compliance with the contractual provisions of the same to obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 5.13(a) and Schedule 5.13(b) with respect to the transactions contemplated by this Agreement. Sellers shall use commercially reasonable efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Sellers shall not be obligated to pay any consideration to (or incur any out of pocket cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith; and provided further that, as to Transfer Requirements that (i) state that consent thereto cannot unreasonably be withheld (or words to similar effect) and (ii) do not state that the applicable transfer or assignment will be void or ineffective without consent thereto (or words to similar effect) (“Soft Consents”) constitute Soft Consents that are not obtained or waived prior to Closing, Purchaser agrees to close over such unobtained consents without adjustment to the Purchase Price. Notwithstanding anything to the contrary herein, if any Soft Consent, Transfer

Requirement, approval or authorization necessary to preserve any right or benefit under any Contract is not obtained prior to the Closing, Seller shall, subsequent to the Closing, use commercially reasonable efforts to cooperate with Purchaser in attempting to obtain such consent, approval or authorization as promptly thereafter as practicable.

(b)If the holder of a Preference Right elects prior to Closing to purchase the Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Sellers receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(c)If, as of the Closing Date, any Preference Right or Transfer Requirement has not been waived in writing by the holder thereof, or been deemed to have been waived in accordance with the terms thereof, then, unless otherwise agreed by Sellers and Purchaser, the Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Purchaser at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset pursuant to Section 7.7(b). Any Retained Asset so held back at the initial Closing will be conveyed to Purchaser (subject to the satisfaction of the conditions in Section 8.2 with respect to such Retained Asset) at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within ten (10) Business Days following the date on which Sellers obtain a waiver of or notice of election not to exercise from the applicable third parties, or otherwise satisfy, all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section 7.7(c) (or if multiple Assets are Retained Assets, on a date mutually agreed to by the parties in order to consolidate, to the extent reasonably possible, the number of Closings). At the delayed Closing, Purchaser shall pay Sellers a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 2.2 through the new Closing Date therefor with respect to such Retained Asset); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained or waived by the holder thereof as contemplated by this Section within one hundred eighty (180) days after the initial Closing has occurred with respect to any Asset, then such Retained Asset shall be eliminated from the Assets and shall become an Excluded Asset, unless Sellers and Purchaser agree to proceed with a closing on such Retained Asset, in which case Purchaser shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnified Persons for all Losses) with respect to non-compliance with such Preference Rights and Transfer Requirements with respect to such Retained Asset(s).

Section 7.8Tax Matters.

(a)Subject to the provisions of Section 12.3, Sellers shall be responsible for all Taxes related to the Assets (including, but not limited to ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, which are addressed and apportioned as set forth in Section 1.4) attributable to any period of time prior to the Effective Time, and Purchaser shall be responsible for all such Taxes related to the Assets attributable to any period of time on and after the Effective Time. Except as provided in Section 1.4, such Taxes shall be calculated by allocating

to the periods before and after the Effective Time pro rata, based on the number of days of the Straddle Period in the period before and ending on the Effective Time Cut-off Date, on the one hand, and the number of days in the Straddle Period in the period after the Effective Time Cut-off Date, on the other hand. Notwithstanding the foregoing, Sellers shall handle payment to the appropriate Governmental Body of all Taxes with respect to the Assets which are required to be paid prior to Closing (and shall file all Tax Returns with respect to such Taxes). If requested by Purchaser, Sellers will assist Purchaser with preparation of all Tax Returns including a Straddle Period and ending on or before the Closing Date (including any extensions requested), but which are required to be paid after the Closing Date. No later than fifteen (15) days prior to the deadline to file each applicable Tax Return, Sellers shall deliver to Purchaser a draft of the applicable Tax Return to be filed by Sellers relating to the Assets and any supporting documentation thereto for Purchaser’s approval, which shall not be unreasonably withheld, excluding Tax Returns related to income tax, franchise tax, or other similar Taxes and routine monthly sales Tax Returns, monthly Texas Gas Severance Tax Returns and monthly GLO royalty filings. Purchaser shall file all Tax Returns covering Taxes treated as Property Costs that are required to be filed after the Closing Date unless covered above. With respect to such Tax Returns covering a Straddle Period, Purchaser shall provide each draft Tax Return to Sellers no later than fifteen (15) days prior to the deadline to file the applicable Tax Return for Sellers’ approval, which shall not be unreasonably withheld. If any Taxes allocated to Sellers pursuant to this Section 7.8 or Section 1.4 are actually paid by Purchaser, then, after the Closing Date and upon written request by Purchaser, Sellers shall, within fifteen (15) Business Days of such request, make a payment to Purchaser of the amount of any such Taxes paid by Purchaser but allocated to Sellers. If any Taxes allocated to Purchaser pursuant to this Section 7.8 or Section 1.4 are actually paid by Sellers and not already accounted for in an adjustment to the Purchase Price pursuant to Section 2.2(d), then, after the Closing Date and upon written request by Sellers, Purchaser shall, within fifteen (15) Business Days of such request, make a payment to Sellers of the amount of any such Taxes paid by Sellers but allocated to Purchaser.

(b)Purchaser and Sellers shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with the filing of any Tax Returns and any audit, litigation or other Proceeding with respect to Taxes. Such cooperation shall include the retention and (upon the other party’s request) the provision of records and information which are reasonably relevant to any such audit, litigation or other Proceeding and making employees reasonably available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Sellers shall control audits for pre-Effective Time periods (and the pre-Effective Time portion of any audit that includes a Straddle Period), keep Purchaser reasonably informed, and Sellers may not settle any item that would reasonably be expected to increase Purchaser’s Taxes for post-Effective Time periods without Purchaser’s prior written consent (not to be unreasonably withheld). Purchaser and each Seller agree (i) to retain all books and records with respect to Tax matters pertinent to the Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Purchaser or Sellers, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Governmental Body, and (ii) to give the other party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other party so requests, each party shall allow the other party the option of taking possession of such books and records prior to their disposal. Purchaser and Sellers further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other

document from any Governmental Body or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated hereby. Sellers shall promptly notify Purchaser in writing upon receipt by any Seller of notice of any pending or threatened Tax audits or assessments relating to the income, properties or operations of Seller that reasonably may be expected to relate to or give rise to a lien on the Assets. Each of Purchaser and Sellers shall promptly notify the other in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the Allocation.

(c)Purchaser and Sellers shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with accommodating a 1031 exchange (as provided for under Section 1031 of the Code). Purchaser and each Seller reserves the right, at or prior to Closing, to assign its rights under this Agreement with respect to all or a portion of the Purchase Price, and that portion of the Assets associated therewith (“1031 Assets”), to a “Qualified Intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4)(v) of the Treasury Regulations) to accomplish this transaction, in whole or in part, in a manner that will comply with the requirements of a like-kind exchange (“Like-Kind Exchange”) pursuant to Section 1031 of the Code. If Purchaser so elects, Purchaser may assign its rights under this Agreement to the 1031 Assets to the Qualified Intermediary and its right to receive the Conveyance and Deed to an Affiliate. Seller hereby (i) consents to Purchaser’s assignment of its rights in this Agreement with respect to the 1031 Assets, and (ii) if such an assignment is made, agrees to transfer all or a portion of the Assets into the qualified trust account or into Purchaser’s Affiliate at Closing as directed in writing by Purchaser. Purchaser and each Seller acknowledge and agree that a whole or partial assignment of this Agreement to a Qualified Intermediary shall not release the other party from any of its respective promises, liabilities and obligations to the other party or expand any promises, liabilities or obligations of such party under this Agreement. Neither party represents to the other that any particular tax treatment will be given to either party as a result of the Like-Kind Exchange. Neither party shall be obligated to pay any additional costs or incur any additional obligations in its sale of the Assets if such costs are the result of the other party’s Like-Kind Exchange, and each party shall hold harmless and indemnify the other party from and against all claims, losses and liabilities (including reasonable attorneys’ fees, court costs and related expenses), if any, resulting from such a Like-Kind Exchange. The Closing Date shall not be delayed or affected by reason of the Like-Kind Exchange.

(d)Any payments made to any party pursuant to Article 11 shall constitute an adjustment of the Purchase Price for Tax purposes and shall be treated as such by Purchaser and Sellers on their Tax Returns to the extent permitted by Law.

Section 7.9Representation and Warranty Insurance Policy*.*

Following the execution of this Agreement, Purchaser shall satisfy the conditions set forth in the Representation and Warranty Insurance Policy Conditional Binder to cause the Representation and Warranty Insurance Policy to be issued on terms and in the form set forth in the Representation and Warranty Insurance Policy Conditional Binder as soon as practicable. Purchaser shall maintain the Representation and Warranty Insurance Policy in effect at all times for the stated duration of its effectiveness based on the terms thereof in effect as of the Closing Date. Purchaser shall cause the Representation and Warranty Insurance Policy to (a) name Purchaser as the named insured, (b) insure Purchaser from any breach, or any failure to be true, of

the representations and warranties made by Sellers under this Agreement or in any certificate delivered pursuant hereto and (c) expressly provide that (i) the insurer(s) issuing the Representation and Warranty Insurance Policy waive and release any and all rights to bring any claim or proceeding against the Seller Indemnified Persons by way of subrogation, claim for contribution, indemnification or other right (other than, but solely in the case of, Fraud), (ii) the Fraud of any Party shall not be imputed to any other Person(s), (iii) the Seller Indemnified Persons are express third-party beneficiaries of the foregoing waiver and release entitled to rely on and enforce such waiver and release as if parties to the Representation and Warranty Insurance Policy, and (iv) the Representation and Warranty Insurance Policy shall not be amended, modified, or otherwise changed in a manner adverse or prejudicial to any Seller individually or the Sellers collectively or any other Seller Indemnified Person without the prior written consent of such adversely affected or prejudiced Seller, which may be withheld, conditioned, or delayed in such Seller’s sole and absolute discretion. The Parties acknowledge and agree that the failure by Purchaser to obtain or maintain the Representation and Warranty Insurance Policy shall not in any manner increase any liability of any Seller or the other Seller Indemnified Persons, including if (x) the Representation and Warranty Insurance Policy is disputed, invalidated or deemed ineffective, in whole or in part, (y) the coverage provided under the Representation and Warranty Insurance Policy is denied, disputed, exhausted or otherwise made unavailable to Purchaser or any of its Affiliates or any other insured thereunder, in whole or in part, or (z) there is otherwise an absence of coverage thereunder for any reason, including due to exclusions. Purchaser acknowledges that Purchaser obtaining the Representation and Warranty Insurance Policy Conditional Binder and purchasing and obtaining the Representation and Warranty Insurance Policy as of the Closing Date (and maintaining the Representation and Warranty Insurance Policy after the Closing Date subject to the depletion of the limit through any claims) is a material inducement to Sellers entering into the transactions contemplated by this Agreement, and Sellers are materially relying on Purchaser’s covenants and obligation set forth in Sections 6.7 and 7.9 without any limitation. From and after the Closing Date, Purchaser shall not (and shall cause its Affiliates not to) grant any right of subrogation, indemnification, claim of contribution or other right or otherwise amend, modify, terminate, or waive any term or condition of the Representation and Warranty Insurance Policy in a manner inconsistent with the immediately preceding sentence. Purchaser shall timely pay, or cause to be paid, all costs, fees and expenses related to the Representation and Warranty Insurance Policy, including the total premium, underwriting costs, taxes, brokerage commission, retention, and other costs, fees and expenses of the Representation and Warranty Insurance Policy and any claims made thereunder, as such costs, fees and expenses are due.

Section 7.10Further Assurances.

After the Closing, Sellers and Purchaser shall, and shall cause their Affiliates, as applicable to, execute, acknowledge and deliver from time to time all such further conveyances, transfer orders, division orders, notices and such other instruments, and shall take such further actions as any party hereto may reasonably request and as may be necessary or appropriate to accomplish the transactions described in this Agreement (including that all of the Assets intended to be conveyed under the terms of this Agreement are so conveyed, including such Assets that are improperly described herein or inadvertently omitted from this Agreement and/or the Conveyance and Deed and/or the Exhibits attached to each of the foregoing and to perfect Purchaser’s title thereto.

Section 7.11Notice of Claims.

Sellers shall promptly notify Purchaser as soon as reasonably practicable (but in any event within five Business Days) of any written notice received or given by any Seller or Affiliate of any Seller with respect to (a) any alleged material breach of any Lease or Contract, (b) any action to alter, terminate, rescind or procure a judicial reformation of any Lease or Contract or (c) any new claim for damages or any new investigation, suit, action or litigation with respect to the Assets.

Section 7.12Enforcement of Third Party Warranties, Guarantees and Indemnities.

Sellers agree that as of the Closing Date, to the extent relating to the Assumed Seller Obligations and at Purchaser’s request, Sellers shall use their commercially reasonable efforts to enforce, for the benefit of Purchaser and at Purchaser’s cost and expense, all of Sellers’ (or their respective Affiliates’) rights against un-Affiliated third parties under any warranties, guarantees or indemnities given by such third parties with respect to the Assets.

Article 8 CONDITIONS TO CLOSING

Section 8.1Conditions of Sellers to Closing.

The obligations of Sellers to consummate the transactions contemplated by this Agreement are subject to the fulfillment on or prior to Closing of each of the following conditions, each of which may be waived by Sellers:

(a)Representations. Each of the representations and warranties of Purchaser contained in Article 6 shall be true and correct in all material respects as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects as of such specified date; and (ii) to the extent the failure of such representations or warranties to be true and correct would not, individually or in the aggregate, result in a Material Adverse Effect

(b)Performance. Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Purchaser under this Agreement prior to the Closing Date and shall be ready, willing and able to perform, in all material respects, all covenants and agreements to be performed by Purchaser under this Agreement on the Closing Date;

(c)Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial damages in connection with (excluding any damage that Purchaser expressly agrees to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damage that Purchaser expressly agrees to be responsible for) in connection with, the transactions contemplated by this Agreement, and no statute, rule, regulation or other requirement shall have

been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby;

(d)Deliveries. Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Sellers duly executed counterparts of the Conveyance and Deed, and all other documents and certificates to be delivered by Purchaser under Section 9.3 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.3;

(e)HSR Act. Except to the extent set forth in Section 7.2(b), and to the extent this transaction is subject to the HSR Act, any waiting period applicable to the consummation of the transactions contemplated by this Agreement under the HSR Act shall have lapsed or terminated (by early termination or otherwise); and

(f)Price Adjustment Limitations. The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4 (Notice of Title Defect Adjustments), Section 3.5 (Casualty or Condemnation Loss), Section 4.3 (Environmental Defects) and Section 7.7 (Preference Rights and Transfer Requirements) does not exceed twenty percent (20%) of the Purchase Price.

Section 8.2Conditions of Purchaser to Closing.

The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject, at the option of Purchaser, to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions:

(a)Representations. Each of the representations and warranties of Sellers contained in Article 5 shall be true and correct in all material respects as of the date hereof and as of the Closing Date as though made on and as of the Closing Date, except (i) to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects as of such specified date; and (ii) to the extent the failure of such representations or warranties to be true and correct would not, individually or in the aggregate, result in a Material Adverse Effect.

(b)Performance. Sellers shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by Sellers under this Agreement prior to the Closing Date and shall be ready, willing and able to perform, in all material respects, all covenants and agreements to be performed by Sellers under this Agreement on the Closing Date;

(c)Proceedings. No Proceeding by an un-Affiliated third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit, or seeking substantial damages in connection with (excluding any damages that Sellers expressly agree to be responsible for), the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order, writ, injunction, decree, award or judgment shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction to restrain, enjoin, or prohibit, or awarding substantial damages (excluding any damages that Sellers expressly agree to be responsible for) in connection with, the transactions contemplated by this Agreement, and no statute, rule, regulation or other requirement shall have

been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby;

(d)Deliveries. Sellers shall have delivered or cause to be delivered (or be ready, willing and able to immediately deliver or cause to be delivered) to Purchaser duly executed counterparts of the Conveyance and Deed, and all other documents and certificates to be delivered or caused to be delivered by Sellers under Section 9.2;

(f)Price Adjustment Limitations. The aggregate maximum downward adjustment (if any) of the Purchase Price which will result from adjustments pursuant to Section 3.4, Section 3.5, Section 4.3 and Section 7.7 does not exceed twenty percent (20%) of the Purchase Price.

Article 9 CLOSING

Section 9.1Time and Place of Closing.

(a)Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 10, and subject to the satisfaction or waiver of the conditions set forth in Article 8 (other than conditions the fulfillment of which by their nature is to occur at the completion of the transactions contemplated by this Agreement (the “Closing”)), and subject to the provisions of Section 7.7(c) relating to Retained Assets, the Closing, shall take place at 10:00 a.m., local time, on February 24, 2026 (such date the “Scheduled Closing Date”), at the offices of Battalion Oil Corporation, 820 Gessner, Suite 1100, Houston, Texas 77024. If any of the conditions (other than conditions the fulfillment of which by their nature is to occur at the Closing) set forth in Article 8 are not satisfied or waived at the time the Closing is to occur pursuant to this Section 9.1(a), then the Closing shall occur on a date that is the third Business Day after the satisfaction or waiver of all such conditions.

(b)The date on which the Closing occurs is herein referred to as the “Closing Date”.

Section 9.2Obligations of Sellers at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Sellers shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a)the Conveyance and the Deed, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by each Seller;

(b)assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising part of the Assets, duly executed and (if applicable) acknowledged by each Seller;

(c)transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by the applicable Seller and prepared in accordance with Section 7.4(a);

(d)a certificate duly executed by an authorized corporate officer of each Seller, dated as of Closing, certifying on behalf of Sellers that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(e)evidence that all lien releases from the Sellers’ current lenders have been obtained relating to all mortgages, deeds of trust, fixture filings and security agreements affecting the Assets, and that releases of any related financing statements have been obtained (where applicable, in accordance with the Uniform Commercial Code);

(f)the change or transfer of operator forms referenced in Section 7.4(c) to be executed by each applicable Seller and which forms shall be filed by Purchaser pursuant to Section 7.4(c) after Closing;

(g)the Preliminary Settlement Statement, duly executed by each Seller;

(h)a joint instruction letter to the Escrow Agent, duly executed by Seller Representative instructing the Escrow Agent to release the Deposit to Sellers;

(i)if applicable, the escrow agreement to be entered into among Seller Representative, Purchaser and Escrow Agent pursuant to Section 3.4(k) duly executed by Seller Representative;

(j)duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Sellers at the Closing;

(k)a completed IRS Form W-9 with respect to each Seller; and

(l)a duly executed non-foreign status certificate under Section 1445 of the Internal Revenue Code (FIRPTA Certificate), in form and substance satisfactory to Purchaser.

Section 9.3Obligations of Purchaser at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shall deliver or cause to be delivered to Sellers, or perform or caused to be performed, the following:

(a)a wire transfer to each Seller (to the accounts designated in Schedule 9.4(d)) in an amount equal to such Seller’s Closing Payment, in immediately available funds;

(b)the Conveyance and the Deed, in sufficient number of counterpart originals to allow recording in all appropriate jurisdictions and offices, duly executed and acknowledged by Purchaser;

(c)assignments, on appropriate forms and in sufficient number of counterpart originals to allow filing in the applicable state and federal offices, of any state and federal leases comprising portions of the Assets, duly executed and (if applicable) acknowledged by Purchaser;

(d)a certificate by an authorized corporate officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled;

(e)transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Purchaser of proceeds attributable to production from the Assets from and after the Effective Time, in each case duly executed by Purchaser and prepared in accordance with Section 7.4(a);

(f)the Preliminary Settlement Statement, duly executed by Purchaser;

(g)a joint instruction letter to the Escrow Agent, duly executed by Purchaser instructing the Escrow Agent to release the Deposit to Sellers;

(h)if applicable, the escrow agreement to be entered into among Seller Representative, Purchaser and Escrow Agent pursuant to Section 3.4(k) duly executed by Purchaser; and

(i)duly executed counterparts of any other agreements, instruments or documents which are required by the other terms of this Agreement to be executed and/or delivered by Purchaser at the Closing.

Section 9.4Closing Adjustments.

(a)Not later than five (5) Business Days prior to the Closing Date, Sellers shall prepare in good faith and deliver to Purchaser, based upon the best information available to Sellers at such time, a draft preliminary settlement statement (the “Preliminary Settlement Statement”) estimating each Seller’s share of the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2 and any amounts to be escrowed pursuant to Section 3.4(k) and reflecting the calculation of the adjustments used to determine such amounts. Within four (4) Business Days of receipt of the Preliminary Settlement Statement, Purchaser will deliver to Sellers a written report containing all changes, with the explanation therefor, that Purchaser proposes to be made to the Preliminary Settlement Statement. The Preliminary Settlement Statement, as agreed upon by Sellers and Purchaser, will be used to adjust the Adjusted Purchase Price and determine the dollar amount to be paid by Purchaser to each Seller at the Closing (each, the “Closing Payment”). If Sellers and Purchaser cannot agree on the Preliminary Settlement Statement prior to Closing, the Preliminary Settlement Statement as presented by Sellers (with such changes agreed to by the parties) will be used to adjust the Adjusted Purchase Price and determine each Closing Payment.

(b)As soon as reasonably practicable after the Closing but not later than 120 days following the Closing Date, Sellers shall prepare and deliver to Purchaser a statement (the “Final

Settlement Statement”) setting forth the final calculation of the Adjusted Purchase Price, and each Seller’s share thereof, and showing the calculation of each adjustment, based on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement, including any amount escrowed pursuant to Section 3.4(k) (the “Final Purchase Price”). Sellers shall, at Purchaser’s request, supply reasonable documentation in Sellers’ or their Affiliates’ possession available to support any credit, charge, receipt or other item for which adjustments are made. Sellers shall afford Purchaser and its representatives the opportunity to review such statement and the supporting schedules, analyses, workpapers, and other underlying records or documentation as are reasonably necessary and appropriate in Purchaser’s review of such statement. Each party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto. As soon as reasonably practicable but not later than the 30th day following receipt of Sellers’ statement hereunder, Purchaser shall deliver to Sellers a written report containing any changes that Purchaser proposes be made to such statement.

(c)Sellers and Purchaser shall undertake to agree on the Final Settlement Statement, including the final statement of the Final Purchase Price, and each Seller’s share thereof, no later than one hundred eighty (180) days **** after the Closing Date (the “Final Settlement Date”). In the event that Sellers and Purchaser cannot reach agreement by the Final Settlement Date, either party may refer the remaining matters in dispute to a nationally-recognized independent accounting firm as may be mutually selected by Purchaser and Sellers (and absent such mutual selection, as appointed by the Houston office of the American Arbitration Association), for review and final determination (the “Agreed Accounting Firm”). Each of Purchaser, on the one hand, and Sellers, on the other hand, shall summarize its position with regard to the remaining matters in dispute in a written document of twenty-five (25) pages or less and submit such summaries to the Agreed Accounting Firm, together with any other documentation such party may desire to submit. Within fifteen (15) Business Days after receiving the parties’ respective submissions, the Agreed Accounting Firm shall render in writing a decision choosing Sellers’ position or Purchaser’s position, whichever is most accurate based on the terms of this Agreement and the materials described above. The Agreed Accounting Firm may not award damages or penalties to any party. Any decision rendered by the Agreed Accounting Firm pursuant hereto shall be final, conclusive and binding on Sellers and Purchaser and will be enforceable against any of the parties hereto in any court of competent jurisdiction. The fees of the Agreed Accounting Firm shall be borne and paid one-half by Sellers and one-half by Purchaser. Sellers and Purchaser shall each bear its own legal fees and other costs of presenting its case. Within ten (10) Business Days after the date on which Sellers and Purchaser or the Agreed Accounting Firm, as applicable, finally determines the disputed matters, subject to Section 3.4(k) with respect to any amounts escrowed pursuant thereto (x) Purchaser shall pay to Sellers each Seller’s share of the amount by which the Final Purchase Price exceeds the Closing Payment or (y) each Seller shall pay to Purchaser the amount by which such Seller’s share of the Closing Payment exceeds such Seller’s share of the Final Purchase Price, as applicable.

(d)All payments made or to be made hereunder to a Seller shall be by electronic transfer of immediately available funds to the account of such Seller as set forth on Schedule 9.4(d) , for the credit of Sellers or to such other bank and account as may be specified by such Seller to Purchaser in writing. All payments made or to be made hereunder to Purchaser shall

be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Sellers.

Article 10 TERMINATION

Section 10.1Termination.

This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing:

(a)by mutual written consent of Sellers and Purchaser;

(b)by Sellers or by Purchaser, by written notice to the other, if:

(i)the Closing shall not have occurred on or before March 26, 2026 (the “Termination Date”); provided, however, that the right to terminate this Agreement under this Section 10.1(b)(i) shall not be available (A) to any Seller, if any breach of this Agreement by a Seller has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date or (B) to Purchaser, if any breach of this Agreement by Purchaser has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date; or

(ii)there shall be any Law that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Body shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and non-appealable;

(c)by Sellers, if Purchaser shall have failed to fulfill in any material respect any of its obligations under this Agreement; and such failure has not been cured within ten (10) days after written notice thereof from Seller to Purchaser; provided that, any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date;

(d)by Purchaser, if a Seller shall have failed to fulfill in any material respect any of its obligations under this Agreement, and, such failure, if curable, has not been cured within ten (10) days after written notice thereof from Purchaser to such Seller; provided that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date;

(e)by Sellers, if the condition set forth in Section 8.1(f) has not been satisfied or waived in writing by Sellers;

(f)by Purchaser, if the condition set forth in Section 8.2(f) has not been satisfied or waived in writing by Purchaser; or

(g)by Purchaser, in accordance with the terms of Section 10.2(b) with regard to failure of Sellers to obtain necessary consents, authorizations and releases.

Section 10.2Remedies.

(a)If this Agreement is terminated pursuant to Section 10.1, this Agreement shall become void and of no further force or effect and the parties shall have no liability or obligation hereunder (except for the provisions of Section 2.4, Section 4.4, Section 5.6, Section 6.5, Section 7.5, and Section 11.9 of this Agreement and this Article 10, the Section entitled “Definitions,” and Article 12 (other than Section 12.3, Section 12.5, Section 12.6 and Section12.20), all of which shall continue in full force and effect). Notwithstanding the foregoing but subject to the remainder of this Section 10.2(a), nothing contained in this Section 10.2(a) shall relieve any party from liability for Losses resulting from its breach of this Agreement. If Sellers terminate this Agreement (a) because the Closing has not occurred on or before the Termination Date and Purchaser’s breach of this Agreement **** has been the principal cause of, or resulted in, the failure of Closing to occur on or before the Termination Date; or (b) as the result of any failure of Purchaser to fulfill in any material respect any of Purchaser’s obligations hereunder and such failure is not cured as provided in Section 10.1(c), then, subject to the terms of Section 2.4, Sellers shall be entitled to the Deposit as liquidated damages and Sellers’ sole and exclusive remedy on account of the termination of this Agreement (and Seller Representative and Purchaser shall jointly direct the Escrow Agent to deliver the Deposit to Sellers). Subject to Section 10.2(b), if Purchaser terminates this Agreement or is entitled to terminate this Agreement (i) because the Closing has not occurred on or before the Termination Date and a Seller’s breach of this Agreement **** has been the principal cause of, or resulted in, the failure of Closing to occur on or before the Termination Date; or (ii) as the result of any failure of any Seller to fulfill in any material respect any of such Seller’s obligations hereunder and such failure is not cured as provided in Section 10.1(d), then Purchaser shall be entitled to (A) seek specific performance of the terms of this Agreement (in which case, this Agreement shall not terminate) or (B) return of the Deposit in accordance with Section 2.4 (and Seller Representative and Purchaser shall jointly direct the Escrow Agent to deliver the Deposit to Purchaser) and damages from Sellers for the Losses suffered by Purchaser on the account of a breach of this Agreement by any Seller up to the amount of the Deposit.

(b)Notwithstanding anything in this Agreement to the contrary, if any of the conditions precedent to the obligations of Purchaser in Section 8.2 have not been satisfied due to the failure of Sellers to obtain all consents, authorizations and releases necessary to consummate the transactions contemplated by this Agreement from any of Sellers’ or the Company’s lenders or creditors (or pursuant to relevant credit agreements), and such failure prevents Closing from occurring on or before the Termination Date, then Purchaser may terminate this Agreement immediately by delivery of written notice to Sellers, in which case: (i) Sellers shall immediately pay to Purchaser a break-up fee in the amount of $1,000,000.00 in immediately available funds (the “Break-Up Fee”), as liquidated damages and not as a penalty, which the Parties agree is a reasonable estimate of Purchaser’s Losses; (ii) the Deposit shall be returned to Purchaser, and Sellers and Purchaser shall immediately deliver joint written instructions to the Escrow Agent directing it to release the Deposit to Purchaser, and (iii) payment of the Break-Up Fee and return of the Deposit shall be Purchaser’s sole and exclusive remedy on account of the termination of this Agreement under this Section 10.2(b); and (iv) this Agreement shall be deemed terminated upon actual receipt of the Break-Up-Fee and Deposit by Purchaser; provided, however, that Sellers shall use reasonable good faith efforts to timely secure all such consents, authorizations and releases as anticipated under this Agreement.

Article 11 POST-CLOSING OBLIGATIONS; Survival; LIMITATIONS; DISCLAIMERS AND WAIVERS

Section 11.1Receipts.

Any Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and any other income, proceeds, receipts and credits attributable to the Assets (in each case) which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and all other income, proceeds, receipts and credits earned with respect to the Assets to which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser, and, to the extent received by Sellers, Sellers shall fully disclose, account for and remit the same promptly to Purchaser, and (b) all Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and all other income, proceeds, receipts and credits earned with respect to the Assets to which Sellers are entitled under Section 1.4 shall be the sole property and entitlement of Sellers and, to the extent received by Purchaser, Purchaser shall fully disclose, account for and remit the same promptly to Sellers.

Section 11.2Expenses.

Any Property Costs which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Property Costs for which Sellers are responsible under Section 1.4 shall be the sole obligation of Sellers and Sellers shall promptly pay, or if paid by Purchaser, promptly reimburse Purchaser for and hold Purchaser harmless from and against same; and (b) all Property Costs for which Purchaser is responsible under Section 1.4 shall be the sole obligation of Purchaser, and Purchaser shall promptly pay, or if paid by Sellers, promptly reimburse Sellers for and hold Sellers harmless from and against same. Sellers are entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Sellers are wholly responsible and Purchaser is entitled to resolve all joint interest audits and other audits of Property Costs (including payment of any third party audit fees and expenses) covering periods for which Purchaser is in whole or in part responsible; provided that Purchaser shall not agree to any adjustments to previously assessed costs for which Sellers are liable without the prior written consent of Seller. Purchaser shall provide Sellers with a copy of all applicable audit reports and written audit agreements received by Purchaser and relating to periods for which Sellers are partially or wholly responsible, and Sellers shall provide Purchaser with a copy of all applicable audit reports and written audit agreements received by a Seller and relating to periods for which Purchaser is partially or wholly responsible.

Section 11.3Assumed Seller Obligations.

Subject to Purchaser’s rights under (a) any title indemnity agreement entered into by the parties pursuant to this Agreement and (b) the special warranty of title contained in the Conveyance and Deed, from and after the Closing, Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of each Seller, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time up to the Closing Date, including obligations to (i) furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (ii) pay the holders of working interests, royalties, overriding royalties and other interests the Suspended Funds to which they are entitled (it being agreed that, notwithstanding anything in this Agreement to the contrary, subject to the provisions of Section 12.20 below, Purchaser shall be solely responsible for the distribution of all Suspended Funds transferred to Purchaser pursuant hereto), (iii) properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (iv) replug any well, wellbore, or previously plugged well on the Properties to the extent required by any Governmental Body, (v) dismantle, salvage and remove any equipment, structures, materials, flowlines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (vi) clean up, restore, remediate or otherwise respond to Hazardous Materials on, at or migrating from the premises covered by or included in the Assets in accordance with applicable Contracts and Laws, to comply with Laws concerning Hazardous Materials and Environmental Liabilities related to the Assets, and to discharge all other Environmental Liabilities, and (vii) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and related Contracts, or as required by applicable Laws (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Seller Obligations”); provided, however, that the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities to the extent that they are (such excluded obligations and liabilities, the “Excluded Seller Obligations”):

(A)attributable to, or arise out of, the ownership, use or operation of the Excluded Assets;

(B)the continuing responsibility of Sellers under Section 11.1 or Section 11.2;

(C)Property Costs for which any Seller is responsible pursuant to Section 1.4(b); and

(D)attributable to, or arise out of, the Retained Liabilities.

Section 11.4Survival; Exclusive Remedy; Release.

The representations and warranties contained in Article 5 and Article 6 (other than the Fundamental Representations and Tax Representations) shall terminate twenty-four (24) months after the Closing Date. The Fundamental Representations shall survive the Closing without time limit, and the Tax Representations shall survive the Closing until the expiration of the applicable statute of limitations period plus thirty (30) days. The indemnities in Section 11.5(a), Section 11.5(b), Section 11.6(a) and Section 11.6(b) shall terminate as of the termination date of each

respective representation, warranty, covenant or agreement that is subject to indemnification. Notwithstanding anything in this Agreement to the contrary, (i) Sellers’ indemnity set forth in Section 11.5(c) shall survive the Closing without time limit and (ii) Purchaser’s indemnities set forth in Section 11.6(c), Section 11.6(d), Section 11.6(e) and Section 11.6(f) shall survive the Closing without time limit. There shall be no termination of a bona fide claim asserted pursuant to the indemnities prior to the date of termination for such indemnity. Except as set forth in Section 7.1(b) and Section 11.6 and the Fundamental Representations, none of the representations or warranties in Article 5 and Article 6 of this Agreement or in any certificate or other instrument delivered by Purchaser or each Seller pursuant to this Agreement, and none of the covenants or agreements in this Agreement, shall survive the Closing and all rights, claims and causes of action (whether under any contract, misrepresentation, tort or strict liability theory, or under applicable Law, and whether in law or in equity, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended) with respect thereto shall terminate at the Closing. Notwithstanding the foregoing, this Section 11.4 shall not in any way limit any covenant or agreement of the Parties set forth in Article 2, Section 7.2, Section 7.4, Section 7.5, Section 7.7, Section 7.8, Section 7.9, Section 11.4, Section 11.5 or Article 12, including the defined terms used therein and herein and any rules of construction applicable thereto, which covenants and agreements shall survive the Closing until fully performed. Except in the event of Fraud, neither Seller, Purchaser nor any of their respective Affiliates shall have any liability with respect to any representation, warranty, covenant, agreement or any other remedy contained in this Agreement or any certificate or other instrument delivered in respect hereof or any Schedule, certificate or other similar instrument delivered pursuant to this Agreement from and after the time that such representation, warranty, covenant, agreement or other remedy ceases to survive hereunder; provided that nothing in the foregoing shall limit any claim or recovery that may be available to Purchaser under the Representation and Warranty Insurance Policy. Without limiting the generality of the foregoing, each Party hereby waives, to the fullest extent permitted under applicable Law, any and all rights and Claims that it or any of its respective Affiliates may have against any other Party or any of its past, present or future Affiliates or its or their respective Representatives with respect to any representations, warranties or covenants terminated upon Closing pursuant to this Section 11.4, whether under any contract, misrepresentation, tort or strict liability theory, or under applicable Law, and whether in law or in equity. Purchaser acknowledges and agrees that, subject to the indemnification obligations of each Seller (excluding those associated any RWI Coverage Obligations, defined below) herein, and except with respect to Fundamental Representations and the Tax Representations and in the case of Fraud, the Representation and Warranty Insurance Policy shall be the sole and exclusive remedy of Purchaser and its Affiliates and any other insured under the Representation and Warranty Insurance Policy (for avoidance of all doubt, specifically excluding Seller Indemnified Persons) in law or in equity, which such Persons have now or may have in the future, resulting from, arising out of, or related to any inaccuracy or breach of any representation or warranty regarding any Seller contained in Article 5 or any certificate delivered by any Seller pursuant to this Agreement (the “RWI Coverage Obligations”), and neither Purchaser, any of its Affiliates, nor any other Person (including the insured under the Representation and Warranty Insurance Policy) shall have any recourse against any Seller or any of the other Seller Indemnified Persons with respect thereto other than in respect of the Fundamental Representations and the Tax Representations. If the amounts available under the Representation and Warranty Insurance Policy are insufficient to pay Purchaser or its Affiliates (or any other insured under the Representation and Warranty Insurance 54

Policy) or if there is a partial or full failure to bind any Representation and Warranty Insurance, then any amounts owed to such Person in respect of any RWI Coverage Obligations shall be limited to the available amounts, except in the case of Fraud or in respect of the Fundamental Representations or the Tax Representations, and none of Purchaser, its Affiliates nor any other Person shall be entitled to collect any remaining amounts not satisfied from the Representation and Warranty Insurance Policy from any Seller nor any other Seller Party, and no such Person shall have any liability for such deficiency or shortfall.

Section 11.5Indemnification by Each Seller

Subject to the terms, conditions, and limitations of this Article 11, from and after the Closing, Sellers are responsible for, shall pay on a current basis and hereby jointly and severally indemnify, defend and hold harmless Purchaser and its Affiliates, and its and their respective directors, officers, employees, members, agents, consultants, advisors and other Representatives (including legal counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (collectively, the “Purchaser Indemnified Persons”), from and against any and all losses asserted against, resulting from, imposed upon, or incurred or suffered by any Purchaser Indemnified Person, directly or indirectly, to the extent resulting from, arising out of or relating to:

(a)any certificate furnished by or on behalf of a Seller in connection with this Agreement, REGARDLESS OF FAULT;

(b)any breach or nonfulfillment of or failure to perform any covenant or agreement of a Seller contained in this Agreement or in any certificate furnished by or on behalf of a Seller in connection with this Agreement, REGARDLESS OF FAULT;

(c)the Excluded Seller Obligations, REGARDLESS OF FAULT;

(d)all Taxes related to the Assets (including, but not limited to ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom) attributable to any period of time prior to the Effective Time;

(e)the matters listed under Schedule 5.7 and Schedule 5.8 (and any related Proceedings), and any other assessment made or to be made by the Texas Comptroller of Public Accounts, to the extent Claims, Losses, and/or Taxes (including any associated interest, penalties, additions to Tax, fees and costs that are allocable to the Assets for events that arise before the Effective Time, and, with respect to any Straddle Period, the portion allocable to the pre-Effective Time under Section 1.4 and Section 7.8; and

(f)any Seller’s breach of the Fundamental Representations or Tax Representations.

Section 11.6Indemnification by Purchaser**.**

From and after the Closing, subject to the terms and conditions of this Article 11, Purchaser shall indemnify, defend and hold harmless each Seller, its Affiliates and its and their directors, officers, employees, agents, consultants, advisors and other representatives (including legal

counsel, accountants and financial advisors) and the successors and permitted assigns of each of the foregoing (collectively, the "Seller Indemnified Persons"), from and against any and all Losses, asserted against, resulting from, imposed upon, or incurred or suffered by any Seller Indemnified Person, directly or indirectly, to the extent resulting from, arising out of, or relating to:

(a)any breach of any representation or warranty of Purchaser contained in this Agreement or in any certificate furnished by or on behalf of Purchaser to Sellers in connection with this Agreement, REGARDLESS OF FAULT;

(b)any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement or any certificate furnished by or on behalf of Purchaser to Sellers in connection with this Agreement, REGARDLESS OF FAULT;

(c)the ownership, use and operation of the Assets from and after the Closing Date, REGARDLESS OF FAULT;

(d)the Assumed Seller Obligations, REGARDLESS OF FAULT;

(e)the indemnity obligations set forth in Section 4.4, REGARDLESS OF FAULT; and

(f)Environmental Laws, Environmental Defects, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment, or any other environmental condition of the Assets, REGARDLESS OF THE TIME OF OCCURRENCE AND REGARDLESS OF FAULT**.**

Section 11.7Indemnification Proceedings.

(a)In the event that any claim or demand for which Sellers or Purchaser (in each case, as applicable, an "Indemnifying Party") may be liable to a Purchaser Indemnified Person under Section 11.5 or to a Seller Indemnified Person under Section 11.6 (as applicable, an "Indemnified Party") is asserted against or sought to be collected from an Indemnified Party by an un-Affiliated third party (a "Third Party Claim"), the Indemnified Party shall with reasonable promptness after the Indemnified Party has Actual Knowledge of the Third Party Claim notify the Indemnifying Party of such Third Party Claim by delivery of a written notice (“Claim Notice”) and a copy of all papers (if any) served with respect to such Third Party Claim, provided that, except as otherwise expressly provided in this Article 11, the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11, except to the extent that the Indemnifying Party demonstrates (to the reasonable satisfaction of the Indemnified Party) that (i) it had insufficient time available to permit such Indemnifying Party to effectively defend against the Third Party Claim or (ii) its defense of such Third Party Claim is otherwise materially prejudiced by such failure or delay. In the case of a claim for indemnification based on a Third Party Claim, the Indemnifying Party shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.7, the "Notice Period") to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Party.

(b)Subject to Section 11.7(d), the Indemnifying Party shall have the right to assume the defense of such Third Party Claim (at its sole cost and expense) only if and for so long as the Indemnifying Party (i) notifies the Indemnified Party during the Notice Period that the Indemnifying Party is assuming the defense of such Third Party Claim, (ii) uses counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conducts the defense of such Third Party Claim in an active and diligent manner. If the Indemnifying Party is entitled to, and does, assume the defense of any such Third Party Claim, the Indemnified Party agrees to cooperate in contesting any such Third Party Claim to the extent such cooperation is so requested by the Indemnifying Party, and, further, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however, that notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys' fees of the Indemnified Party if the Indemnified Party's counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to have common counsel for the Indemnifying Party and the Indemnified Party it being understood and agreed, however, that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Third Party Claim.

(c)If the Indemnifying Party elects (and is entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Party without the Indemnified Party's written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld, conditioned or delayed). If the Indemnifying Party elects not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period, otherwise is not entitled to assume such defense or fails to diligently prosecute or settle the Third Party Claim), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Party; provided, however, that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any Indemnifying Party without the prior written consent of such Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed.

(d)Notwithstanding the foregoing, the Indemnifying Party shall not be entitled to control (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party, shall be entitled to have sole control over, the defense or settlement, compromise, admission, or acknowledgment of any Third Party Claim (i) at the reasonable expense of the Indemnifying Party, as to which the Indemnifying Party fails to assume the defense during the Notice Period after the Indemnified Party gives notice thereof to the Indemnifying Party or (ii) at the reasonable expense of the Indemnifying Party, to the extent the Third Party Claim seeks an order, injunction, or other equitable relief against the Indemnified Party which, if successful, could adversely affect the business, condition (financial or other), capitalization, assets,

liabilities, results of operations or prospects of the Indemnified Party. The Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of the Indemnifying Party without the prior written consent of the Indemnifying Party (which consent shall not be unreasonably withheld, conditioned or delayed).

(e)Subject to Section 11.4, in any case in which an Indemnified Party seeks indemnification hereunder and no Third Party Claim is involved, the Indemnified Party shall deliver a Claim Notice to the Indemnifying Party within a reasonably prompt period of time after an officer of such Indemnified Party or its Affiliates has obtained actual knowledge of the Loss giving rise to indemnification hereunder. Except as otherwise expressly provided in this Article 11 (including Section 11.4), the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively mitigate the resulting Losses or otherwise prejudices the Indemnifying Party.

Section 11.8Release.

EXCEPT WITH RESPECT TO (A) POST-CLOSING REMEDIATION AGREED TO PURSUANT TO SECTION 4.3, (B) PURCHASER’S REMEDIES UNDER SECTION 11.4, OR (C) ANY SELLER’S FRAUD, INTENTIONAL MISREPRESENTATION OR WILLFUL MISCONDUCT, PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHETHER NOW EXISTING OR ARISING IN THE FUTURE, CONTINGENT OR OTHERWISE, WHICH PURCHASER MIGHT NOW OR SUBSEQUENTLY MAY HAVE AGAINST THE SELLER INDEMNIFIED PERSONS, RELATING TO OR ARISING OUT OF (1) THE VIOLATION OF ANY ENVIRONMENTAL LAWS WITH RESPECT TO THE ASSETS, (II) ANY ENVIRONMENTAL LIABILITIES WITH RESPECT TO THE ASSETS, (III) ANY ENVIRONMENTAL DEFECTS, (IV) THE RELEASE OF MATERIALS INTO THE ENVIRONMENT WITH RESPECT TO THE ASSETS OR THE PROTECTION OF NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT.

Section 11.9Disclaimers.

(a)EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCE OR DEED, AND EXCEPT IN THE CASE OF ANY SELLER’S FRAUD, INTENTIONAL MISREPRESENTATION OR WILLFUL MISCONDUCT, (I) SELLERS MAKE NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLERS EXPRESSLY DISCLAIM ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT

MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLERS OR ANY OF THEIR RESPECTIVE AFFILIATES).

(b)EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5 OF THIS AGREEMENT, OR IN THE CERTIFICATE OF EACH SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(d), OR IN THE CONVEYANCE OR DEED, AND EXCEPT IN THE CASE OF ANY SELLER’S FRAUD, INTENTIONAL MISREPRESENTATION OR WILLFUL MISCONDUCT, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, EACH SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLERS OR ANY THIRD PARTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, (IX) REDHIBITORY, PATENT OR LATENT DEFECTS, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT PURCHASER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE, OR (X) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)OTHER THAN AS SET FORTH IN SECTION 5.7 OR SECTION 5.9, AND EXCEPT IN THE CASE OF ANY SELLER’S FRAUD, INTENTIONAL MISREPRESENTATION OR WILLFUL MISCONDUCT, SELLERS HAVE NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL

CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

Section 11.10Recording.

As soon as practicable after Closing, Purchaser shall record the Conveyance and Deed in the appropriate counties where the Properties and Fee Lands are located and provide each Seller with copies of all recorded or approved instruments. The Conveyance in the form attached as Exhibit B and the Deed in the form attached as Exhibit C are intended to convey all of the Properties and Fee Lands being conveyed pursuant to this Agreement. Certain Properties or specific portions of the Properties that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyance and also are described and covered under separate assignments made by Sellers to Purchaser on officially approved forms, in sufficient multiple originals to satisfy applicable statutory and regulatory requirements. The interests conveyed by such separate assignments are the same, and not in addition to, the interests conveyed in the Conveyance attached as Exhibit B. Further, such assignments shall be deemed to contain all of the exceptions, reservations, rights, titles, power and privileges set forth herein and in the Conveyance as fully and only to the extent as though they were set forth in each such separate assignment.

Article 12 MISCELLANEOUS

Section 12.1Counterparts.

This Agreement may be executed and delivered (including by facsimile or email transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

Section 12.2Notice.

All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by overnight courier service, by electronic mail, or by registered or certified mail, postage prepaid, as follows:

If to Sellers or Seller Representative:	Battalion Oil Corporation<br><br>820 Gessner, Suite 1100<br><br>Houston, Texas 77024<br><br>Attention: Walter Mayer<br><br>Email: wmayer@battalionoil.com

If to Purchaser:		MCM Energy Partners, LLC<br><br>223 W. Wall St., Ste 400<br><br>Midland, Texas 79701<br><br>Attention: Miles McFerrin and James Rowland<br><br>Email: miles@mcmenergy.com; james@mcmenergy.com
With a copy to (which shall not constitute notice to Purchaser):		Jackson Walker LLP<br><br>1900 Broadway St., Ste. 1200<br><br>San Antonio, Texas 78215<br><br>Attention: Brandon Durrett<br><br>Email: bdurrett@jw.com

Each party may change its address for notice by notice to the other in the manner set forth above. All notices shall be deemed to have been duly given at the time of receipt by the party to which such notice is addressed.

Section 12.3Sales or Use Tax Recording Fees and Similar Taxes and Fees.

The Assets represent 100% of the “operating assets” of an identifiable segment of Sellers’ business as defined in Texas Comptroller Rule 3.291(d) and Seller maintains written records of income and expense solely with respect to the identifiable segment of business in which the Assets are used. None of the Excluded Assets is an “operating asset” of the identifiable segment of Seller’s business represented by the Assets. Purchaser shall bear any real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees (collectively “Transfer Taxes”) incurred and imposed upon, or with respect to, the transactions contemplated by this Agreement. Purchaser will determine the amount of any Transfer Taxes, if any, that are due in connection with the transactions contemplated by this Agreement and Purchaser agrees to pay any such Transfer Taxes to the appropriate Governmental Body.

Section 12.4Transaction Expenses.

Except as otherwise expressly provided in Section 12.3 or elsewhere in this Agreement, (a) all expenses incurred by Sellers in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyance and Deed delivered hereunder and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, all fees and expenses of counsel, accountants and financial advisers employed by Sellers, shall be borne solely and entirely by Sellers, and (b) all such expenses incurred by Purchaser and all other fees and expenses relating to the registration of title to the Assets after Closing shall be borne solely and entirely by Purchaser.

Section 12.5Change of Name.

As promptly as practicable, but in any case within sixty (60) days after the Closing Date, Purchaser shall eliminate the name “Halcón” and any variants thereof from the Assets acquired

pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Sellers or any of their Affiliates.

Section 12.6Replacement of Bonds, Letters of Credit and Guarantees.

The parties understand that none of the Bonds, if any, posted by Sellers or any of their Affiliates with Governmental Bodies and relating to the Assets may be transferable to Purchaser. Except as provided in Section 7.4(c), prior to Closing, Purchaser shall have obtained, or caused to be obtained in the name of Purchaser, replacements for such Bonds, to the extent such replacements are necessary to permit the cancellation of such Bonds posted by Sellers or any of their Affiliates or to consummate the transactions contemplated by this Agreement.

Section 12.7Governing Law and Venue.

THIS AGREEMENT AND THE LEGAL RELATIONS AMONG THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS. JURISDICTION AND VENUE WITH RESPECT TO ANY DISPUTES ARISING HEREUNDER (EXCEPT FOR DISPUTES REQUIRED HEREUNDER TO BE DETERMINED SOLELY BY ARBITRATION OR OTHER ALTERNATIVE DISPUTE RESOLUTION) SHALL BE PROPER ONLY IN MIDLAND COUNTY, TEXAS. EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY DISPUTE.

Section 12.8Captions.

The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

Section 12.9Waivers.

Any failure by any party or parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the party or parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 12.10Assignment.

Subject to the provisions of Section 7.8(c), no party shall assign all or any part of this Agreement, nor shall any party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other party, which shall not be unreasonably withheld, conditioned or delayed. No assignment hereunder by any party shall relieve such party or its guarantor, if any, of

any obligations and responsibilities hereunder. **** This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

Section 12.11Entire Agreement.

The Confidentiality Agreement, this Agreement and the Exhibits and Schedules attached hereto, and the documents to be executed hereunder constitute the entire agreement between the parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

Section 12.12Amendment.

(a)This Agreement may be amended or modified only by an agreement in writing executed by the parties hereto.

(b)No waiver of any right under this Agreement shall be binding unless executed in writing by the party to be bound thereby.

Section 12.13No Third-Party Beneficiaries.

Nothing in this Agreement shall entitle any Person other than Purchaser or Sellers to any claims, remedy or right of any kind, except as to those rights expressly provided herein to the Seller Indemnified Persons and Purchaser Indemnified Persons.

Section 12.14References.

In this Agreement:

(a)References to any gender includes a reference to all other genders;

(b)References to the singular includes the plural, and vice versa;

(c)Reference to any Article or Section means an Article or Section of this Agreement;

(d)Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e)Unless expressly provided to the contrary, “hereunder”, “hereof”, “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement;

(f)“for example,” “include” and “including” mean include or including, as applicable, without limitation; and

(g)Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the Definitions section hereof.

Section 12.15Construction.

Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent party would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability. Each Seller and Purchaser has had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions. In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against either party.

Section 12.16Conspicuousness.

The parties agree that provisions in this Agreement in “bold” and/or “ALL CAPS” type satisfy any requirements of the “express negligence rule” and any other requirements at law or in equity that provisions be conspicuously marked or highlighted.

Section 12.17Severability.

If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any materially adverse manner with respect to either party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 12.18Time of Essence.

Time is of the essence in this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 12.19Limitation on Damages.

Notwithstanding any other provision contained elsewhere in this Agreement to the contrary, except in the case of fraud, intentional misrepresentation or willful misconduct, the parties acknowledge that this Agreement does not authorize one party to sue for or collect from the other party its own punitive damages, or its own special, punitive, exemplary, consequential or indirect damages or loss of profits in connection with this Agreement and the transactions contemplated hereby and each party expressly waives for itself and on behalf of its Affiliates, any and all claims it may have against the other party for its own such damages in connection with this Agreement and the transactions contemplated hereby.

Section 12.20Suspended Funds.

Sellers covenant to deliver to Purchaser, within thirty (30) days after Closing, in Microsoft Excel format, the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of Suspended Funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries. Upon receipt of such information, Purchaser shall administer all such accounts and distribute such Suspended Funds in accordance with all applicable Laws to the proper parties.

Section 12.21Joint and Several Liability.

The representations, warranties and covenants made by (and the obligations of) Sellers in and under this Agreement are joint and several.

Section 12.22Seller Representative.

For purposes of this Agreement, each Seller, without any further action, shall be deemed to have consented to the appointment of HEPI as its representative (in such capacity, the “Seller Representative”), as the attorney-in-fact for and on behalf of such Seller, with respect to the exercise of any decision, right, consent, election or other action that such Seller is required or permitted to make or take under the terms of this Agreement (the “Delegated Matters”) and Purchaser may rely on the decisions of Seller Representative with respect to all Delegated Matters. For the avoidance of doubt, notwithstanding anything to the contrary herein, Sellers will be treated as a single party for purposes of any election, exercise of a right, consent or similar action to be made by Sellers under this Agreement. The parties further acknowledge that Purchaser shall have no responsibility to determine the portion of the Purchase Price or Adjusted Purchase Price to be paid to any Seller and shall be entitled to rely on the Preliminary Settlement Statement and Final Settlement Statement, as well as instructions by the Seller Representative as to the portion of the Purchase Price or Adjusted Purchase Price payable to any Seller hereunder.

[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

IN WITNESS WHEREOF, this Agreement has been signed by each of the parties hereto as of the date first above written.

SELLERS :

HALCÓN ENERGY PROPERTIES, INC.

By: /s/ Matthew B. Steele

Name:Matthew B. Steele

Title:CEO

HALCÓN PERMIAN, LLC

By: /s/ Matthew B. Steele

Name:Matthew B. Steele

Title:CEO

HALC o N OPERATING CO., INC.

By: /s/ Matthew B. Steele

Name:Matthew B. Steele

Title:CEO

HALCÓN FIELD SERVICES, LLC

By: /s/ Matthew B. Steele

Name:Matthew B. Steele

Title:CEO

PURCHASER :

MCM DELAWARE RESOURCES, LLC

By: MCM Permian Holdings II, LLC,

its sole member

By: /s/ Miles C. McPherren

Name:Miles C. McPherren

Title:Manager

Direct Dial:

Exhibit 10.20 PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT dated as of March 10th, 2026 (“Agreement”), is made by and between RoadRunner Resource Holdings, LLC a Texas limited liability company, whose address is 16400 Dallas Parkway, Suite 100, Dallas, TX 75248 (“Seller”), Halcón Energy Properties, Inc., a Delaware corporation, whose address is 820 Gessner, Suite 1100, Houston, Texas 77024 (“Buyer”), and BATTALION OIL CORPORATION, a Delaware corporation (the “Company” and, together with Buyer, the “Buyer Parties”) .

WHEREAS, Seller desires to sell and convey to Buyer, and Buyer desires to purchase and accept, the Properties;

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller, Buyer and the Company agree as follows:

Properties. Subject to the terms and provisions contained herein, Seller agrees to sell and Buyer agrees to purchase, the Properties (as this term is defined in Exhibit A, attached hereto (the “Assignment”)).

Purchase Price. At the Closing, the Company shall issue to Seller 485,000 shares of common stock, $0.0001 par value per share of the Company, free and clear of all Liens (as defined below), except for Permitted Company Securities Liens (as defined below) (the “Purchase Price”).

Seller agrees that, during the period beginning on the date of the issuance of the above referenced shares to Seller and ending on the date that is 60 days from such date, Seller will not, without the prior written consent of the Company, (i) directly or indirectly, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of any shares of the Company including its common stock or any other securities convertible into or exercisable or exchangeable for the Company’s shares of common stock, whether now owned or hereafter acquired by the undersigned or with respect to which the undersigned has or hereafter acquires the power of disposition (collectively, the “Lock-Up Securities”), or exercise any right with respect to the registration of any of the Lock-up Securities, or file or cause to be filed any registration statement in connection therewith, under the Securities Act of 1933, as amended (the “Securities Act”), or publicly announce the intention to do any of the foregoing, or (ii) enter into any swap or any other agreement or any transaction that transfers, in whole or in part, directly or indirectly, the economic consequence of ownership of the Lock-Up Securities, whether any such swap or transaction is to be settled by delivery of the Lock-Up Securities, other common stock or other securities of the Company, in cash or otherwise.

All shares issued to Seller under this Agreement shall be issued pursuant to Section 4(a)(2) of the Securities Act, will be “restricted securities” as defined in Rule 144 thereunder and, other than as set forth in this Agreement (including the next sentence), shall carry no resale registration rights that would require or permit the filing of any registration statement with the Securities and Exchange Commission (the “SEC”) in connection therewith unless the Company in its absolute sole discretion provides its express written consent to Seller. Further, Seller agrees that no such registration right shall be provided or registration statement shall be filed with the SEC during a period in which Buyer deems, in its absolute sole discretion, that such registration rights or the filing with the SEC of any such registration statement would violate or cause any fee, penalty, cost or liability under any of Buyer’s agreements with third parties. In the event that the Company files a registration statement under the Securities Act with the SEC covering shares of its common stock for its own account (other than a registration statement on Form S-4 or Form S-8), the Company will promptly give written notice of such proposed filing to Seller. Upon the written request of Seller delivered within five (5) business days after receipt of such notice, the Company shall include in such registration statement all of Seller’s shares of common stock received as the Purchase Price hereunder. Seller agrees that during the period beginning on the day after the SEC declares any registration statement contemplated by the preceding sentences effective and ending 15 days thereafter, Seller will not sell or take any of the actions described in the second paragraph of this Section 2 above with respect to any shares of common stock or any other securities of the Company and will comply with all of the restrictions set forth in the second paragraph of this Section 2 above until the expiration of such 15 day period. The Company shall bear and pay all expenses incurred in connection with any registration of the shares pursuant to this Section, including all registration, filing and qualification fees, stock exchange listing fees, printing expenses, accounting and legal fees and expenses of the Company and any blue sky fees and expenses, except that Seller shall bear any underwriting discounts, commissions or transfer taxes applicable to the sale of Seller’s shares.

Purchase Price Adjustments. The Purchase Price shall be adjusted by way of a cash payment from one Party to the other as applicable (i) upward by the amount of all out-of-pocket, third-party operating and similar expenses actually paid by Seller that are attributable to the Properties for the period between the Effective Date and Closing, including those billed under applicable operating agreements, and all prepaid expenses; and (ii) downward by the amount of the proceeds received by Seller or accrued and payable to Seller for the period between the Effective Date and Closing that are attributable to the Properties after the Effective Date, net of any royalties, other lease burdens and any production, severance, sales or windfall profit taxes not reimbursed to Seller by the Buyer.

Closing Date; Liability Allocation; Closing. The closing and consummation of the transaction contemplated hereby (“Closing”) shall take place on March 24^th^ or sooner (“Closing Date”), and shall be effective as of 7:00 a.m., where the Properties are located, on March 1, 2026 (“Effective Date”). Buyer shall assume, and be bound by (and shall be entitled to all production, proceeds and benefits with regard to), the oil and gas leases, contracts and other interests constituting the Properties, and Buyer shall be liable with regard to the Properties, insofar and only insofar as any of the above obligations, liabilities or claims are related solely to the ownership and operation of the Properties occurring from and after the Effective Date; and Seller shall retain and remain liable for all obligations, liabilities, claims, lawsuits, and expenses attributable or allocable to the Properties with regard to all periods prior to the Effective Date. At Closing, (i) Seller will convey the Properties to Buyer with special warranty of title, with such special warranty subject to the permitted encumbrances identified on Exhibit “C” (the “Permitted Encumbrances”), by the form of the Assignment attached hereto as Exhibit “B” (the “ABOS”), (ii) Buyer will pay Seller the Purchase Price, as adjusted, for the Properties, (iii) Seller will execute and deliver a non-foreign affidavit, in such form and substance as is reasonably satisfactory to Buyer, and (iv) Seller will also execute and deliver such change of operator forms for any Seller operated Properties, and such letters-in-lieu of transfer orders to purchasers of Seller’s production attributable to the Properties, all in such forms and substance as are reasonably satisfactory to Buyer. At Closing, the Company shall issue to Seller the shares of common stock of the Company constituting the Purchase Price and shall deliver to Seller evidence reasonably satisfactory to Seller of such issuance, including confirmation from the Company’s transfer agent that such shares have been issued to Seller in restricted book-entry form. Promptly after closing the Company shall file a supplemental listing application with the New York Stock Exchange American (the “NYSE”) with respect to the issuance of the shares of common stock of the Company hereunder and shall deliver to Seller evidence that such shares have been approved and authorized for listing on the NYSE subject only to official notice of issuance promptly after receipt of such confirmation from the NYSE. The Closing shall occur through the simultaneous exchange of the deliverables described in this Section 4, and no deliverable shall be deemed delivered until all deliverables have been delivered.
(a)Buyer’s obligation to purchase the Properties and to take the other actions required to be taken by Buyer at the Closing shall be subject to the satisfaction of the following conditions (any of which may be waived in writing by Buyer): (i) all of Seller’s representations and warranties contained herein shall be true and correct, in all material respects; (ii) Seller shall have performed and satisfied all of its covenants set forth herein in all material respects; (iii) no suit, action, or other proceeding instituted by a third party shall be pending before any governmental authority or arbitrator seeking to restrain, prohibit, enjoin, or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement; (iv) no order shall have been entered by any court or governmental agency that restrains or prohibits the transactions contemplated by this Agreement; and (v) all consents and approvals (if any) required from governmental authorities for the consummation of the transactions contemplated by this Agreement shall have been granted (except for consents and approvals of governmental authorities customarily obtained subsequent to transfer of title); and (vi) the board of directors, (including, considered separately, its disinterested directors), approve the purchase of the Properties and the issuance of the Purchase Price shares.

(b)Seller’s obligation to sell the Properties and to take the other actions required to be taken by Seller at the Closing shall be subject to the satisfaction of the following conditions (any of which may be waived in writing by Seller): (i) all of the Buyer Parties’ representations and warranties contained herein shall be true and correct, in all material respects, (ii) each of the Buyer Parties shall have performed and satisfied all of its covenants set forth herein in all material respects; (iii) no suit, action, or other proceeding instituted by a third party shall be pending before any governmental authority or arbitrator seeking to restrain, prohibit, enjoin, or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement; (iv) no order shall have been entered by any court or governmental agency that restrains or prohibits the transactions contemplated by this Agreement; 2

(v) all consents and approvals (if any) required from governmental authorities for the consummation of the transactions contemplated by this Agreement shall have been granted (except for consents and approvals of governmental authorities customarily obtained subsequent to transfer of title).

(c)This Agreement may be terminated by written notice and without liability at any time prior to the Closing: (i) by mutual written consent of Buyer and Seller; (ii) by Buyer if Seller defaults hereunder and fails to cure such default within 10 days after Buyer gives Seller written notice of such default; (iii) by Seller if a Buyer Party defaults hereunder and fails to cure such default within 10 days after Seller gives the Buyer Parties written notice of such default, (iv) by Buyer if any condition under Section 5(a) is not satisfied by the Closing Date; (v) by Seller if any condition under Section 5(b) is not satisfied by the Closing Date, (vi) by Seller at any time prior to the time the Company delivers the Board Approval Certification (as defined below) to Seller pursuant to Section 12(k), or (vii) by Buyer or Seller, if the party invoking is not in default, and if the Closing has not occurred on or before the date that is ninety (90) days from the date of this Agreement as set forth in the opening paragraph hereof. If this Agreement is terminated pursuant to this Section 5(c), all further obligations of the Parties under this Agreement shall terminate; provided, however, that the Parties shall, in any event, remain bound by and continue to be subject to this Section 5(c), and the indemnity provisions of Section 11.

Representations of the Parties. Each party (“Representing Party”) represents and warrants to the other party as of the date hereof, and as of the Closing (all of which representations and warranties shall survive the Closing):

a.Organization; Existence; Authority; Non-Contravention; Valid and Binding. If the Representing Party is not an individual, such Representing Party is duly organized, validly existing and in good standing under the laws of the state of its formation. The Representing Party has the legal power and right to enter into and perform this Agreement and the transactions contemplated hereby. The consummation of the transactions contemplated by this Agreement does not violate or conflict with: (i) any provision of such by-laws, or other document pursuant to which the Representing Party was formed; (ii) any material agreement or instrument to which the Representing Party is a party or by which the Representing Party is bound; or (iii) any judgment, order, ruling or decree applicable to the Representing Party or any law, rule or regulation applicable to the Representing Party. This Agreement and any other document executed by the Representing Party in connection herewith constitutes the legal, valid and binding obligations of the Representing Party, enforceable in accordance with their terms. Notwithstanding anything to the contrary herein, (A) the parties acknowledge that Seller shall in good faith attempt to obtain the consent to assign which is required pursuant to Paragraph 10 of the Lease (as defined in Exhibit A attached hereto) and (B) while the Lease provides that such consent “shall not be unreasonably withheld”, should the Lessor (as defined in the Lease) refuse to consent, Seller’s failure to obtain such consent shall not be a breach of this Section 6(a) or any other term or condition in this Agreement and shall not prevent the consummation of the transactions contemplated herein.

b.No Broker Fees. The Representing Party has incurred no obligation contingent or otherwise, for any broker's, finder's or consultant's fees for which the other party will be liable.

Representations of Seller. Seller represents and warrants as of the Closing:

a.Contracts; No Drilling Commitments; Other. Except for those listed on Schedule 7(a), there are no agreements, contracts, commitments (including, without limitation, any outstanding authorities for expenditure or other capital or expense commitments relating to the Properties), or agreements, whether written or verbal, constituting part of the Properties (collectively, “Contracts”). To Seller’s knowledge, (i) all Contracts, leases, agreements, permits, declarations and/or orders that are part of the Properties (“Basic Documents”) are in effect and constitute binding obligations of the parties thereto, and Seller is not in material breach (and no situation exists which, with the passing of time or giving of notice, would create a material breach) of its obligations under any of the foregoing; (ii) all payments owing under Basic Documents have been and are being made before they are delinquent in all material respects; and (iii) no Basic Document involves an assumption by Buyer or its successors of any pre-Closing liabilities or claims.

b. Tax Partnerships. None of the Properties is subject to, held in, or treated for tax purposes, as being owned by, a tax partnership. 3

c.No Pending Claims; Taxes. There is no pending (or, to the Seller’s knowledge, threatened) suit, action, notice of violation, or proceeding against Seller or any of its affiliates (if any) that has, or will, materially affect the Seller’s ability to consummate the transactions contemplated herein. All expenses relating to the Properties, have been, and are being, paid before they become delinquent, except those disputed in good faith and for which an adequate accounting reserve has been established by Seller. All taxes imposed by any governmental authority with regard to the ownership, operation or production from the Properties have been timely and fully paid.

d.Compliance with Laws. Seller’s ownership and operation of those Properties is, and has been, in conformity in all material respects with all applicable laws, rules, regulations guidelines and orders of all governmental authorities having jurisdiction, relating to the Properties (including without limitation those relating to the protection of the environment, natural resources, and human health and safety).

The representations and warranties under this Section 7 shall survive for a period of twelve (12) months following the Closing Date, at which time they will terminate and be of no further force or effect.

Representations of the Buyer Parties. Each Buyer Party represents and warrants, jointly and severally, to Seller as of the date hereof and as of the Closing (all of which representations and warranties shall survive the Closing):

a.Capitalization.

(i) The Company has, and at the Closing will have, sufficient authorized shares of common stock of the Company, par value $0.0001 (the “Common Stock”), to enable it to issue the shares of Common Stock constituting the Purchase Price at Closing.

(ii)All of the issued and outstanding shares of Common Stock of the Company are duly authorized and validly issued in accordance with the governing documents of the Company and are fully paid and non-assessable (except as otherwise provided under applicable law).

(iii)The Company is not in default or violation (and no event has occurred which, with notice or the lapse of time or both, would constitute a default or violation) of any term, condition or provision of any governing document of the Company in any material respects.

b.Valid Issuance. The shares of Common Stock comprising the Purchase Price, when and if issued pursuant to the terms of this Agreement, will be duly authorized, validly issued, fully paid and non-assessable, will have the rights, preferences and privileges specified in the Company’s governing documents, will be free of any Liens (as defined below), other than Liens and restrictions on transfer (i) arising under any applicable federal and state securities laws, (ii) arising pursuant to or otherwise set forth in this Agreement or the governing documents of the Company or (iii) created or imposed by Seller or its affiliates at or after the Closing (clauses (i) through (iii) collectively, the “Permitted Company Securities Liens”). For purposes herein “Liens” shall mean any lien, mortgage, pledge, charge, collateral assignment, encumbrances, or security interest of any kind (including any agreement to give any of the foregoing, any conditional sale or other title retention agreement) and any option, trust or other preferential arrangement having the practical effect of any of the foregoing.

c.SEC Documents; Financial Statements.

(i)The Company has timely filed or furnished with the SEC all reports, schedules, forms, statements, and other documents (including exhibits and other information incorporated therein) required to be filed or furnished by it under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) since January 1, 2025 (the “Company SEC Documents”). As of their respective filing dates (or, if amended prior to the date hereof, as of the date of such amendment), the Company SEC Documents complied in all material respects with the applicable requirements of the Exchange Act and the rules and regulations promulgated thereunder and did not contain any untrue 4

statement of material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading.

(ii) The consolidated financial statements of the Company included in the Company SEC Documents were prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) applied on a consistent basis during the periods presented (except as may be indicated in the notes thereto or, in the case of unaudited statements, subject to normal year-end adjustments and the absence of notes permitted by applicable SEC rules), and fairly present in all material respects the consolidated financial condition, results of operations, and cash flows of Company and its subsidiaries as of the dates and for the periods indicated therein.

d.No Stockholder Approval. The transactions contemplated hereby, do not require any vote of the equityholders of the Company under applicable law, the rules and regulations of the NYSE (or other national securities exchange on which the Common Stock is then listed) or the governing documents of the Company.

9.Disclaimers and Acknowledgments.

a.EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES EXPRESSLY SET FORTH IN SECTIONS 6 AND 7 AND IN THE ABOS, SELLER MAKES NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, WITH RESPECT TO THE PROPERTIES OR THE TRANSACTIONS CONTEMPLATED HEREBY, AND EACH BUYER PARTY ACKNOWLEDGES THAT IT HAS NOT RELIED ON ANY REPRESENTATION OR WARRANTY OTHER THAN THOSE EXPRESSLY SET FORTH IN SECTIONS 6 AND 7. WITHOUT LIMITING THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY WITH RESPECT TO (I) TITLE TO THE PROPERTIES, (II) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS, (III) ANY ESTIMATES OF RESERVES, VALUE OR FUTURE REVENUES, (IV) THE CONDITION, SUITABILITY OR FITNESS OF THE PROPERTIES FOR ANY PARTICULAR PURPOSE, OR (V) THE ACCURACY OR COMPLETENESS OF ANY INFORMATION PROVIDED OR MADE AVAILABLE TO THE BUYER PARTIES IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY.

b.EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES EXPRESSLY SET FORTH IN SECTIONS 6 AND 7 AND IN THE ABOS, THE PROPERTIES ARE CONVEYED “AS IS, WHERE IS, WITH ALL FAULTS.” SELLER EXPRESSLY DISCLAIMS ALL IMPLIED WARRANTIES, INCLUDING WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE.

c.ABSENT FRAUD, EACH BUYER PARTY AGREES THAT ITS SOLE REMEDIES WITH RESPECT TO THE PROPERTIES AND THE CONVEYANCE OF THE PROPERTIES AS CONTEMPLATED HEREBY SHALL BE FOR BREACH OF THE EXPRESS REPRESENTATIONS, WARRANTIES OR COVENANTS OF SELLER SET FORTH IN THIS AGREEMENT AND IN THE ABOS.

10.Accounting Adjustments. On or before 90 days after Closing (the “Settlement Date”), Buyer and Seller shall (i) review any additional information then available pertaining to the adjustments provided for in Section 3 above, (ii) determine if any additional adjustments (whether to account for matters not considered in making the adjustments at Closing, or to correct errors made in such adjustments) should be made beyond those made at Closing, and (iii) agree upon a final settlement statement setting forth any such additional adjustments by appropriate payments from Seller to Buyer or from Buyer to Seller. In the event that Seller and Buyer cannot agree upon a final settlement statement on or before the Settlement Date, either party may refer the remaining matters in dispute to a nationally-recognized independent accounting firm mutually agreeable to Buyer and Seller (and absent such mutual selection, as appointed by the Houston office of the American Arbitration Association), for review and final determination (the “Agreed Accounting Firm”). Each party shall summarize its position with regard to the remaining matters in dispute in a written document submitted to the Agreed Accounting Firm, together with any other documentation such party may desire to submit. Within fifteen (15) business days after receiving the parties’ respective submissions, the Agreed Accounting Firm shall render in writing a decision choosing Seller’s position or Buyer’s position, whichever is most accurate based on the terms of this Agreement and the materials described above, which decision shall be final, conclusive and binding on the parties and will be enforceable against any of the parties hereto in any court of competent jurisdiction. The Agreed Accounting Firm may not award damages or penalties to any party. The fees of the Agreed Accounting Firm shall be borne and paid one-half by Seller and one-half by Buyer. Each party shall bear its own legal 5

fees and other costs of presenting its case. Within ten (10) business days after the date on a final determination is issued on the disputed matters, the appropriate final payments from Seller to Buyer or from Buyer to Seller, as applicable, shall be made.

Indemnification. Seller shall indemnify each Buyer Party and its affiliates, officers, employees and agents from and against, and will defend and hold them harmless against, any damages, liabilities, costs or expenses (“Losses”) directly or indirectly arising from or related to any breach of any representation, warranty or covenant made by Seller in this Agreement. The Buyer Parties shall indemnify Seller and its affiliates, officers, employees and agents from and against, and will defend and hold them harmless against, any Losses directly or indirectly arising from or related to any breach of any representation, warranty or covenant made by the Buyer Parties in this Agreement. In no event shall either party be liable to indemnify the other for consequential, special, or punitive damages, except to the extent such damages are awarded to a third party. A party that believes it is entitled to indemnification from the other party shall provide the other party with written notice of the indemnification claim as soon as practical, but in no event more than thirty (30) days after the party seeking indemnification reasonably becomes aware of its claim for indemnification. A party’s obligation to indemnify the other party against a breach of representation or warranty shall terminate on the date that is thirty (30) days after the termination date of such representation or warranty, except with regard to any matter for which the other party has previously provided a written indemnification notice to the indemnifying party.

Notwithstanding anything herein to the contrary, other than with respect to a breach of a representation or warranty contained in Section 6 or Section 8 or the breach of a covenant to be performed after Closing (for which the following limitations shall not apply), (a) in no event shall there be any indemnification obligations owed by one party to the other party under this Section 11 unless the total amount of Losses for which such party owes indemnification hereunder exceeds a deductible in an amount equal to Fifty Thousand Dollars ($50,000) (the “Indemnity Deductible”), after which point the indemnification obligation of such party shall be only for the amount of Losses which are in excess of such Indemnity Deductible, and (b) the indemnification obligations owed by one party under this Section 11 shall be capped at the sum of Five Hundred Thousand Dollars ($500,000) (the “Indemnity Cap”), and no party shall be responsible to indemnify the other party against that portion of Losses which, in the aggregate, exceed the Indemnity Cap. For the avoidance of doubt, the foregoing Indemnity Deductible and Indemnity Cap does not apply to the Buyer Parties’ obligation to deliver the Purchase Price at Closing and the Seller’s obligation to transfer the Properties at Closing.

Miscellaneous.

a. Taxes. All sales, use or other taxes (other than taxes on gross income, net income or gross receipts) and duties, levies or other governmental charges (including recording or similar fees and expenses) incurred by or imposed with respect to the property transfers undertaken pursuant to this Agreement shall be shared equally between Buyer and Seller.

b. Further Assurances. After Closing, each party at the request of the other and without additional consideration, shall execute and deliver, or shall otherwise cause to be executed and delivered, from time to time, such further instruments of conveyance or transfer, and do such further acts, as necessary to more fully and effectively convey and deliver the Properties to Buyer. After the Closing, the parties will cooperate to have all proceeds received attributable to the Properties, to be paid to the proper party hereunder and to have all expenditures, including taxes, attributable to the Properties, to be made by the proper party hereunder.

c. Entire Agreement; Amendment; No Assignment; Severability; No Third-Party Beneficiaries. This Agreement, the documents to be executed hereunder, and the exhibits attached hereto constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior agreements, understandings, and discussions, whether oral or written, with respect to the subject matter hereof. No modification, waiver or termination of this Agreement shall be binding unless executed in writing by the parties hereto and specifically referencing this Agreement. This Agreement may not be assigned, in whole or in part, without the prior written consent of the other party; provided, however, that no such consent shall be required for an assignment by any party to any of its affiliates. If any provision of this Agreement is held invalid or unenforceable, the remaining provisions shall remain in full force and effect. Except as set forth in Section 11, nothing in this Agreement is intended to confer any rights or remedies upon any person other than the parties. 6

d. Notices. Any notice, communication, request, instruction or other document required or permitted hereunder shall be given in writing and delivered in person or sent by U.S. Mail postage prepaid, return receipt requested or facsimile, with printed confirmation, to the addresses of Seller, Buyer and the Company set forth below. Any such notice shall be effective only upon receipt.

Buyer:

Halcón Energy Properties, Inc.

820 Gessner Road

Suite 1100

Houston, Texas 77024 Attention: Walter R. Mayer

Company:

Battalion Oil Corporation

820 Gessner Road

Suite 1100

Houston, Texas 77024 Attention: Walter R. Mayer

Seller:

RoadRunner Resource Holdings LLC

16400 Dallas Parkway, Suite 100

Dallas, Texas 75248

Attention: Cameron Rice

with a copy to (which shall not constitute notice):

RoadRunner Resource Holdings LLC

16400 Dallas Parkway, Suite 100

Dallas, Texas 75248

Attention: Doug Smith

Either party may, by written notice so delivered, change its address for notice purposes hereunder.

e. Choice of Law; WAIVER OF JURY TRIAL. Without regard to principles of conflicts of law, this Agreement shall be construed, enforced, and governed by the laws of the state of Texas applicable to contracts made and to be performed entirely within such state and the laws of the United States of America, except that, to the extent that the law of a state in which a portion of the Properties is located (or which is otherwise applicable to a portion of the Properties) governs, the law of such state shall apply as to that portion of the Properties located in (or otherwise subject to the laws of) such state. EACH PARTY HEREBY IRREVOCABLY WAIVES ANY RIGHT TO TRIAL BY JURY IN ANY ACTION ARISING OUT OF OR RELATING TO THIS AGREEMENT.

f. Counterpart Execution. This Agreement may be executed in counterparts, all of which are identical and all of which constitute one and the same instrument. It shall not be necessary for Buyer, the Company and Seller to sign the same counterpart. PDF or other electronic transmission of copies of signatures shall constitute original signatures for all purposes of this Agreement and any enforcement hereof.

g. Limitation on Damages. NOTWITHSTANDING ANYTHING HEREIN TO THE CONTRARY, EXCEPT AS SET FORTH IN SECTION 11, NEITHER PARTY SHALL HAVE ANY LIABILITY IN CONNECTION WITH THIS AGREEMENT, FOR ANY PUNITIVE DAMAGES, NOR SHALL IT HAVE 7

ANY LIABILITY FOR ANY SPECIAL, INDIRECT OR CONSEQUENTIAL DAMAGES SUFFERED BY THE OTHER PARTY; AND ANY DAMAGES THAT MAY BE ASSESSED IN CONNECTION WITH THIS AGREEMENT SHALL, TO THE MAXIMUM EXTENT PERMITTED BY APPLICABLE LAW, BE LIMITED TO THE ACTUAL DAMAGES SUFFERED.

h. Listing Application. The Company shall use its reasonable best efforts to complete all such filings with the NYSE and otherwise use its reasonable best efforts to take all such actions as may be reasonably necessary for the shares of Common Stock issued as the Purchase Price hereunder to be approved for listing on the NYSE from and after the time of Closing, subject to official notice of issuance.

i.Removal of Restrictive Legends. The Company shall cause the removal of the restrictive legends on the shares of Common Stock acquired by Seller pursuant to this Agreement if (i) such shares are sold pursuant to an effective registration statement in accordance with the plan of distribution described therein, (ii) a registration statement covering the resale of such shares is effective under the Securities Act and Seller delivers to the Company a representation and/or “will comply” letter, as applicable, in a form reasonably acceptable to the Company, (iii) such shares may be sold without restriction under Rule 144 under the Securities Act (including the satisfaction of any applicable holding period) or (iv) such shares are otherwise transferred in compliance with applicable securities laws. Seller shall provide such documentation as is reasonably requested by the Company or its transfer agent as may be necessary to evidence that such legend may be removed under applicable securities laws. The Company shall bear all costs and expenses associated with the removal of any such legend.

j.Specific Performance. Damages in the event of breach of this Agreement by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each party, in addition to and without limiting any other remedy or right it may have, will have the right to seek an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such party from pursuing any other rights and remedies at law or in equity which such party may have.

k.Company Board Approval. The Company shall submit this Agreement (and the transactions contemplated herein, including the issuance of Common Stock to Seller hereunder) to its board of directors for approval (including, considered separately, the approval of its disinterested directors) within three (3) days of the date hereof and shall use reasonable best efforts to obtain such approval (such approval, including the separate approval of the Company’s disinterested directors, the “Required Board Approval”). Upon receiving the Required Board Approval, the Company shall provide a written certification to Seller executed by an officer of the Company (the “Board Approval Certification”) certifying that (i) the Required Board Approval has been obtained and (ii) for purposes of this Agreement, Buyer’s closing condition set forth in Section 5(a)(vi) has been satisfied.

[Signature Pages Follow]

IN WITNESS WHEREOF, this Agreement is executed by the parties hereto on the date first set forth above.

SELLER:

ROADRUNNER RESOURCE HOLDINGS LLC

By: /s/ Cameron Rice

Name: Cameron Rice

Title: President

BUYER:

Halcón Energy Properties, Inc.

By: /s/ Matthew B. Steele

Name: Matthew B. Steele

Title: Chief Executive Officer

COMPANY

BATTALION OIL CORPORATION

By: /s/ Matthew B. Steele

Name: Matthew B. Steele

Title: Chief Executive Officer

Exhibits:

Exhibit A – Properties

Exhibit B – Form of Assignment, Bill of Sale and Conveyance

Exhibit C – Permitted Encumbrances

Schedules:

Schedule 7(a) - Contracts and Commitments 9

Exhibit 21.1

Subsidiaries of the Registrant


Subsidiary		State of Incorporation<br>or Organization
Battalion Energy Holdings, LLC.		Delaware
Battalion Oil Management, Inc.		Delaware
Halcón Energy Properties, Inc.		Delaware
Halcón Field Services, LLC		Delaware
Halcón Holdings, LLC		Delaware
Halcón Operating Co., Inc.		Texas
Halcón Permian, LLC		Delaware
Wink Amine Treater Holdings, LLC		Texas

Exhibit 31

CERTIFICATION FOR FORM 10-K

I, Matthew B. Steele, certify that:

1.	I have reviewed this Annual Report on Form 10-K of Battalion Oil Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
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(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
---	---
5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
---	---
on
---	---	---	---
	BATTALION OIL CORPORATION<br><br>
March 23, 2026	By:	/s/ Matthew B. Steele
	Name:	Matthew B. Steele
	Title:	Chief Executive Officer
	(Principal Executive Officer and Principal Financial Officer)

Exhibit 32

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), Matthew B. Steele, Chief Executive Officer of Battalion Oil Corporation, (the “Company”), hereby certifies that, to the best of his knowledge:

(1) The Company’s Annual Report on Form 10-K for the year ended December 31, 2025 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


March 23, 2026	/s/ Matthew B. Steele
	Matthew B. Steele
	Chief Executive Officer
	(Principal Executive Officer and Principal Financial Officer)

This certification accompanies this Form 10-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that Section.

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

2002

Exhibit 99.1

February 27, 2026

Mr. Russell W. Greco

Battalion Oil Corporation

820 Gessner Road, Suite 1100

Houston, Texas 77024

Dear Mr. Greco:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2025, to the Battalion Oil Corporation (Battalion) interest in certain oil and gas properties located in Oklahoma and Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Battalion. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Battalion's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Battalion interest in these properties, as of December 31, 2025, to be:


	Net Reserves			Future Net Revenue (M)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%

Proved Developed Producing	16,709.4	7,469.1	64,322.8	466,452.6	269,399.6
Proved Developed Non-Producing	409.4	146.4	1,165.0	10,832.5	4,506.2
Proved Undeveloped	14,681.4	4,028.6	32,059.8	271,092.2	77,824.4

Total Proved	31,800.2	11,644.0	97,547.7	748,377.5	351,730.3

All values are in US Dollars.

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Gross revenue is Battalion's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Battalion's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2025. For oil and NGL volumes, the average West Texas Intermediate spot price of $66.01 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.387 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $63.48 per barrel of oil, $21.01 per barrel of NGL, and $1.060 per MCF of gas.

Operating costs used in this report are based on operating expense records of Battalion. These costs include the per-well overhead expenses allowed under joint operating agreements; gathering, processing, and transportation fees; and other estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into midstream-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Battalion are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Battalion and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for artificial lift installations, workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Battalion's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Battalion interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Battalion receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Battalion, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in

accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Battalion, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Jose A. Aburto, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2018 and has over 9 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ Richard B. Talley, Jr.

By: ‌

Richard B. Talley, Jr., P.E.

Chairman and Chief Executive Officer

/s/ Jose A. Aburto/s/ Edward C. Roy III

By: By: ‌

Jose A. Aburto, P.E. 146624Edward C. Roy III, P.G. 2364

Vice PresidentVice President

Date Signed: February 27, 2026Date Signed: February 27, 2026

JAA:JAC

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) *Acquisition of properties.*Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)	Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)	Same environment of deposition;
---	---
(iii)	Similar geological structure; and
---	---
(iv)	Same drive mechanism.
---	---

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
---	---

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) *Development costs.*Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)	Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)	Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
---	---

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii)	Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)	Provide improved recovery systems.
---	---

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)	Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)	Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
---	---
(iii)	Dry hole contributions and bottom hole contributions.
---	---
(iv)	Costs of drilling and equipping exploratory wells.
---	---
(v)	Costs of drilling exploratory-type stratigraphic test wells.
---	---

(13) Exploratory well. An exploratory well is 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 gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) 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. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)	Oil and gas producing activities include:

(A)	The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B)	The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
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(C)	The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
---	---
(1)	Lifting the oil and gas to the surface; and
---	---
(2)	Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
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Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D)	Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.	The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.	In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
---	---

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)	Oil and gas producing activities do not include:

(A)	Transporting, refining, or marketing oil and gas;
(B)	Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
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(C)	Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
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(D)	Production of geothermal steam.
---	---

(17) *Possible reserves.*Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
---	---
(iii)	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
---	---
(iv)	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
---	---
(v)	Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
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(vi)	Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
---	---

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii)	Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
---	---
(iv)	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
---	---

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)	Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)	Costs of labor to operate the wells and related equipment and facilities.
(B)	Repairs and maintenance.
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(C)	Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
---	---
(D)	Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
---	---
(E)	Severance taxes.
---	---

(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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 the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)	The area of the reservoir considered as proved includes:

(A)	The area identified by drilling and limited by fluid contacts, if any, and
(B)	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
---	---

(ii)	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
---	---
(iv)	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
---	---

(A)	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B)	The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) *Reserves.*Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

*a.*Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

*b.*Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

*a.*Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

*b.*Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

*c.*Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

*d.*Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

*e.*Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

*f.*Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i)	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
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From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

●The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

●The company's historical record at completing development of comparable long-term projects;

●The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

●The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

●The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves. Definitions - Page 6 of 6