{"url_path":"/sec/useg/10-k/2026/item-14","section_key":"item-14","section_title":"Item 14 Principal Accounting Fees and Services.**","topic":"sec","document":{"doc_type":"10-K","doc_date":"2026-03-13","source_url":"https://www.sec.gov/Archives/edgar/data/101594/0001437749-26-008057-index.html","accession_number":"0001437749-26-008057","cik":"0000101594","ticker":"USEG","issuer_name":"BIG SKY INDUSTRIAL INC.","edgar_url":"https://www.sec.gov/Archives/edgar/data/101594/0001437749-26-008057-index.html","primary_entity_key":"0000101594","primary_entity_name":"US ENERGY CORP"},"word_count":13219,"has_tables":true,"body_markdown":"**Item 14. Principal Accounting Fees and Services.**\n\n \n\nOur independent public accounting firm is Weaver and Tidwell, L.L.P, Houston, Texas, PCAOB ID 410.\n\n \n\nThe information required by this Item will be set forth under the heading “Ratification of Appointment of Independent Auditors” \"Principal Accounting Fees and Services” in the Company’s 2025 Proxy Statement to be filed with the SEC within 120 days after December 31, 2025 and is incorporated herein by reference.\n\n \n\n \n**Page**\n\n[Report of Independent Registered Public Accounting Firm](#report) (Weaver and Tidwell, L.L.P., Houston, Texas, PCAOB ID 410)\n\n[67](#report)\n\n[Consolidated Balance Sheets as of December 31, 2025 and 2024](#bs)\n\n[70](#bs)\n\nFinancial Statements \n\n[Consolidated Statements of Operations for the Years Ended December 31, 2025 and 2024](#ops)\n\n[71](#ops)\n\n[Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2025 and 2024](#se)\n\n[72](#se)\n\n[Consolidated Statements of Cash Flows for the Years Ended December 31, 2025 and 2024](#cf)\n\n[73](#cf)\n\n[Notes to Consolidated Financial Statements](#notes)\n\n[74](#notes)\n\n \n\n \n\n66\n\n[Table of Contents](#toc)\n\n \n\n**Report of Independent Registered Public Accounting Firm**\n\n \n\nTo the Shareholders and Board of Directors of U.S. Energy Corp.\n\n \n\n**Opinion on the Consolidated Financial Statements**\n\n \n\nWe have audited the accompanying consolidated balance sheets of U.S. Energy Corp. and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the years then ended, 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 years then ended, in conformity with accounting principles generally accepted in the United States of America.\n\n \n\n**Basis for Opinion**\n\n \n\nThese financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audit. 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.\n\n \n\nWe 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 entity’s internal control over financial reporting. Accordingly, we express no such opinion.\n\n \n\nOur 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 provides a reasonable basis for our opinion.\n\n \n\n**Critical Audit Matters**\n\n \n\nThe critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.\n\n \n\n \n\n67\n\n[Table of Contents](#toc)\n\n \n\n**Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and natural gas properties**\n\n \n\n \n\nAs described in Note 1 to the financial statements, the Company accounts for its oil and natural gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and natural gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and natural gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.\n\n \n\nThe principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.\n\n \n\n \n\nWe obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.\n\n \n\n \n●\n\nWe evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.\n\n \n\n \n●\n\nTo the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions, to the extent key, as follows:\n\n \no\n\nCompared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;\n\n \no\n\nEvaluated the forecasted operating costs at year-end compared to historical operating costs;\n\n \no\n\nEvaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests;\n\n \no\n\nApplied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.\n\n \n\n/s/ WEAVER AND TIDWELL, L.L.P.\n\n \n\nWe have served as the Company’s auditor since 2023.\n\n \n\nHouston, Texas\n\nMarch 13, 2026\n\n \n\n68\n\n[Table of Contents](#toc)\n\n  \n\n \n\n \n\n \n\n \n\n69\n\n[Table of Contents](#toc)\n\n \n\n \n\n \n\n**U.S. ENERGY CORP. AND SUBSIDIARIES**\n\n**CONSOLIDATED BALANCE SHEETS**\n\n**December 31, 2025 and 2024**\n\n**(in thousands, except share and per share amounts)**\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n**ASSETS**\n   ** **   ** **\n\n**Current assets:**\n   ** **   ** **\n\nCash and equivalents\n $429  $7,723 \n\nOil and natural gas sales receivables\n  454   1,298 \n\nMarketable equity securities\n  146   131 \n\nOther current assets\n  956   572 \n\n         \n\n**Total current assets**\n  1,985   9,724 \n\n         \n\n**Oil and natural gas properties under full cost method:**\n   ** **   ** **\n\nEvaluated properties\n  132,459   142,029 \n\nLess accumulated depreciation, depletion and amortization\n  (117,237)  (112,958)\n\n         \n\n**Net oil and natural gas properties**\n  15,222   29,071 \n\n         \n\n**Unproved industrial gas properties, not subject to amortization**\n  22,479   9,384 \n\n         \n\n**Other assets:**\n   ** **   ** **\n\nProperty and equipment, net\n  318   660 \n\nRight of use asset\n  356   528 \n\nOther assets\n  270   300 \n\n         \n\n**Total other assets**\n  944   1,488 \n\n         \n\n**Total assets**\n $40,630  $49,667 \n\n         \n\n**LIABILITIES AND SHAREHOLDERS’ EQUITY**\n   ** **   ** **\n\n**Current liabilities:**\n   ** **   ** **\n\nAccounts payable and accrued liabilities\n $1,538   5,086 \n\nAccrued compensation and benefits\n  54   850 \n\nRevenue and royalties payable\n  3,921   4,836 \n\nAsset retirement obligations\n  300   1,000 \n\nCurrent lease obligation\n  210   196 \n\n         \n\n**Total current liabilities**\n  6,023   11,968 \n\n         \n\n**Noncurrent liabilities:**\n   ** **   ** **\n\nCredit facility\n  2,500   - \n\nAsset retirement obligations\n  7,706   13,083 \n\nLong-term lease obligation\n  206   415 \n\n         \n\n**Total noncurrent liabilities**\n  10,412   13,498 \n\n         \n\n**Total liabilities**\n  16,435   25,466 \n\n         \n\n**Commitments and contingencies (Note 9)**\n    ** **    ** **\n\n         \n\n**Shareholders’ equity:**\n   ** **   ** **\n\nCommon stock, $0.01 par value; 245,000,000 authorized; 34,405,143 and 27,903,197 shares issued and outstanding as of December 31, 2025 and 2024, respectively\n  345   279 \n\nAdditional paid-in capital\n  235,762   221,460 \n\nAccumulated deficit\n  (211,912)  (197,538)\n\n         \n\n**Total shareholders’ equity**\n  24,195   24,201 \n\n         \n\n**Total liabilities and shareholders’ equity**\n $40,630  $49,667 \n\n \n\n \n\nThe accompanying notes are an integral part of these consolidated financial statements.\n\n \n\n70\n\n[Table of Contents](#toc)\n\n \n\n \n\n**U.S. ENERGY CORP. AND SUBSIDIARIES**\n\n**CONSOLIDATED STATEMENTS OF OPERATIONS**\n\n**FOR THE YEARS ENDED December 31, 2025 and 2024**\n\n**(in thousands, except share and per share amounts)**\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n         \n\n**Revenue:**\n   ** **   ** **\n\nOil\n $6,378  $18,165 \n\nNatural gas and liquids\n  975   2,454 \n\nTotal revenue\n  7,353   20,619 \n\n         \n\n**Operating expenses:**\n   ** **   ** **\n\nLease operating expenses\n  5,174   11,160 \n\nGathering, transportation, and treating\n  59   205 \n\nProduction taxes\n  539   1,213 \n\nDepreciation, depletion, accretion, and amortization\n  3,607   8,254 \n\nImpairment of oil and natural gas properties\n  3,628   11,918 \n\nExploration Expense\n  230   369 \n\nGeneral and administrative expenses\n  8,064   8,197 \n\nLoss on sale of assets\n  411   4,978 \n\nTotal operating expenses\n  21,712   46,294 \n\n         \n\n**Operating loss**\n  (14,359)  (25,675)\n\n         \n\n**Other income (expense):**\n   ** **   ** **\n\nCommodity derivative gain, net\n  -   537 \n\nInterest expense, net\n  (208)  (442)\n\nOther income (expense), net\n  199   (33)\n\nTotal other income (expense)\n  (9)  62 \n\n         \n\n**Net loss before income taxes**\n $**(14,368****)** $**(25,613****)**\n\nIncome tax (expense) benefit\n  (6)  (20)\n\n**Net loss**\n $**(14,374****)** $**(25,633****)**\n\nBasic and diluted weighted average shares outstanding\n  33,820,394   26,720,295 \n\nBasic and diluted loss per share\n $(0.43) $(0.96)\n\n \n\nThe accompanying notes are an integral part of these consolidated financial statements.\n\n \n\n71\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**U.S. ENERGY CORP. AND SUBSIDIARIES**\n\n**CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS**’**EQUITY**\n\n**FOR THE YEARS ENDED December 31, 2025 and 2024**\n\n**(in thousands, except share amounts)**\n\n \n\n  * *** ** * *** **\n**Additional**\n  * *** ** * *** **\n\n \n**Common Stock**\n \n**Paid-in**\n \n**Accumulated**\n  * *** **\n\n \n**Shares**\n \n**Amount**\n \n**Capital**\n \n**Deficit**\n \n**Total**\n \n\n                \n\n                \n\nBalances, December 31, 2023\n 25,333,870  253  218,403  (171,904)$46,752 \n\nShares issued for acquired properties\n 2,600,000  26  2,652  -  2,678 \n\nShares issued to employees and directors\n 710,104  7  (7) -  - \n\nShares withheld to settle tax withholding obligations for restricted stock awards\n (124,177) (1) (131) -  (132)\n\nShare repurchases\n *(616,600*) (6) (724) -  (730)\n\nStock-based compensation\n *-*  -  1,268  -  1,268 \n\nNet loss\n *-*  -  -  (25,633) (25,633)\n\n                \n\nBalances, December 31, 2024\n 27,903,197  279 $221,460 $(197,538)$24,201 \n\nShares issued for acquisition of industrial gas properties\n 1,400,000  14  2,618  -  2,632 \n\nShares issued to employees and directors\n 1,086,015  11  (10) -  1 \n\nShares withheld to settle tax withholding obligations for restricted stock awards\n (245,810) (2) (373) -  (375)\n\nShares sold in underwritten offering, net of offering costs $899,099\n 4,871,400  49  11,828  -  11,877 \n\nShares issued as part of private placement equity raise\n 223,141  2  268  -  270 \n\nShares repurchased\n (197,400) (2) (314) -  (316)\n\nShares repurchased from related party\n (635,400) (6) (1,568) -  (1,574)\n\nStock-based compensation\n *-*  -  1,853  -  1,853 \n\nNet Loss\n *-*  -  -  (14,374) (14,374)\n\n                \n\nBalances, December 31, 2025\n 34,405,143 $345 $235,762 $(211,912)$24,195 \n\n \n\nThe accompanying notes are an integral part of these consolidated financial statements.\n\n \n\n72\n\n[Table of Contents](#toc)\n\n \n\n \n\n**U.S. ENERGY CORP. AND SUBSIDIARIES**\n\n**CONSOLIDATED STATEMENTS OF CASH FLOWS**\n\n**FOR THE YEARS ENDED December 31, 2025 and 2024**\n\n**(in thousands)**\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n         \n\n**Cash flows from operating activities:**\n   ** **   ** **\n\nNet loss\n $(14,374) $(25,633)\n\nAdjustments to reconcile net loss to net cash provided by (used in) operating activities:\n        \n\nDepreciation, depletion, accretion, and amortization\n  3,607   8,254 \n\nImpairment of oil and natural gas properties\n  3,628   11,918 \n\nDeferred income taxes\n  -   (16)\n\nTotal commodity derivatives gains, net\n  -   (537)\n\nCommodity derivative settlements received\n  -   2,381 \n\n(Gains) losses on marketable equity securities\n  (15)  33 \n\nLoss on sale of assets\n  411   4,978 \n\nAmortization of debt issuance costs\n  104   49 \n\nStock-based compensation\n  1,853   1,268 \n\nRight of use asset amortization\n  173   165 \n\nChanges in operating assets and liabilities:\n        \n\nOil and natural gas sales receivable\n  844   1,038 \n\nOther assets\n  198   (89)\n\nAccounts payable and accrued liabilities\n  (1,994)  1,207 \n\nAccrued compensation and benefits\n  (796)  148 \n\nRevenue and royalties payable\n  (485)  (21)\n\nPayments on operating lease liability\n  (196)  (182)\n\nSettlements of asset retirement obligations\n  (96)  (374)\n\n         \n\nNet cash (used in) provided by operating activities\n  (7,138)  4,587 \n\n         \n\n**Cash flows from investing activities:**\n   ** **   ** **\n\nAcquisition of industrial gas properties\n  (2,128)  (2,578)\n\nIndustrial gas properties capital expenditures\n  (9,863)  (3,908)\n\nOil and natural gas capital expenditures\n  (86)  (1,415)\n\nProceeds from sale of oil and natural gas properties, net\n  194   13,541 \n\nSale of real estate and other, net\n  -   128 \n\n         \n\nNet cash (used in) provided by investing activities:\n  (11,882)  5,768 \n\n         \n\n**Cash flows from financing activities:**\n   ** **   ** **\n\nBorrowings on credit facility\n  2,500   2,000 \n\nPayments on credit facility\n  -   (7,000)\n\nPayments on insurance premium finance note\n  -   (62)\n\nDebt and equity financing costs\n  (386)  - \n\nShares withheld to settle tax withholding obligations for restricted stock awards\n  (375)  (133)\n\nRelated party share repurchase\n  (1,574)  - \n\nProceeds from underwritten offering\n  11,877   - \n\nRepurchases of common stock\n  (316)  (788)\n\n         \n\nNet cash provided by (used in) financing activities\n  11,726   (5,983)\n\n         \n\nNet (decrease) increase in cash and equivalents\n  (7,294)  4,372 \n\n         \n\nCash and equivalents, beginning of year\n  7,723   3,351 \n\n         \n\nCash and equivalents, end of year\n $429  $7,723 \n\n \n\nThe accompanying notes are an integral part of these consolidated financial statements. Please see *Note 15- Supplemental Disclosures of Cash Flow Information*\n\n \n\n73\n\n[Table of Contents](#toc)\n\n  \n\n**U.S. ENERGY CORP. AND SUBSIDIARIES**\n\n**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**\n\n \n\n \n\n**1. ORGANIZATION, OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES**\n\n \n\n**Organization and Operations**\n\n \n\nU.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.\n\n \n\n****\n\n**Use of Estimates**\n\n \n\nThe 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.\n\n \n\n*74*\n\n[Table of Contents](#toc)\n\n \n\n****\n\n**Principles of Consolidation**\n\n \n\nThe 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.\n\n \n\n****\n\n**Industry Segment and Geographic Information **\n\n \n\nThe 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.\n\n \n\nIn addition, the Company has commenced development activities related to industrial gas assets. These activities are currently in the development stage and have *not* yet generated revenues. Development activities primarily consist of resource evaluation, permitting, engineering and related capital expenditures.\n\n \n\nThe Company manages its operations as a single reportable segment under ASC *280* 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 do *not* currently constitute a separate operating segment, as discrete operating results are *not* reviewed by the CODM and *no* revenues have been generated.\n\n \n\nThe Company’s principal oil and natural gas properties and operations are located in:\n\n \n\n \n●\n\nThe Rockies region (Montana and Wyoming)\n\n \n●\n\nThe Mid-Continent region (Oklahoma and North and East Texas)\n\n \n●\n\nWest Texas, South Texas, and the Gulf Coast region\n\n \n\nThe 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.\n\n \n\n****\n\n**Cash and Equivalents**\n\n \n\nThe Company considers all highly liquid investments with original maturities of *three* 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, 2025*and *2024*. 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.\n\n \n\n****\n\n**Oil and Natural Gas Receivables**\n\n \n\nThe 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 within *one* 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 within *one* to *three* 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 are *not* 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, 2025*from $100 thousand as of *December 31, 2024. **No* write offs, recoveries, or other adjustments were recorded in *2025* or *2024.* 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.\n\n \n\n****\n\n**Concentration of Credit Risk**\n\n \n\nThe 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 for *10%* or more of the Company’s total oil and natural gas revenue for at least *one* of the periods presented:\n\n \n\n  \n**Year Ended**\n \n\n  \n**December 31,**\n \n\n**Purchaser**\n \n**2025**\n  \n**2024**\n \n\nPurchaser A\n  54%  27%\n\nPurchaser B\n  15%  27%\n\nPurchaser C\n  6%  4%\n\n \n\n**\n\n*75*\n\n[Table of Contents](#toc)\n\n \n\n****\n\n**Marketable Equity Securities**\n\n \n\nMarketable 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.\n\n \n\n****\n\n**Oil and Natural Gas Properties**\n\n \n\nThe 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 does *not* 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.\n\n \n\nUnder 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 at *10%* per annum, from proved reserves, based on average prices per barrel of oil and per Mcf of natural gas at the *first* day of each month in the *12*-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 properties *not* 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 has *one* cost center for which a quarterly Ceiling Test is performed.\n\n \n\n****\n\n**Industrial Gas Properties**\n\n \n\nThe 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.\n\n \n\nThe 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.\n\n \n\n****\n\n**Acquisitions**\n\n \n\nThe 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 is *not* 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.\n\n \n\n****\n\n**Divestitures**\n\n \n\nFor 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 does *not* 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, with *no* 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.\n\n \n\n****\n\n**Property and Equipment**\n\n \n\n \n\n*76*\n\n[Table of Contents](#toc)\n\n \n\nAdministrative assets are carried at cost. Depreciation of administrative assets are provided principally by the straight-line method over estimated useful lives as follows:\n\n \n\n  \n**Years**\n \n\nAdministrative assets:\n    \n\nComputers and software\n  3 \n\nOffice furniture and equipment\n  5 \n\nAutos and trucks\n  5 \n\nOther equipment\n  10 \n\n \n\n****\n\n**Impairment of Long-Lived Assets**\n\n \n\nThe 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.\n\n \n\n****\n\n**Leases**\n\n \n\nThe Company accounts for leases in accordance with Accounting Standards Codification (“ASC”) Topic *842,* Leases, (“Topic *842”*), which requires lessees to recognize operating and finance leases with terms greater than *12* 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.\n\n \n\nCertain assumptions and judgments are made by the Company when evaluating a contract that meets the definition of a lease under Topic *842,* 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 than *one* year.\n\n \n\nA 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.\n\n \n\n****\n\n**Derivative Financial Instruments**\n\n \n\nThe 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 does *not* designate commodity derivative contracts as fair value or cash flow hedges, and therefore the contracts do *not* 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.\n\n \n\n****\n\n**Revenue Recognition**\n\n \n\nThe 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.\n\n \n\nThe Company does *not* disclose the values of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC *606.* 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 is *not* required.\n\n \n\nThe 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.\n\n \n\n**\n\n*77*\n\n[Table of Contents](#toc)\n\n \n\n****\n\n**Asset Retirement Obligations**\n\n \n\nThe 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.\n\n \n\n**Reclassification**\n\n \n\nCertain 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 had *no* impact on total operating expenses, net income, cash flows, or stockholders’ equity.\n\n \n\n****\n\n**Stock-Based Compensation**\n\n \n\nThe 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 are *not* included in common shares outstanding until vesting has occurred.\n\n \n\n****\n\n**Income Taxes**\n\n \n\nThe 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.\n\n \n\nAdditionally, 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 than *not* they will *not* be realized.  As of *December 31, 2025*and *2024*, management did *not* believe it was more likely than *not* 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 the *three*-year period ended *December 31, 2025*.\n\n \n\nThe 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 than *not* 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.\n\n \n\n****\n\n**Income (Loss) Per Share**\n\n \n\nBasic 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.\n\n \n\n**Correction of Immaterial Errors**\n\n \n\nThe Company identified *two* immaterial errors related to the over accrual of commitment fees on its credit facility in *2024* and production taxes in *2024* 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 were *not* material to any previously issued financial statements including previously issued interim financial statements.\n\n \n\nAccordingly, the Company revised the *2024* comparative financial statement amounts presented herein and recorded the cumulative effect of periods prior to *2024* as an adjustment to beginning retained deficit as of *December 31, 2023*.\n\n \n\n****\n\n**Impact of Immaterial Error Corrections**\n\n \n\nThe following table summarizes the impact of the corrections (in thousands):\n\n \n\n  \n**As Previously Reported**\n  \n*Adjustment for*\n  \n*Adjustment for*\n  \n**As Revised**\n \n\n  \n**2024**\n  \n**Production Tax**\n  \n**Commitment Fee**\n  \n**2024**\n \n\nProduction taxes\n $1,276  $(63) $-  $1,213 \n\nTotal operating expense\n  46,357   (63)  -   46,294 \n\nInterest expense, net\n  (530)  -   88   (442)\n\nTotal other income (expense)\n  (26)  -   88   62 \n\nNet loss before income taxes\n  25,764   63   88   25,613 \n\nAccumulated deficit, December 31, 2023\n  (172,134)  318   -   (171,816)\n\nAccumulated deficit, December 31, 2024\n  (197,918)  381   -   (197,538)\n\nAccounts payable and accrued liabilities\n  5,466   (381)  -   5,086 \n\nTotal current liabilities\n  12,348   (381)  -   11,968 \n\n \n\n**\n\n*78*\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**2. ACQUISITIONS AND DIVESTITURES**\n\n \n\n**Acquisition of Industrial Gas Acreage**\n\n \n\nOn *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. \n\n \n\nWe 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.\n\n \n\nConsideration 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 Synergy *18%* 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.\n\n \n\n \n\n  \n**Amount**\n \n\n  \n(in thousands)\n \n\nAmounts incurred as of the closing date:\n    \n\nCash\n $2,000 \n\nValue of 1,400,000 shares issued\n  2,632 \n\nTransaction costs\n  325 \n\nTotal consideration paid\n $4,957 \n\n     \n\nAllocation to acquired assets:\n    \n\nUnproved industrial gas properties\n $4,957 \n\n     \n\n \n\nOn *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 of two 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.\n\n \n\n*79*\n\n[Table of Contents](#toc)\n\n \n\n \n\n**Divestitures**\n\n \n\nDuring the year ended *December 31, 2025*, the Company closed on *two* 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, with no gain or loss recognized in the Consolidated Statement of Operations.\n\n \n\nDuring 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 did *not* 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, with no 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.*\n\n \n\n  \n\n*80*\n\n[Table of Contents](#toc)\n\n   \n\n \n\n**3. REVENUE FROM CONTRACTS WITH CUSTOMERS**\n\n \n\nThe Company disaggregates its share of revenue from the sale of oil, natural gas and natural gas liquids by region as follows:\n\n \n\n  \n**Year Ended**\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\n**Revenue:**\n   ** **   ** **\n\n*Rockies*\n   * *   * *\n\nOil\n $5,099  $7,366 \n\nNatural gas and liquids\n  178   189 \n\nTotal\n  5,277   7,555 \n\n         \n\n*West Texas, South Texas, and Gulf Coast*\n   * *   * *\n\nOil\n  754   5,276 \n\nNatural gas and liquids\n  16   117 \n\nTotal\n  770   5,393 \n\n         \n\n*Mid-Continent*\n   * *   * *\n\nOil\n  525   5,523 \n\nNatural gas and liquids\n  781   2,148 \n\nTotal\n  1,306   7,671 \n\n         \n\nTotal revenue\n $7,353  $20,619 \n\n   \n\n \n\n*81*\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**4. LEASES**\n\n \n\nThe 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, 2025*and *2024*:\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nRight of use asset\n        \n\nOperating lease\n $356  $528 \n\nLease liability\n        \n\nCurrent lease obligation\n  210   196 \n\nLong-term lease obligation\n  206   415 \n\n  $416  $611 \n\n \n\nThe 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, 2025*and *2024*:\n\n \n\n \n**December 31,**\n\n \n**2025**\n\n**2024**\n\n \n(in thousands)\n\nOperating lease cost\n$218$213\n\nShort-term lease cost\n 118 426\n\nTotal lease costs\n$336$639\n\n \n\nThe Houston office operating lease commenced in *May 2022*and is for a term of 67 months. The base rent under the lease escalates $0.50 per square foot each *twelve*-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.\n\n \n\nShort-term lease cost is associated with short-term lease agreements primarily related to compressors and field equipment rentals contracted for *12* months or less.\n\n \n\nThe Company’s office operating lease agreements did *not* 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.\n\n \n\n  \n**As of December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n         \n\nWeighted average lease term (years)\n  1.9   2.9 \n\nWeighted average discount rate\n  4.25%  4.25%\n\n \n\nMaturity of operating lease liabilities with terms of *one* year or more as of *December 31, 2025* are presented in the following table:\n\n \n\n  \n**December 31, 2025**\n \n\n  \n(in thousands)\n \n\n2026\n $224 \n\n2027\n  210 \n\nTotal future lease payments\n $434 \n\nLess: imputed interest\n  (18)\n\nTotal lease liability\n $416 \n\n \n\n \n\n*82*\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**5. OIL AND NATURAL GAS PRODUCING ACTIVITIES**\n\n \n\n**Unevaluated Properties**\n\nAs of *December 31, 2025*and *2024*, the Company had *no* unevaluated oil and natural gas properties.\n\n \n\n**Ceiling Test and Impairment**\n\n \n\nFor the year ended *December 31, 2025*and *2024*, 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.\n\n \n\nThe reserves used in the ceiling test incorporate assumptions regarding pricing and discount rates over which management has *no* 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 per *one 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 per *one 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%.\n\n \n\n \n\n**6. DEBT**\n\n \n\nOn *January 5, 2022,*the Company entered into a four-year credit agreement (“Credit Agreement”) with FirstBank Southwest (“FirstBank”) as administrative agent for *one* 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 a *first* 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 *may*be borrowed, repaid and re-borrowed until *January 5, 2026,*when all outstanding amounts must be repaid.\n\n \n\nOn *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, 2026*to *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.*During *2025,* 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.\n\n \n\nUnder the Credit Agreement, revolving loans *may*be 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%.\n\n \n\nInterest 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, 2025*and *2024* are presented in the following table:\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nInterest charges\n $26  $309 \n\nWeighted average interest rate\n  7.8%  9.2%\n\n \n\nThe 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 as *no* 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.\n\n \n\n \n\n \n\n*83*\n\n[Table of Contents](#toc)\n\n \n\n \n\n**7. COMMODITY DERIVATIVES**\n\n \n\nThe 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 *may*enter into commodity derivative contracts to protect against price declines in future periods. The Company does *not* enter into derivative contracts for speculative purposes. The Company does *not* 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.\n\n \n\nThere were no derivative contracts outstanding as of *December 31, 2025*and *2024*.  During *2024*, the Company settled all of its outstanding commodity derivative contracts for *2024* and *2025* production, receiving $1.8 million in settlement proceeds.   \n\n \n\n*84*\n\n[Table of Contents](#toc)\n\n \n\nAll 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.\n\n \n\nThe 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:\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nCommodity derivative settlement gains (losses):\n        \n\nOil contracts\n $-  $2,381 \n\n         \n\nTotal derivative settlement gains (losses)\n $-  $2,381 \n\n         \n\nTotal net commodity derivative gains (losses):\n        \n\nOil contracts\n $-  $537 \n\n         \n\nTotal net commodity derivative gains (losses)\n $-  $537 \n\n \n\n*85*\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**8. ASSET RETIREMENT OBLIGATIONS**\n\n \n\nThe 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 had no 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.\n\n \n\nIn 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.\n\n \n\nThe following is a reconciliation of the changes in the Company’s liabilities for asset retirement obligations for the years ended *December 31, 2025*and *2024*:\n\n \n\n  \n**Year Ended December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nBalance, beginning of year\n $14,083  $18,490 \n\nAcquired\n  26   2 \n\nCost and life revisions\n  (1,304)  (150)\n\nSettlements\n  (232)  (374)\n\nLiabilities related to disposition\n  (5,571)  (5,435)\n\nAccretion\n  1,004   1,550 \n\nBalance, end of year\n $8,006  $14,083 \n\n         \n\nAsset retirement obligations - current\n $300  $1,000 \n\nAsset retirement obligations - noncurrent\n  7,706   13,083 \n\nBalance, end of year\n $8,006  $14,083 \n\n  \n\n \n\n**9. COMMITMENTS, CONTINGENCIES, AND RELATED PARTY TRANSACTIONS**\n\n \n\n**Contingencies**\n\n \n\nThe 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 are *not* expected to have a material effect on the consolidated results of operations, the financial position, or the cash flows of the Company.\n\n \n\n \n\n**10. SHAREHOLDERS**’**EQUITY**\n\n \n\nAt *December 31, 2025*and *2024*, the Company had 245,000,000 common stock shares authorized. In addition, at *December 31, 2025*and *2024*, the Company had 5,000,000 authorized but unissued shares of preferred stock.\n\n \n\n**Committed Equity** **Facility**\n\n \n\nOn *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 over *24* 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 did not issue any shares under the committed equity facility in *2025.*\n\n \n\n**Equity Issuance**\n\n \n\nOn *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”).\n\n \n\nThe 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.\n\n \n\n**Related Party Share Repurchase**\n\n \n\nOn *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.\n\n \n\nPursuant 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.*\n\n \n\n**Stock Option Plans**\n\n \n\nFrom 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 expire ten years from the grant date.\n\n \n\n*86*\n\n[Table of Contents](#toc)\n\n \n\nFor the years ended *December 31, 2025*and *2024*, there was no compensation expense related to stock options. As of *December 31, 2025*and *2024*, 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, 2025*and *2024*. The remaining term is approximately 1.8 years. The options had de minimis intrinsic values for the periods reported.\n\n \n\n**Restricted Stock**\n\n \n\nThe 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, *may*be 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 are *not* included in common shares outstanding until vesting has occurred.\n\n \n\nThe 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*:\n\n \n\n   * *** ** \n**Weighted-Avg.**\n \n\n   * *** ** \n**Grant Date**\n \n\n   * *** ** \n**Fair Value**\n \n\n  \n**Shares**\n  \n**per Share**\n \n\n         \n\nNon-vested restricted stock at December 31, 2024\n  1,450,695  $1.41 \n\nGranted\n  1,140,000  $2.03 \n\nVested\n  (1,086,015) $1.56 \n\nModifications (accelerated vesting)\n  -  $- \n\nForfeited\n  (76,000) $2.03 \n\nNon-vested restricted stock at December 31, 2025\n  1,428,680  $2.03 \n\n \n\n*87*\n\n[Table of Contents](#toc)\n\n \n\nThe following table presents the stock compensation expense related to restricted stock grants for the years ended *December 31, 2025*and *2024*:\n\n \n\n  \n**Year Ended**\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nStock compensation expense\n $1,853  $1,268 \n\n \n\nTotal compensation cost related to non-vested time-based awards *not* 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 its *2022* Stock Incentive Plan.\n\n \n\n**Share Repurchase Program**\n\n \n\nOn *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.*\n\n \n\nUnder 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 will *not* be held in treasury or reissued.\n\n \n\nThe following table presents the activity for the share repurchase program for the years ended *December 31, 2025*and *2024*:\n\n \n\n \n\n  **Year Ended December 31,** \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands except per share amounts)\n \n\nShares repurchased\n  197   617 \n\nWeighted average price per share\n $1.604  $1.183 \n\nValue of shares repurchased\n $316  $730 \n\n \n\nUnder 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 will *not* be held in treasury or reissued.\n\n \n\n \n\n**11. INCOME TAXES**\n\n \n\n**Adoption of ASU 2023-09**\n\n \n\nThe Company adopted Accounting Standards Update (ASU) *2023*-*09,* Income Taxes (Topic *740*): Improvements to Income Tax Disclosures, effective *January 1, 2025.*The amendments expand the Company’s income tax disclosure requirements but do *not* impact its consolidated financial position, results of operations, or cash flows.\n\n \n\n**Components of Income Tax Expense**\n\n \n\nThe components of the income tax provision for the years ended *December 31, 2025*and *2024* are as follows:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nCurrent:\n        \n\nFederal\n $-  $- \n\nState\n  6   36 \n\nTotal current income tax\n $6  $36 \n\n         \n\nDeferred:\n        \n\nFederal\n $-  $456 \n\nState\n  -   (472)\n\nTotal deferred income taxes\n $-  $(16)\n\n         \n\nTotal income tax expense (benefit)\n $6  $20 \n\n \n\n*88*\n\n[Table of Contents](#toc)\n\n \n\n**Rate Reconciliation**\n\n \n\nThe following table presents a reconciliation of the U.S. federal statutory income tax rate to the Company’s effective income tax rate for the years ended *December 31, 2025*and *2024* ($ in thousands):\n\n \n\n  \n**2025**\n  * *% \n**2024**\n  * *%\n\n**Reconciling Item**\n               \n\nPretax income (loss)\n  (14,368)  0.0% $(25,613)  0.0%\n\nTax at U.S. federal statutory rate (21%)\n  (3,032)  21.0%  (5,410)  21.0%\n\nState income taxes, net of federal benefit\n  5   1.7%  (444)  1.6%\n\nTax credits\n  -   0.0%  -   0.0%\n\nForeign tax effects\n  -   0.0%  -   0.0%\n\nEffects of tax law changes\n  -   0.0%  -   0.0%\n\nNondeductible expenses\n  93   0.6%  155   0.7%\n\nChanges in valuation allowance\n  2,911   22.1%  5,705   20.1%\n\nChanges in unrecognized tax benefits\n  -   0.0%  -   0.0%\n\nOther, net\n  28   0.0%  13   -0.9%\n\n                 \n\n**Income tax expense (benefit)**\n $6   0.1% $20   -2.7%\n\n \n\nThe 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 does *not* have foreign operations, tax credit activity, or uncertain tax positions that materially impact the effective tax rate.\n\n \n\n**Deferred Tax Assets and Liabilities**\n \n\nThe components of deferred tax assets and liabilities as of *December 31, 2025*and *2024* are as follows:\n\n \n\n \n**2025**\n \n**2024**\n \n\n \n(in thousands)\n \n\nDeferred tax assets:\n      \n\nNet operating loss carryover\n$13,613 $9,787 \n\nProperty and equipment\n 7,808  6,781 \n\nPercentage depletion and contribution carryovers\n 2,007  1,988 \n\nDeferred compensation liability\n 9  188 \n\nAsset retirement obligations\n 1,843  3,215 \n\nStock-based compensation\n 408  379 \n\nLease obligations\n 94  138 \n\nOther\n 218  220 \n\n       \n\nTotal deferred tax assets\n 26,000  22,695 \n\n       \n\nDeferred tax liabilities:\n      \n\nLease assets\n (81) (119)\n\n       \n\nTotal deferred tax liabilities\n (81) (119)\n\n       \n\nNet deferred tax assets\n 25,919  22,576 \n\nLess valuation allowance\n (25,919) (22,576)\n\n       \n\nNet deferred tax liability\n$- $- \n\n \n\n**Cash Taxes Paid**\n\n \n\nCash paid for income taxes was as follows for the years ended *December 31, 2025*and *2024* (in thousands):\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nJurisdiction:\n        \n\nFederal\n  -   - \n\nState\n  -   17 \n\nForeign\n  -   - \n\n         \n\nTotal Cash Taxes Paid\n $-  $17 \n\n \n\nThe Company has *no* foreign operations.\n\n \n\n*89*\n\n[Table of Contents](#toc)\n\n \n\n**Other Disclosures** \n\n \n\nAs 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, 2022*are subject to an Internal Revenue Code (IRC) Section *382* limitations due to a change of control on that date.\n\n \n\nThe Company also has approximately $10.6 million of realized built-in loss (\"RBIL\") carryovers that carry forward indefinitely subject to annual limitations.\n\n \n\nThe Company recognizes, measures, and discloses uncertain tax positions under the “more-likely-than-*not”* threshold. The Company has no uncertain tax positions. \n\n \n\nThe Company files income tax returns in U.S. federal and multiple state jurisdictions. It is generally *not* subject to federal tax examinations for years prior to 2021 and remains open for various state tax examinations for tax years 2020 and later.\n\n \n\n \n\n**12. INCOME (LOSS) PER SHARE**\n\n \n\nBasic 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, 2025*and *2024*, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of dilutive net loss per common share.\n\n \n\nThe following table sets forth the calculation of basic and diluted net income (loss) per share for the years ended *December 31, 2025*and *2024*:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands except per share data)\n \n\nNet income (loss) attributable to common shareholders\n $(14,374) $(25,633)\n\n         \n\nBasic weighted-average common shares outstanding\n  33,820   26,720 \n\nDilutive effect of potentially dilutive securities\n  -   - \n\nDiluted weighted-average common shares outstanding\n  33,820   26,720 \n\n         \n\nBasic net loss per share\n $(0.43) $(0.96)\n\nDiluted net loss per share\n $(0.43) $(0.96)\n\n \n\n*90*\n\n[Table of Contents](#toc)\n\n \n\nFor the years ended *December 31, 2025*and *2024*, potentially dilutive securities were excluded from the calculation of weighted average shares because they were anti-dilutive are as follows:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nStock options\n  17   22 \n\nUnvested shares of restricted stock\n  1,429   1,451 \n\n         \n\nTotal\n  1,446   1,473 \n\n \n\n \n\n**13. FAIR VALUE MEASUREMENTS**\n\n \n\nThe 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 (Level *1*) and the lowest priority to unobservable data (Level *3*). 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 *may*affect the valuation of the assets and liabilities and their placement within the hierarchy level. The *three* levels of inputs that *may*be used to measure fair value are defined as:\n\n \n\nLevel *1* - Quoted prices for identical assets and liabilities traded in active markets.\n\n \n\nLevel *2* - Observable inputs other than Level *1* 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.\n\n \n\nLevel *3* - Unobservable inputs supported by little or *no* 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.\n\n \n\nWhile 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:\n\n \n\n*91*\n\n[Table of Contents](#toc)\n\n \n\n \n\n \n\n*92*\n\n[Table of Contents](#toc)\n\n \n\n**Marketable Equity Securities Valuation Methodologies**\n\n \n\nWe 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 Level *1.*\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n         \n\nNumber of shares owned\n  32,282   2,421,180 \n\nQuoted market price\n $5.14173  $0.06256 \n\nShare value\n $165,985  $151,475 \n\nEstimated cost to sell shares\n  (20,000)  (20,000)\n\nFair Value\n $145,985  $131,475 \n\n  \n\n**Credit Facility**\n\n \n\nThe Company’s credit facility approximates fair value because the interest rate is variable and reflective of market rates.\n\n \n\n**Other Financial Instruments**\n\n \n\nThe carrying value of financial instruments included in current assets and current liabilities approximate fair value due to the short-term nature of those instruments.\n\n \n\n**Nonrecurring Fair Value Measurements**\n\n \n\n**Asset Retirement Obligations**\n\n \n\nThe 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 Level *3* 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%. \n\n \n\n*93*\n\n[Table of Contents](#toc)\n\n \n\n \n\n**14. OTHER CURRENT ASSETS AND ACCOUNTS PAYABLE AND ACCRUED LIABILITIES**\n\n \n\n**Other Current Assets**\n\n \n\nThe following table presents the components of other current asset**s**a**s** of the dates indicated:\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nPrepaid expense\n $164  $119 \n\nJoint interest billings receivable, net of allowance of $380 and $100 as of December 31, 2025 and 2024, respectively\n  (31)  378 \n\nIncome tax receivable\n  28   28 \n\nDeferred offering costs\n  776   - \n\nOther\n  19   47 \n\n         \n\nTotal other current assets\n $956  $572 \n\n \n\n**Accounts Payable and Accrued Liabilities**.\n\n \n\nThe following table presents the components of accounts payable and accrued liabilities as of the dates indicated:\n\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nAccounts payable\n $837  $2,197 \n\nOperating expense accruals\n  499   2,417 \n\nInterest payable\n  26   172 \n\nProduction taxes payable\n  95   653 \n\nOther\n  81   27 \n\n         \n\nTotal accounts payable and accrued expenses\n $1,538  $5,466 \n\n \n\n*94*\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**15. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION**\n\n \n\n  \n**Year Ended**\n \n\n  \n**December 31,**\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nCash paid for interest\n $26  $605 \n\n         \n\n**Investing activities:**\n   ** **   ** **\n\nChange in capital expenditure accruals\n  (1,554)  (165)\n\nCommon stock issued for acquisition of properties\n  2,632   2,678 \n\nAsset retirement obligations (acquired, revisions, sold, and plugged wells)\n  (6,985)  (5,957)\n\n**Financing activities:**\n   ** **   ** **\n\nShares issued for underwriter fee\n  270   - \n\nAccrued costs of financing\n  180   - \n\n  \n\n \n\n**16. SUBSEQUENT EVENTS**\n\n \n\n**Committed Equity** **Facility**\n\n \n\nSubsequent 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.\n\n \n\n**Expected Write-Down of Oil and Natural Gas Properties**\n\n \n\nUnder 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 the *first* day of each of the previous *12* 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 at *10* percent per annum. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation.\n\n \n\nWe expect to record a write-down of our oil and natural gas properties in the *first* quarter of *2026* due to lower commodity prices used in the calculation of the ceiling test as higher *first* quarter *2025* commodity prices will be removed from the ceiling test calculation and replaced with what we expect to be lower *first* quarter *2026* 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 the *first* quarter of *2026.*\n\n \n\n \n\n**17. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)**\n\n \n\n**Capitalized Costs Incurred**\n\n \n\nThe capitalized costs incurred in crude oil and natural gas acquisitions, exploration and development activities for the years ended *December 31, 2025*and *2024* are provided in the table below:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nProved property acquisition\n $-  $- \n\nDevelopment (1)\n  -   1,213 \n\nExploration\n  -   - \n\n         \n\nTotal\n $-  $1,213 \n\n \n\n \n(*1*)\n\nIncludes amounts related to estimated asset retirement obligations of $0.0 million and $1.0 million for the years ended *December 31, 2025*and *2024*, respectively.\n\n  \n\n*95*\n\n[Table of Contents](#toc)\n\n \n\n**Net Capitalized Costs**\n\n \n\nThe following table presents the Company’s capitalized costs associated with oil and natural gas producing activities as of *December 31, 2025*and *2024*:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nOil and Natural Gas Properties:\n        \n\nEvaluated properties in full cost pool (1)\n  132,459   142,029 \n\nLess accumulated depletion (2)\n  (117,237)  (112,958)\n\n         \n\nNet capitalized costs\n $15,222  $29,071 \n\n \n\n \n\n \n(*1*)\n\nDepletion expense was $2.3 million ($21.89 per barrels of oil equivalent (BOE) and $6.4 million ($19.64 per BOE) for the years ended *December 31, 2025*and *2024*, respectively.\n\n \n\n**Results of Operations from oil and natural gas producing activities**\n\n \n\nThe following table includes revenues and expenses associated with the Company’s oil and gas producing activities. It does *not* include any allocation of the Company’s interest costs or general corporate overhead and therefore, it is *not* 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, 2025*and *2024*:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nOil and natural gas sales\n $7,353  $20,619 \n\nLease operating expense\n  (5,174)  (11,160)\n\nGathering, treating, and transportation costs\n  (59)  (205)\n\nProduction taxes\n  (539)  (1,213)\n\nDepletion\n  (2,261)  (6,369)\n\nIncome tax (expense) benefit\n  (6)  (20)\n\n         \n\nResults of operations from oil and natural gas producing activities\n $(686) $1,652 \n\n \n\n*96*\n\n[Table of Contents](#toc)\n\n \n\n**Oil and Natural Gas Reserves **\n\n \n\nProved 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 the *12*-month period prior to the effective date of 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. 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.\n\n \n\nProved oil and natural gas reserve quantities at *December 31, 2025*and *2024* 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.\n\n \n\nAs of *December 31, 2025*and *2024*, the Company had *no* proved undeveloped reserves. All proved reserves were proved developed producing.\n\n \n\nThe 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, 2025*and *2024*:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n**Oil**\n  \n**Gas**\n  \n**Oil**\n  \n**Gas**\n \n\n  \n**(bbls)**\n  \n**(mcfe) (1)**\n  \n**(bbls)**\n  \n**(mcfe) (1)**\n \n\n                 \n\n**Total proved reserves:**\n   ** **   ** **   ** **   ** **\n\nReserve quantities, beginning of year\n  1,592,306   2,306,915   3,182,861   10,082,386 \n\nRevisions of previous estimates\n  (120,898)  220,809   (515,318)  (2,546,079)\n\nDiscoveries and extensions\n  -   -   -   - \n\nPurchases of minerals in place\n  -   -   -   - \n\nSale of minerals in place\n  (271,457)  (27,997)  (819,071)  (4,271,067)\n\nProduction\n  (112,797)  (311,729)  (256,166)  (958,325)\n\n                 \n\nReserve quantities, end of year\n  1,087,155   2,187,999   1,592,306   2,306,915 \n\n \n\n \n(*1*)\n\nMcf equivalents (Mcfe) consist of natural gas reserves in mcf plus NGLs converted to mcf using a factor of *6* mcf for each barrel of NGL.\n\n \n\nNotable changes in proved reserves for the years ended *December 31, 2025*and *2024* included the following:\n\n \n\n \n●\n\nDownward oil revisions in *2025* and *2024* primarily represent revisions due to a decrease in SEC pricing, which resulted in shortening the economic lives of certain properties. Upward gas revisions in *2025* primarily represent revisions due to an increase in SEC pricing.\n\n   \n\n ●Sales of minerals in place in *2025* and *2024* represent reserves associated with properties sold during each respective year. Please see *Note 2-Acquisitions and divestitures*.\n\n \n\n*97*\n\n[Table of Contents](#toc)\n\n \n\n**Standardized Measure (Unaudited)**\n\n \n\nThe 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 do *not* 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.\n\n \n\nFuture 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:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n         \n\nOil per Bbl\n $65.34  $75.48 \n\nGas per Mmbtu\n $3.39  $2.13 \n\n \n\nFuture 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.\n\n \n\nThe 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, 2025*and *2024*:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nFuture cash inflows\n $71,278  $117,237 \n\nFuture cash outflows:\n        \n\nProduction costs\n  (35,496) $(63,555)\n\nDevelopment costs\n  (9,988)  (28,142)\n\nIncome taxes\n  -   - \n\n         \n\nFuture net cash flows\n  25,794  $25,540 \n\n10% annual discount factor\n  (9,066)  (1,714)\n\n         \n\nStandardized measure of discounted future net cash flows\n $16,728  $23,826 \n\n \n\n*98*\n\n[Table of Contents](#toc)\n\n  \n\n**Changes in Standardized Measure (Unaudited)**\n\n \n\nThe changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended *December 31, 2025*and *2024* are as follows:\n\n \n\n  \n**2025**\n  \n**2024**\n \n\n  \n(in thousands)\n \n\nStandardized measure, beginning of year\n $23,826  $60,282 \n\nSales of oil and natural gas, net of production costs\n  (1,581)  (7,978)\n\nNet changes in prices and production costs\n  (4,829)  (1,303)\n\nChanges in estimated future development costs\n  3,017   1,788 \n\nSale of minerals in place\n  (3,577)  (23,116)\n\nRevisions in previous quantity estimates\n  (1,089)  (14,188)\n\nPreviously estimated development costs incurred\n  231   374 \n\nNet changes in income taxes\n  -   2,611 \n\nAccretion of discount\n  2,499   6,073 \n\nChanges in timing and other\n  (1,770)  (717)\n\n         \n\nStandardized measure, end of year\n $16,727  $23,826 \n\n \n\n \n\n99\n\n[Table of Contents](#toc)\n\n  \n\n \n\n**PART IV**"}