US ENERGY CORP

1. ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES

Organization and Operations

U.S. Energy Corp. (and its wholly-owned subsidiaries), are referred to as the “Company” in these Notes to Consolidated Financial Statements. The Company is incorporated in the State of Delaware and its principal business activities are focused on the acquisition, exploration and development of industrial gas and oil and natural gas properties in the United States.

Use of Estimates

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and natural gas reserves that are used in the calculation of depreciation, depletion, amortization and impairment of the carrying value of proved oil and natural gas properties, and the cost and timing of future asset retirement obligations. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable. Due to inherent uncertainties, including the future prices of oil and natural gas, these estimates could change in the near term and such changes could be material.

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Principles of Consolidation

The accompanying consolidated financial statements have been prepared in conformity with GAAP and include the accounts of U.S. Energy Corp. and its wholly-owned subsidiaries. U.S. Energy Corp. accounts for its share of oil and natural gas exploration and production activities, and industrial gas activities in which it has a direct working interest, by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the consolidated balance sheets, statements of operations, and statements of cash flows. All inter-company balances and transactions have been eliminated in consolidation.

Industry Segment and Geographic Information

The Company operates primarily in the exploration and production segment of the oil and gas industry, conducting onshore operations within the United States. All current revenues are derived from the production and sale of oil and natural gas.

In addition, the Company has commenced development activities related to industrial gas assets. These activities are currently in the development stage and havenot yet generated revenues. Development activities primarily consist of resource evaluation, permitting, engineering and related capital expenditures.

The Company manages its operations as asingle reportable segment under ASC280 Segment Reporting. The Company’s Chief Executive Officer serves as the Chief Operating Decision Maker (“CODM”) and reviews financial information on a consolidated basis for purposes of allocating resources and assessing performance. While industrial gas development costs and capital expenditures are tracked separately for internal project management purposes, such activities donot currently constitute a separate operating segment, as discrete operating results arenot reviewed by the CODM andno revenues have been generated.

The Company’s principal oil and natural gas properties and operations are located in:

The CODM evaluates performance primarily based on operating income (loss), defined as revenues less lease operating expenses. Other significant items reviewed include total assets, depreciation, depletion and amortization (“DD&A”), general and administrative expense, gain or loss on derivative activity, interest expense and income tax expense (benefit). These amounts are presented in the Consolidated Balance Sheets and Consolidated Statements of Operations.

Cash and Equivalents

The Company considers all highly liquid investments with original maturities ofthree months or less to be cash equivalents. Cash and cash equivalents potentially subject the Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the federal deposit insurance limits as of* December 31, 2025and2024*. The Company maintains its cash and cash equivalents in the form of checking accounts or short-term investments with financial institutions that it believes are creditworthy. The Company's checking accounts are with the same financial institution as its credit facility.

Oil and Natural Gas Receivables

The Company’s oil and natural gas sales receivables consist of receivables from purchasers of the Company’s operated oil, natural gas, and natural gas liquids (“NGLs”) sales. Generally, the Company’s oil, natural gas and NGL sales receivables from operated properties are collected withinone month. The Company also has joint operating agreements as a non-operator of oil and natural gas properties. Generally, receivables, if any, from the joint interest operator are collected withinone tothree months. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses as appropriate given relevant facts and circumstances. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Receivables arenot collateralized. For the year ended* December 31, 2025,the Company recognized $280 thousand of expense related to its joint interest accounts receivable, increasing the allowance for credit losses to $380 thousand as of December 31, 2025from $100 thousand as of December 31, 2024.*No write offs, recoveries, or other adjustments were recorded in2025 or2024. The balance of the oil and natural gas sales receivable reported on the Consolidated Balance Sheets is comprised entirely of receivables associated with sales under contracts with customers.

Concentration of Credit Risk

The Company has exposure to credit risk in the event of nonpayment of oil and natural gas receivables by purchasers of the Company’s share of oil and natural gas production and its operated production. The following table presents the purchasers that accounted for10% or more of the Company’s total oil and natural gas revenue for at leastone of the periods presented:

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Marketable Equity Securities

Marketable equity securities are reported at fair value based on end of period quoted prices adjusted for selling expenses. Changes in fair value are recorded in other income (expense), net on the Consolidated Statements of Operations at the end of each reporting period. Gains or losses from sales of marketable equity securities are recorded in other income (expense), net on the Consolidated Statements of Operations when the sale is completed.

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for its oil and natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities but doesnot include any costs related to production, general corporate overhead or similar activities. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center are subject to depreciation, depletion and amortization (“DD&A”) using the equivalent unit-of-production method, based on total proved oil and natural gas reserves. For consolidated financial statement presentation, DD&A includes accretion expense related to asset retirement obligations. Cost associated with unevaluated properties, if any, are excluded from amounts subject to DD&A.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability, or the cost center ceiling (the “Ceiling Test”). The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at10% per annum, from proved reserves, based on average prices per barrel of oil and per Mcf of natural gas at thefirst day of each month in the12-month period prior to the end of the reporting period; and costs, adjusted for contract provisions and financial derivatives qualifying as accounting hedges and asset retirement obligations, (ii) the cost of unevaluated propertiesnot being amortized, and (iii) the lower of cost or market value of unproved properties included in the cost being amortized, reduced by (iv) the income tax effects related to differences between the book and tax basis of the crude oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability (if any) exceeds the cost center ceiling limitation, a non-cash impairment charge is required in the period in which the impairment occurs. Since all of the Company’s oil and natural gas properties are located within the United States, the Company only hasone cost center for which a quarterly Ceiling Test is performed.

Industrial Gas Properties

The Company capitalizes all costs associated with the acquisition, exploration and development of industrial gas properties. The acquisition of leases, cost of acquiring drilling permits, drilling, development and asset retirement costs are capitalized as exploration and unevaluated properties. When commercially viable quantities of industrial gas reserves are discovered, the associated costs are reclassified to evaluated assets. The Company will periodically assess exploration and unevaluated properties, and upon evaluation, will reclass the properties to evaluated. Any additional costs to develop the properties or to construct infrastructure to produce and process industrial gases, including processing plant construction costs, will also be capitalized as evaluated. Interest expense, if any, is capitalized on qualifying expenditures. Evaluated industrial gas properties are subject to DD&A once production commences utilizing the units of production method. Evaluated industrial gas properties are stated at cost, less accumulated depletion, depreciation and amortization.

The carrying value of the evaluated properties is reviewed for impairment when there are indications that it* may**not* be recoverable due to significant and prolonged declines in prices, significant reductions in estimated resources, changes in the Company’s plans or other significant events that indicate that an impairment* may*exist. If any such indication of impairment exists and the sum of the undiscounted cash flows is less than the carrying value of the evaluated property, the carrying value is reduced to estimated fair value and reported as an impairment charge in the period with a reduction in the associated carrying cost. Individual evaluated properties are grouped for impairment purposes at the lowest level for which there are identifiable cash flows. The fair value of impaired property is typically determined based on the present value of expected future cash flows using discount rates believed to be consistent with market participants. The impairment test incorporates several assumptions involving expectations of future cash flows which can change significantly over time. These assumptions include estimates of future production, future contracted industrial gas prices, estimates of future operating and development costs.

Acquisitions

The Company accounts for acquisitions as business combinations if the acquired assets meet the definition of a business. If substantially all of the fair value of the gross assets acquired are concentrated in a single identifiable asset or a group of similar assets, the acquisition isnot considered a business and is accounted for as an asset acquisition. This determination of whether the gross assets acquired are concentrated in a group of similar assets is based on whether the risks associated with managing and creating outputs from the assets are similar.

Divestitures

For divestitures involving oil and natural gas assets included in the full cost pool, the Company evaluates if a given divestment has a significant impact to either our reserves volumes or the full cost pool unit-of-production depletion rate. If a divestiture has a significant impact to reserves volumes or the full cost pool depletion rate, the Company will consider if recognizing a gain or loss on the transaction is appropriate. If a divestiture doesnot have a significant impact to reserves volumes or the full cost pool depletion rate, the Company records proceeds, net of transaction costs and purchase price adjustments, to the full cost pool, withno gain or loss recognized on the Consolidated Statements of Operations. Relief of any associated asset retirement obligation is also recorded to the full cost pool. Revenues and expenditures are recorded following our standard accounting policies until the divestment closes.

Property and Equipment

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Administrative assets are carried at cost. Depreciation of administrative assets are provided principally by the straight-line method over estimated useful lives as follows:

Impairment of Long-Lived Assets

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amount* may**not* be recoverable. If estimated future cash flows, on an undiscounted basis, are less than the carrying amount of the related asset, an asset impairment charge is recognized, and measured as the amount by which the carrying value exceeds the estimated fair value. Changes in significant assumptions underlying future cash flow estimates* may*have a material effect on the Company’s financial position and results of operations.

Leases

The Company accounts for leases in accordance with Accounting Standards Codification (“ASC”) Topic842, Leases, (“Topic842”), which requires lessees to recognize operating and finance leases with terms greater than12 months on the Consolidated Balance Sheets. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component. Certain leases* may*contain both lease and non-lease components. The Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease.

Certain assumptions and judgments are made by the Company when evaluating a contract that meets the definition of a lease under Topic842, which include those to determine the discount rate and lease term. Unless the discount rate can be determined in the lease agreement, the Company determines the present value of the future lease payments using an estimated incremental borrowing rate at the lease inception. The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a right-of-use (“ROU”) asset and corresponding lease liability. The Company excludes from the Consolidated Balance Sheets leases with terms that are less thanone year.

A ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement excludes certain variable lease payments, such as payments that vary depending on actual usage.

Derivative Financial Instruments

The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to oil price volatility for its expected future oil production. The Company doesnot designate commodity derivative contracts as fair value or cash flow hedges, and therefore the contracts donot qualify for hedge accounting treatment. Changes in fair value of derivative contracts are recorded in the Consolidated Statement of Operations in other income (expense). The fair value of derivative contracts is recorded as either an asset or a liability on the Consolidated Balance Sheet.

Revenue Recognition

The Company derives revenue from the sale of produced oil, natural gas and NGLs. Revenue is recognized at the point in time when custody and title of the product transfers to the purchaser, which* may*differ depending on the applicable contractual terms. Revenue accruals are recorded based on the Company’s share of estimated production and the expected price to be received. The Company uses its knowledge of its properties, contractual arrangements, historical performance, NYMEX differentials, and other factors as the basis of these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received.

The Company doesnot disclose the values of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC606. The exemption applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to the remaining performance obligations isnot required.

The Company reports revenue as its proportionate share of the gross amount received before taking into account transportation costs. Production taxes and gathering, transportation, and treating costs are reported separately on the Consolidated Statements of Operations.

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Asset Retirement Obligations

The Company records the estimated fair value of restoration and reclamation liabilities related to its oil and natural gas and industrial gas properties as of the date that the liability is incurred. The Company reviews the liability each quarter and determines if a change in estimate is required, and accretion of the discounted liability is recorded based on the passage of time. The Company deducts any actual funds expended for restoration and reclamation during the quarter in which it occurs.

Reclassification

Certain prior-year amounts have been reclassified to conform to the current-year presentation. For the year ended* December 31, 2024,the Company reclassified approximately $369 thousand of acquisition costs to exploration expense within Operating expenses. This reclassification hadno* impact on total operating expenses, net income, cash flows, or stockholders’ equity.

Stock-Based Compensation

The Company measures the cost of employee and director services received in exchange for all equity awards granted, including stock options, based on the fair value of the award as of the grant date. The Company's policy is to compute the fair values of any options granted to employees using the Black-Scholes option pricing model unless the fair value is expected to be inconsequential. The Company recognizes the cost of the equity awards over the period during which an employee or director is required to provide services in exchange for the award, usually the vesting period. Forfeitures are recognized as they occur. Unvested shares of restricted stock grants arenot included in common shares outstanding until vesting has occurred.

Income Taxes

The Company recognizes deferred income tax assets and liabilities for the expected future income tax consequences, based on enacted tax laws, of temporary differences between the financial reporting and tax bases of assets, liabilities and carry forwards.

Additionally, the Company recognizes deferred tax assets for the expected future effects of all deductible temporary differences, loss carry forwards, and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance for any tax benefits that, based on current circumstances, are considered more likely thannot they willnot be realized. As of* December 31, 2025and2024*, management didnot believe it was more likely thannot that such a tax benefit would be realized and as such, a valuation allowance has been recorded. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over thethree-year period ended* December 31, 2025*.

The Company assesses its tax positions annually to determine if there are any uncertain tax positions. If an uncertain tax position is identified, the Company recognizes the tax benefit from an uncertain tax position only if it is more likely thannot that the tax position will be sustained on examination by taxing authorities, based on the technical merits of the position. The tax benefits recognized in the consolidated financial statements from such a position are measured based on the largest benefit that is probable of being realized upon ultimate settlement. The amount of unrecognized tax benefits is adjusted as appropriate for changes in facts and circumstances, such as significant amendments to existing tax law, new regulations or interpretations by the taxing authorities, new information obtained during a tax examination, or resolution of an examination.

Income (Loss) Per Share

Basic net income (loss) per share is computed based on the weighted average number of common shares outstanding. Diluted net income (loss) per share is calculated by dividing net income or loss by the diluted weighted average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of in-the-money outstanding stock options, and unvested restricted stock. When there is a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are excluded from the calculation of net income (loss) per share. The treasury stock method is used to measure the dilutive impact of unvested restricted stock and in-the-money stock options.

Correction of Immaterial Errors

The Company identifiedtwo immaterial errors related to the over accrual of commitment fees on its credit facility in2024 and production taxes in2024 and earlier periods. The errors resulted in an overstatement of operating expenses, interest expense and Accumulated Deficit and the understatement of Other income (expense). The Company concluded the errors werenot material to any previously issued financial statements including previously issued interim financial statements.

Accordingly, the Company revised the2024 comparative financial statement amounts presented herein and recorded the cumulative effect of periods prior to2024 as an adjustment to beginning retained deficit as of* December 31, 2023*.

Impact of Immaterial Error Corrections

The following table summarizes the impact of the corrections (in thousands):

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2. ACQUISITIONS AND DIVESTITURES

Acquisition of Industrial Gas Acreage

On* January 7, 2025,*we entered and simultaneously closed the transactions contemplated by, a purchase and sale agreement, with Synergy Offshore LLC (“Synergy”). Synergy is controlled by Mr. Duane H. King, a member of the Board of Directors of the Company, who serves as the Chief Executive Officer and Manager of Synergy, and John A. Weinzierl, the Company’s Chairman, who was then an approximate sixty percent beneficial owner of Synergy.

We acquired approximately 24,000 net operated acres located across the Kevin Dome structure in Toole County, Montana, including all leases, wells, rights and interests in, under or derived from the acquired acreage subject to Synergy retaining an undivided twenty percent (20%) of Synergy’s right title and interest in the property.

Consideration for the transaction consisted of the following: (a) $2.0 million in cash, subject to customary adjustments; (b)1,400,000 shares of the Company’s common stock; (c) a carried working interest whereby the Company agreed to cover and pay for 100% of Synergy’s costs attributable to the Synergy acreage, until the earlier of (i)78 months from the closing date; or (ii) the date the total costs associated therewith total $20 million; (d) our agreement to pay Synergy18% of the cash amounts we actually realize from any law or regulation from our sequestration of carbon oxides or similar substances derived directly from an agreed area of mutual interest including Synergy’s acreage; and (e) our agreement to pay Synergy 18% of any gain we* may*receive in connection with the sale of the future, first, gas processing plant located on Synergy’s acreage. Total consideration was $4.9 million. The transaction was accounted for as an asset acquisition.

On* June 26, 2024,the Company entered into and closed the transactions contemplated by, a purchase and sale agreement with Wavetech Helium ("Wavetech" and the "Purchase Agreement"). Pursuant to the Purchase Agreement, effective June 1, 2024,the Company acquired 82.5% of Wavetech's rights under a farmout agreement for approximately 144,000 net acres located across the Kevin Dome Structure in Toole County, Montana (the "Assigned Rights"). The Assigned Rights vest upon the drilling oftwo wells on the property. As of December 31, 2025,the Company had completed its drilling commitment on the property. In consideration for the Assigned Rights, the Company paid Wavetech $2.0 million in cash and 2.6 million shares of restricted common stock, which were valued at $2.7 million on June 26, 2024.*In addition, prior to the closing of the Purchase Agreement, the Company incurred $0.4 million of transaction costs related to the acquisition of the Assigned Rights. Additionally, the Company agreed to be responsible for 100% of capital costs, including costs related to project exploration, appraisal, development drilling and completion until $20.0 million has been incurred related to Wavetech's 17.5% interest. The Company accounted for the acquisition of the Assigned Rights as an asset acquisition.

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Divestitures

During the year ended* December 31, 2025*, the Company closed ontwo oil and natural gas property divestments, in Wyoming and in West Texas, for total net proceeds of $0.6 million. Relief of the associated asset retirement obligations for the properties divested was $5.6 million. The Company recorded the proceeds, net of transaction costs and final settlement adjustments, along with the associated asset retirement obligations to the full cost pool, withno gain or loss recognized in the Consolidated Statement of Operations.

During the year ended* December 31, 2024*, the Company closed several divestment transactions of its oil and natural gas properties for total net proceeds of $14.0 million before transaction costs of $0.4 million. Relief of the associated asset retirement obligations for the properties divested was $5.4 million. The divestitures included several individual divestitures of wells in Garza, Karnes and Archer County, Texas, Sumner and Pratt County, Kansas, Kay County, Oklahoma and Lea County, New Mexico. The net proceeds from these transactions totaled $7.2 million. These divestitures didnot have a significant impact to reserves volumes or the full cost pool depletion rate. As such, the Company recorded the proceeds, net of transaction costs and purchase price adjustments, to the full cost pool, withno gain or loss recognized in the Consolidated Statement of Operations. In addition, on* December 31, 2024,the Company closed on the sale of properties in Anderson, Henderson and Liberty County, Texas. This divestiture represented 36% of the reserve volumes and 30% of the reserve value at the date of the divestment, and as such, the Company considered this a significant divestiture and recognized a $5.0 million loss on the sale of the properties in the Consolidated Statement of Operations for the year ended December 31, 2024.*

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3. REVENUE FROM CONTRACTS WITH CUSTOMERS

The Company disaggregates its share of revenue from the sale of oil, natural gas and natural gas liquids by region as follows:

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4. LEASES

The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value under the following captions in the Consolidated Balance Sheets as of* December 31, 2025and2024*:

The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments, which are recognized as incurred. Following are the amounts recognized as components of rental expense for the years ended* December 31, 2025and2024*:

The Houston office operating lease commenced in* May 2022and is for a term of 67 months. The base rent under the lease escalates $0.50 per square foot eachtwelve*-month period during the term of the lease. In addition, the Company is responsible for its share of operating expenses and tax expenses as defined in the lease.

Short-term lease cost is associated with short-term lease agreements primarily related to compressors and field equipment rentals contracted for12 months or less.

The Company’s office operating lease agreements didnot contain implicit interest rates that could be readily determined; therefore, the Company used the incremental borrowing rates in effect at the time the Company entered into the leases.

Maturity of operating lease liabilities with terms ofone year or more as of* December 31, 2025* are presented in the following table:

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5. OIL AND NATURAL GAS PRODUCING ACTIVITIES

Unevaluated Properties

As of* December 31, 2025and2024*, the Company hadno unevaluated oil and natural gas properties.

Ceiling Test and Impairment

For the year ended* December 31, 2025and2024*, the Company recorded $3.6 million and $11.9 million, respectively, of ceiling test write-downs of its oil and natural gas properties. The impairment resulted from declines in commodity prices used in the ceiling test calculation and reduced the carrying value of oil and natural gas properties.

The reserves used in the ceiling test incorporate assumptions regarding pricing and discount rates over which management hasno influence in the determination of present value. In the calculation of the ceiling test as of* December 31, 2025*, the Company used $65.34 per barrel for oil and $3.39 perone million British Thermal Units (MMbtu) for natural gas (as further adjusted for property, specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. In the calculation of the ceiling test as of* December 31, 2024*, the Company used $75.48 per barrel for oil and $2.13 perone million British Thermal Units (MMbtu) for natural gas (as further adjusted for property, specific gravity, quality, local markets and distance from markets) to compute the future cash flows of the Company’s producing properties. The discount factor used for both years was 10%.

6. DEBT

On* January 5, 2022,the Company entered into afour-year credit agreement (“Credit Agreement”) with FirstBank Southwest (“FirstBank”) as administrative agent forone* or more lenders (the “Lenders”), which provided for a revolving line of credit with an initial borrowing base of $15 million, and a maximum credit amount of $100 million. Borrowings under the Credit Agreement are collateralized by afirst priority, perfected lien and security interests on substantially all assets of the Company (subject to permitted liens and other customary exceptions). On* July 26, 2022,the Company entered into a letter agreement with FirstBank whereby it increased the borrowing base under the Credit Agreement from $15 million to $20 million. Under the Credit Agreement, revolving loans maybe borrowed, repaid and re-borrowed until January 5, 2026,*when all outstanding amounts must be repaid.

On* September 16, 2025,effective August 1, 2025,the Company entered into a First Amendment to Credit Agreement and Limited Waiver ("Amendment") with FirstBank, as administrative agent for the lenders party thereto, and such lenders. Significant revisions made to the Credit Amendment as a result of the Amendment include extending the maturity date of amounts owed from January 5, 2026to May 31, 2029,lowering the borrowing base from $20 million to $10 million and deferring the next test period for the ratio of total debt to EBITDAX to March 31, 2026.During2025,* the Company expensed $53 thousand of remaining capitalized deferred financing costs associated with the Credit Agreement and capitalized $60 thousand of deferred financing costs attributable to the Amendment.

Under the Credit Agreement, revolving loans* maybe borrowed, repaid and re-borrowed until May 31, 2029,*when all outstanding amounts must be repaid. Interest on the outstanding amounts under the Credit Agreement will accrue at an interest rate equal to the greater of (i) the prime rate in effect on such day, and (ii) the Federal Funds rate in effect on such day (as determined in the Credit Agreement) plus 0.50%, and an applicable margin that ranges between 0.25% to 1.25% depending on utilization of the amount of the borrowing base (the “Applicable Margin”). In addition, there is a fee on the unused borrowing commitment of 0.5%.

Interest charges recognized on the Credit Agreement, excluding debt issuance cost amortization and the fee for the unused commitment, and the weighted average interest rates for the years ended* December 31, 2025and2024* are presented in the following table:

The Credit Agreement contains various restrictive covenants and compliance requirements, which include: (i) maintenance of certain financial ratios, as defined in the Credit Agreement tested quarterly, that limit the Company’s ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require its ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher; (ii) restrictions on making certain payments as defined in the Credit Agreement, including the payment of cash dividends and repurchases of equity interests (subject to certain limited rights to make restricted payments as long asno event of default has occurred, or would result from the restricted payment, certain financial ratios are met and the borrowing availability after giving pro forma effect to any borrowing to be made on the date of the restricted payment is greater than, or equal to,20% of the then existing borrowing base); (iii) limits on the incurrence of additional indebtedness; (iv) a prohibition on the entry into commodity swap contracts exceeding a specified percentage of our expected production; and (v) restrictions on the disposition of assets.

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7. COMMODITY DERIVATIVES

The Company’s results of operations and cash flows are affected by changes in market prices for crude oil and natural gas. To manage a portion of its exposure to price volatility from producing crude oil and natural gas, the Company* mayenter into commodity derivative contracts to protect against price declines in future periods. The Company doesnot* enter into derivative contracts for speculative purposes. The Company doesnot apply hedge accounting. Accordingly, changes in the fair value of the derivative contracts are recorded in the Consolidated Statements of Operations and are included as a non-cash adjustment to net income in the operating activities section in the Consolidated Statement of Cash Flows.

There wereno derivative contracts outstanding as of* December 31, 2025and2024*. During2024, the Company settled all of its outstanding commodity derivative contracts for2024 and2025 production, receiving $1.8 million in settlement proceeds.

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All commodity derivative contracts held by the Company were subject to master netting arrangements with its counterparty. The terms of the Company’s derivative agreements provide for offsetting of amounts payable or receivable between it and the counterparty for contracts that settle on the same date. The Company’s agreements also provide that in the event of an early termination, the counterparty has the right to offset amounts owed or owing under that and any other agreement. The Company’s accounting policy is to offset positions when we have a right of offset or master netting arrangement.

The following table summarizes the components of the commodity derivative settlement gain (loss) as well as the components of the net derivative loss line-item presentation in the accompanying Consolidated Statements of Operations:

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8. ASSET RETIREMENT OBLIGATIONS

The Company has asset retirement obligations (“ARO”) associated with the future plugging and abandonment of industrial gas and oil and natural gas properties. Initially, the fair value of a liability for an ARO is recorded in the period in which the ARO is incurred with a corresponding increase in the carrying amount of the related asset. The liability is accreted to its present value each period and the capitalized cost is depleted over the life of the related asset. For oil and natural gas properties, if the liability is settled for an amount other than the recorded amount, an adjustment to the full-cost pool is recognized. The Company hadno assets that are restricted for the purpose of settling ARO. For industrial gas properties, if the liability is settled for an amount other than the recorded amount, an adjustment to operating expenses in the Consolidated Statement of Operations is recognized.

In the fair value calculation for the ARO there are numerous assumptions and judgments including the ultimate retirement cost, inflation factors, credit-adjusted risk-free discount rates, timing of retirement and changes in legal, regulatory, environmental, and political environments. To the extent future revisions to assumptions and judgments impact the present value of the existing ARO, a corresponding adjustment is made to the oil and natural gas or industrial gas property balance.

The following is a reconciliation of the changes in the Company’s liabilities for asset retirement obligations for the years ended* December 31, 2025and2024*:

9. COMMITMENTS, CONTINGENCIES, AND RELATED PARTY TRANSACTIONS

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims arenot expected to have a material effect on the consolidated results of operations, the financial position, or the cash flows of the Company.

10. SHAREHOLDERS’** EQUITY**

At* December 31, 2025and2024*, the Company had 245,000,000 common stock shares authorized. In addition, at* December 31, 2025and2024*, the Company had 5,000,000 authorized but unissued shares of preferred stock.

Committed Equity Facility

On* October 9, 2025**,the Company entered into a Common Stock Purchase Agreement and related Registration Rights Agreement with Roth Principal Investments, LLC (“Roth Principal”), providing a discretionary equity facility of up to $25.0 million. Beginning December 1, 2025,the Company may**,at its option over24* months from the date the resale registration is declared effective and certain other conditions are met, sell shares of common stock to Roth Principal at a price based on the Nasdaq volume weighted average prices during a specific pricing period, less a 2.5% discount, subject to pricing and ownership limits. The facility is capped at 19.99% of outstanding shares of the Company’s common stock as of the date of the Company’s entry into the Common Stock Purchase Agreement, absent shareholder approval or satisfaction of the Nasdaq pricing exemption and includes a 4.99% beneficial-ownership blocker. As consideration, the Company paid a $25 thousand structuring fee, issued 223,141 shares of common stock as a partial commitment fee (valued at $270,000)(the “Stock Commitment Fee”), agreed to a $180 thousand cash commitment fee, and to reimburse legal fees. Proceeds, if any, are expected to be used for working capital and general corporate purposes. Under the Purchase Agreement, the Company** may**be required to make a cash “make-whole” payment of up to $270,000 (the value of the Stock Commitment Fee”) if, under certain conditions, Roth Principal receives less than $270,000 in total cash proceeds from the resale of such shares before certain specified dates. In such a case, Roth Principal would return to the Company for cancellation any unsold commitment shares. The Company didnot issue any shares under the committed equity facility in2025.

Equity Issuance

On* January 22, 2025,*the Company entered into an underwriting agreement for the offering of 4,871,400 shares of common stock, at a price to the public of $2.65 per share (such offering, the “Offering”).

The sale of 4,871,400 shares of common stock (including the full 635,400 over-allotment option) in connection with the Offering, closed on* January 23, 2025.** The Company generated approximately $11.9 million of net proceeds from the Offering, after deducting the underwriting discounts and commissions and offering costs payable by us, and has used and plans to continue to use such proceeds for the development of its recent acquisition in Montana, general corporate purposes, and working capital, or for other purposes that our board of directors, in their good faith, deems to be in the best interest of the Company. Additionally, management used $1.574 million from the over-allotment option exercise to purchase shares of common stock from Sage Road Capital, LLC (whose co-manager, Joshua L. Batchelor, was a then member of the Board of Directors of the Company) and its affiliates at a price equal to the public offering price of the Offering, less underwriting discounts, which sale took place in January 2025,** *as discussed below.

Related Party Share Repurchase

On* January 27, 2025,the Company entered into a Share Repurchase Agreement with Banner Oil & Gas, LLC (“Banner”), Woodford Petroleum, LLC (“Woodford”), and Sage Road Energy II, LP, (“Sage Road”, and together with Banner and Woodford, the “Selling Stockholders”). In his capacity as co-Managing Partner of Sage Road Capital, LLC, which indirectly controls and manages certain funds which own a majority interest in Banner, Woodford and Sage Road, Joshua L. Batchelor, a then member of the Board of Directors of the Company, may*be deemed to beneficially own the shares of common stock held by the Selling Stockholders.

Pursuant to the Share Repurchase Agreement, the Company, in a private transaction, outside of, and separate from the Company’s previously disclosed share repurchase program, on* January 27, 2025**,repurchased (a)534,020 shares of common stock held by Banner, (b)41,229 shares of common stock held by Woodford, and (c)60,151 shares of common stock held by Sage Road, for an aggregate of $1.574 million or approximately $2.48 per share, which was the net price per share of the 4,871,400 shares of common stock sold in our underwritten public offering which closed on January 23, 2025,less underwriting discounts and commissions, and which represented an 8.2% premium to the closing sales price of the Company's common stock on January 27, 2025.*

Stock Option Plans

From time to time, the Company* may*grant stock options under its incentive plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically expireten years from the grant date.

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For the years ended* December 31, 2025and2024*, there wasno compensation expense related to stock options. As of* December 31, 2025and2024*, all stock options had vested. The had stock options to purchase 16.5 thousand and 22.2 thousand shares of common stock with an average exercise price of $10.00 and $30.48 as of* December 31, 2025and2024*. The remaining term is approximately 1.8 years. The options had de minimis intrinsic values for the periods reported.

Restricted Stock

The Company grants restricted stock under its incentive plan covering shares of common stock to employees and directors of the Company. The restricted stock awards are time-based awards and are amortized ratably over the requisite service period. Restricted stock vests ratably on each anniversary following the grant date provided the grantee is employed on the vesting date. Forfeitures of restricted stock awards are recognized as they occur. Restricted stock granted to employees, when vested,* maybe net settled through the net issuance of shares, reduced by the number of shares required to pay withholding taxes. Non-vested shares of restricted stock arenot* included in common shares outstanding until vesting has occurred.

The following table presents the changes in non-vested, time-based restricted stock awards to all employees and directors for the year ended* December 31, 2025*:

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The following table presents the stock compensation expense related to restricted stock grants for the years ended* December 31, 2025and2024*:

Total compensation cost related to non-vested time-based awardsnot yet recognized in the Company’s Consolidated Statements of Operations as of* December 31, 2025* is $841 thousand. This cost is expected to be recognized over a weighted average period of 1.46 years. As of* December 31, 2025*, the Company had 4,201,742 shares available for issuance under its2022 Stock Incentive Plan.

Share Repurchase Program

On* April 26, 2023,the Board of Directors of the Company authorized and approved a share repurchase program for up to $5.0 million of the outstanding shares of the Company’s common stock. On March 19, 2024,the Board of Directors of the Company authorized and approved an extension of the ongoing share repurchase program for up to $5.0 million of the currently outstanding shares of the Company’s common stock, which was set to expire on June 30, 2025,and was extended until June 30, 2026.*

Under the stock repurchase program, shares are repurchased from time to time in the open market or through negotiated transactions at prevailing market prices, or by other means in accordance with federal securities laws. Repurchases are made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. The repurchase program is funded using the Company’s working capital. The repurchased shares are cancelled and therefore willnot be held in treasury or reissued.

The following table presents the activity for the share repurchase program for the years ended* December 31, 2025and2024*:

Under the stock repurchase program, shares are repurchased from time to time in the open market or through negotiated transactions at prevailing market prices, or by other means in accordance with federal securities laws. Repurchases are made at management’s discretion at prices management considers to be attractive and in the best interests of both the Company and its stockholders, subject to the availability of stock, general market conditions, the trading price of the stock, alternative uses for capital, and the Company’s financial performance. The repurchase program is funded using the Company’s working capital. The repurchased shares are cancelled and therefore willnot be held in treasury or reissued.

11. INCOME TAXES

Adoption of ASU2023-09

The Company adopted Accounting Standards Update (ASU)2023-09, Income Taxes (Topic740): Improvements to Income Tax Disclosures, effective* January 1, 2025.The amendments expand the Company’s income tax disclosure requirements but donot* impact its consolidated financial position, results of operations, or cash flows.

Components of Income Tax Expense

The components of the income tax provision for the years ended* December 31, 2025and2024* are as follows:

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Rate Reconciliation

The following table presents a reconciliation of the U.S. federal statutory income tax rate to the Company’s effective income tax rate for the years ended* December 31, 2025and2024* ($ in thousands):

The Company’s effective tax rate differs from the U.S. federal statutory rate primarily due to changes in valuation allowance, state income taxes, and nondeductible expenses. The Company doesnot have foreign operations, tax credit activity, or uncertain tax positions that materially impact the effective tax rate.

Deferred Tax Assets and Liabilities

The components of deferred tax assets and liabilities as of* December 31, 2025and2024* are as follows:

Cash Taxes Paid

Cash paid for income taxes was as follows for the years ended* December 31, 2025and2024* (in thousands):

The Company hasno foreign operations.

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Other Disclosures

As of* December 31, 2025*, the Company has approximately $28.1 million in net operating loss carryovers for federal income tax purposes. Net operating losses incurred prior to* January 5, 2022are subject to an Internal Revenue Code (IRC) Section382* limitations due to a change of control on that date.

The Company also has approximately $10.6 million of realized built-in loss ("RBIL") carryovers that carry forward indefinitely subject to annual limitations.

The Company recognizes, measures, and discloses uncertain tax positions under the “more-likely-than-not” threshold. The Company hasno uncertain tax positions.

The Company files income tax returns in U.S. federal and multiple state jurisdictions. It is generallynot subject to federal tax examinations for years prior to 2021 and remains open for various state tax examinations for tax years 2020 and later.

12. INCOME (LOSS) PER SHARE

Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing adjusted net income (loss) by the diluted weighted average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of stock options and unvested shares of restricted common stock, which are measured using the treasury stock method. When the Company recognizes a net loss, as was the case for the years ended* December 31, 2025and2024*, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of dilutive net loss per common share.

The following table sets forth the calculation of basic and diluted net income (loss) per share for the years ended* December 31, 2025and2024*:

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For the years ended* December 31, 2025and2024*, potentially dilutive securities were excluded from the calculation of weighted average shares because they were anti-dilutive are as follows:

13. FAIR VALUE MEASUREMENTS

The Company’s fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving highest priority to quoted prices in active markets (Level1) and the lowest priority to unobservable data (Level3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and* mayaffect the valuation of the assets and liabilities and their placement within the hierarchy level. Thethree* levels of inputs that* may*be used to measure fair value are defined as:

Level1 - Quoted prices for identical assets and liabilities traded in active markets.

Level2 - Observable inputs other than Level1 that are directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in active markets, or other observable inputs that can be corroborated by observable market data.

Level3 - Unobservable inputs supported by little orno market activity for financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation.

While the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. The following is a description of the valuation methodologies used for complex financial instruments measured at fair value:

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Marketable Equity Securities Valuation Methodologies

We measure the fair value of marketable equity securities based on quoted market prices obtained from independent pricing services. The Company has an investment in the marketable equity securities of Anfield Energy (“Anfield”), which it acquired as consideration for sales of certain mining operations. Anfield is traded in an active market under the trading symbol AEC:TSXV and has been classified as Level1.

Credit Facility

The Company’s credit facility approximates fair value because the interest rate is variable and reflective of market rates.

Other Financial Instruments

The carrying value of financial instruments included in current assets and current liabilities approximate fair value due to the short-term nature of those instruments.

Nonrecurring Fair Value Measurements

Asset Retirement Obligations

The Company measures the fair value of asset retirement obligations as of the date a well is acquired, the date a well begins drilling, or the date the Company revises its ARO assumptions. The Company’s estimated asset retirement obligation is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment costs and federal and state regulatory requirements, all unobservable inputs, and therefore, are designated as Level3 within the valuation hierarchy. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised upward. The credit adjusted risk-free rate used to discount the Company’s plugging and abandonment liabilities range from 7.30% to 19.00%.

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14. OTHER CURRENT ASSETS AND ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Other Current Assets

The following table presents the components of other current assetsas of the dates indicated:

Accounts Payable and Accrued Liabilities.

The following table presents the components of accounts payable and accrued liabilities as of the dates indicated:

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15. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

16. SUBSEQUENT EVENTS

Committed Equity Facility

Subsequent to* December 31, 2025* and through* March 15, 2026,*the Company has issued 8.5 million shares generating proceeds of $9.3 million after underwriter commissions.

Expected Write-Down of Oil and Natural Gas Properties

Under the full-cost method of accounting, the net book value of proved oil and natural gas properties, less related deferred income taxes,* may**not* exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves. Estimated future net cash flows are calculated using the unweighted arithmetic average of commodity prices in effect on thefirst day of each of the previous12 months, adjusted for location and quality differentials, held flat for the life of the production (except where prices are defined by contractual arrangements), less estimated operating costs, production taxes and future development costs, all discounted at10 percent per annum. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation.

We expect to record a write-down of our oil and natural gas properties in thefirst quarter of2026 due to lower commodity prices used in the calculation of the ceiling test as higherfirst quarter2025 commodity prices will be removed from the ceiling test calculation and replaced with what we expect to be lowerfirst quarter2026 commodity prices. Depending on actual commodity prices, estimated price differentials, lease operating costs, revisions to reserve estimates, and the amount and timing of capital expenditures, the write-down could be approximately $0.5 million to $1.5 million in thefirst quarter of2026.

17. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

Capitalized Costs Incurred

The capitalized costs incurred in crude oil and natural gas acquisitions, exploration and development activities for the years ended* December 31, 2025and2024* are provided in the table below:

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Net Capitalized Costs

The following table presents the Company’s capitalized costs associated with oil and natural gas producing activities as of* December 31, 2025and2024*:

Results of Operations from oil and natural gas producing activities

The following table includes revenues and expenses associated with the Company’s oil and gas producing activities. It doesnot include any allocation of the Company’s interest costs or general corporate overhead and therefore, it isnot necessarily indicative of the contribution to net earnings of the Company’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including DD&A, and giving effect to permanent differences. Presented below are the results of operations from oil and natural gas producing activities for the years ended* December 31, 2025and2024*:

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Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Oil and natural gas prices used are the average price during the12-month period prior to the effective date of the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements. Proved developed reserves are reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and natural gas reserve quantities at* December 31, 2025and2024* and the related discounted future net cash flows before income taxes are based on the estimates prepared by On Point Resources. The estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. All of the Company’s estimated proved reserves are located in the United States.

As of* December 31, 2025and2024*, the Company hadno proved undeveloped reserves. All proved reserves were proved developed producing.

The Company’s estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below for the years ended* December 31, 2025and2024*:

Notable changes in proved reserves for the years ended* December 31, 2025and2024* included the following:

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Standardized Measure (Unaudited)

The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions donot necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure:

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The standardized measure of discounted future net cash flows relating to the Company’s proved oil and natural gas reserves is as follows as of* December 31, 2025and2024*:

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Changes in Standardized Measure (Unaudited)

The changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended* December 31, 2025and2024* are as follows: