{"url_path":"/sec/useg/10-k/2026/item-7","section_key":"item-7","section_title":"Item 7 Management**’**s Discussion and Analysis of Financial Condition and Results of Operations**","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":4638,"has_tables":true,"body_markdown":"**Item 7. Management**’**s Discussion and Analysis of Financial Condition and Results of Operations**\n\n \n\nThis discussion includes forward-looking statements. Please refer to “[Cautionary Statement Regarding Forward-Looking Statements](#caution)” of this annual report on Form 10-K for important information about these types of statements and “[Risk Factors](#item1a)”, above. Additionally, please refer to the “[Glossary of Oil and Natural Gas Terms](#glossary)” of this annual report on Form 10-K for oil and natural gas industry terminology used herein.\n\n \n\n**Summary of The Information Contained in Management**’**s Discussion and Analysis of Financial Condition and Results of Operations**\n\n \n\nOur Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is provided in addition to the accompanying consolidated financial statements and notes to assist readers in understanding our results of operations, financial condition, and cash flows. MD&A is organized as follows:\n\n \n\n \n\n●\n\n**Plan of Operations and Strategy**. Discussion of our strategy moving forward and how we plan to seek to increase stockholder value.\n\n \n \n\n \n\n \n\n●\n\n**Critical Accounting Policies and Estimates**. Accounting estimates that we believe are important to understanding the assumptions and judgments incorporated in our reported financial results and forecasts.\n\n \n \n\n \n\n \n\n●\n\n**Results of Operations**. An analysis of our financial results comparing the years ended December 31, 2025 and 2024.\n\n \n \n\n \n\n \n\n●\n\n**Liquidity and Capital Resources**. A discussion of our financial condition, including descriptions of balance sheet information and cash flows.\n\n \n\n56\n\n[Table of Contents](#toc)\n\n \n\n**Plan of Operations and Strategy**\n\n \n\nIn 2026 and beyond, we intend to seek additional opportunities in the oil, natural gas and industrial gas sectors, including but not limited to further acquisition of assets, participation with industry partners, and the acquisition of existing companies. We also plan to finalize the detailed engineering of our processing facility and related activities necessary to bring the plant online. These activities include but are not limited to acquiring surface acreage, negotiating rights of way and offtake agreements, designing power infrastructure, and raise capital to fully fund development.\n\n \n\n**Business Strategy**\n\n \n\nKey elements of our business strategy include:\n\n \n\n \n\n●\n\n*Deploy our Capital in a Conservative and Strategic Manner and Review Opportunities to Bolster our Liquidity*. In the current industry environment, maintaining liquidity is critical. Therefore, we plan to be highly selective in the projects we evaluate and to review opportunities to bolster our liquidity and financial position through various means.\n\n \n \n\n \n\n \n\n●\n\n*Evaluate and Pursue Value-Enhancing Transactions*. We plan to continuously evaluate strategic alternative opportunities with the goal of enhancing stockholder value.\n\n \n\n**Critical Accounting Policies and Estimates**\n\n \n\nThe preparation of our consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions. A summary of our significant accounting policies is detailed in [Note 1 – Organization, Operations and Significant Accounting Policies](#note1) of our consolidated financial statements. We have outlined below those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.\n\n \n\n*Oil and Natural Gas Reserve Estimates.* Our estimates of proved reserves are based on quantities of oil and natural gas reserves which current engineering data indicates are recoverable from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are critical estimates in determining our depreciation, depletion and amortization expense (“DD&A”) and our full cost ceiling limitation (“Full Cost Ceiling”). Future cash inflows are determined by applying oil and natural gas prices, as adjusted for transportation, quality and basis differentials to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Future production and development costs are based on costs existing at the effective date of the report. Expected cash flows are discounted to present value using a prescribed discount rate of 10% per annum.\n\n \n\nEstimates of proved reserves are inherently imprecise because of uncertainties in projecting rates of production and timing of developmental expenditures, interpretations of geological, geophysical, engineering and production data and the quality and quantity of available data. Changing economic conditions also may affect our estimates of proved reserves due to changes in developmental costs and changes in commodity prices that may impact reservoir economics. We utilize independent reserve engineers to estimate our proved reserves at the end of each fiscal quarter during the year.\n\n \n\n57\n\n[Table of Contents](#toc)\n\n \n\n*Oil and Natural Gas Properties.*We follow the full cost method in accounting for our 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.\n\n \n\nThe sum of net capitalized costs and estimated future development and dismantlement costs for each country-wide cost center are amortized using the equivalent unit-of-production method, based on proved oil and natural gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the DD&A recognized in the period that the reserves are produced. DD&A is calculated by dividing the period’s production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our DD&A per unit. Costs associated with production and general corporate activities are expensed in the period incurred.\n\n \n\nUnder the full cost method of accounting, capitalized oil and natural gas property costs less accumulated DD&A and net of deferred income taxes may not exceed the Full Cost Ceiling. The Full Cost Ceiling is equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the unimpaired cost of unproved properties not subject to amortization, plus the lower of cost or fair value of unproved properties that are subject to amortization. When net capitalized costs exceed the Full Cost Ceiling, an impairment is recognized.\n\n \n\n*Industrial Gas Properties. *The Company capitalizes all costs associated with the acquisition, exploration and development of industrial gas reserves.   The acquisition of leases, cost of acquiring drilling permits, drilling, development and asset retirement costs are capitalized as exploration and unevaluated assets.   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 assets, and upon evaluation, will reclass the assets to evaluated.  Any additional costs to develop the asset 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 assets are subject to depreciation, depletion and amortization once production commences utilizing the units of production method.  Evaluated industrial gas assets are stated at cost, less accumulated depletion, depreciation and amortization.\n\n \n\nThe carrying value of evaluated assets is reviewed for impairment when there are indications that the asset 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 assets 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*Divestitures.  *For divestitures involving oil and gas assets included in the full cost pool, the Company evaluates if a given divestiture 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 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 obligations are also recorded to the full cost pool. Revenue and expenditures are recorded following our standard accounting policies up until the month that a divestment closes.\n\n \n\n*Revenue Recognition.* We recognize revenue in accordance with Financial Accounting Standards Board (\"FASB\") Accounting Standards Codification (\"ASC\") Topic 606-*Revenue from Contracts with Customers. See Note 3- Revenue From Contracts With Customers*to our consolidated financial statements.\n\n \n\n**Recent Accounting Standards**\n\n \n\nPlease refer to the section entitled *Recent Accounting Pronouncements* under [*Note 1*–*Organization, Operations and Significant Accounting Policies*](#note1) to our consolidated financial statements, for additional information on recently issued accounting standards and our plans for adoption of those standards.\n\n \n\n58\n\n[Table of Contents](#toc)\n\n \n\n**Results of Operations**\n\n \n\n**Comparison of our Statements of Operations for the Years Ended December 31, 2025 and 2024**\n\n \n\nDuring the year ended December 31, 2025, we recorded a net loss of $14.4 million. The net loss is primarily due to a reduction in revenue of $13.3 million (discussed below), ceiling test impairment of $3.6 million of the Company's oil and gas properties, lower production volumes resulting from cumulative divestments, lower realized sales price for our production and increasing lease operating expense on a BOE basis. During the year ended December 31, 2024, we recorded a net loss of $25.6 million including an $11.9 million ceiling test impairment.\n\n \n\n \n\nIn the following sections we discuss our revenue, operating expenses, and non-operating income (expense) for the year ended December 31, 2025 compared to the year ended December 31, 2024.\n\n \n\n*Revenue.*Presented below is a comparison of our oil and natural gas sales, production quantities and average sales prices for the years ended December 31, 2025 and 2024 (dollars in thousands, except average sales prices):\n\n \n\n \n \n \n \n** **\n \n \n \n** **\n \n\n**Change**\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Amount**\n\n \n \n\n**Percent**\n\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\n**Revenue:**\n\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n\nOil\n\n \n$\n6,378\n \n \n$\n18,165\n \n \n$\n(11,787\n)\n \n \n-65\n%\n\nGas\n\n \n \n975\n \n \n \n2,454\n \n \n \n(1,479\n)\n \n \n-60\n%\n\nTotal\n\n \n$\n7,353\n \n \n$\n20,619\n \n \n$\n(13,266\n)\n \n \n-64\n%\n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\n**Production quantities:**\n\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n\nOil (Bbls)\n\n \n \n112,797\n \n \n \n256,166\n \n \n \n(143,369\n)\n \n \n-56\n%\n\nGas (Mcfe)\n\n \n \n311,729\n \n \n \n958,325\n \n \n \n(646,596\n)\n \n \n-67\n%\n\nBOE\n\n \n \n164,752\n \n \n \n415,887\n \n \n \n(251,135\n)\n \n \n-60\n%\n\nBOE per day\n\n \n \n451\n \n \n \n1,136\n \n \n \n(685\n)\n \n \n-60\n%\n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\n**Average sales prices:**\n\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n \n \n \n** **\n\nOil (Bbls)\n\n \n$\n56.54\n \n \n$\n70.91\n \n \n$\n(14.37\n)\n \n \n-20\n%\n\nGas (Mcfe)\n\n \n \n3.13\n \n \n \n2.56\n \n \n \n0.57\n \n \n \n22\n%\n\nBOE\n\n \n \n44.63\n \n \n \n49.58\n \n \n \n(4.95\n)\n \n \n-10\n%\n\n \n\nThe decrease in our oil and gas revenue of $13.3 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024, was due to decreases in both production quantities and commodity prices. The realized price received for our oil production decreased 20% and the realized price received for our natural gas production increased 22% for the year ended December 31, 2025, compared to the year ended December 31, 2024.  \n\n \n\nFor the year ended December 31, 2025, we produced 164,752 BOE, or an average of 451 BOE per day, as compared to 415,887 BOE or 1,136 BOE per day, during the comparable period in 2024. Our oil production decreased 56% and our natural gas production decreased 67% compared to the prior year period. Production declines were primarily the result of property sales during 2025 and 2024. During the year ended December 31, 2025, our BOE production mix was 68% oil and 32% natural gas and liquids, consistent with 62% oil and 38% natural gas and liquids during 2024.\n\n \n\n*Oil and Natural Gas Production Costs.* Presented below is a comparison of our oil and natural gas production costs for the years ended December 31, 2025 and 2024 (in thousands):\n\n \n\n \n \n \n \n** **\n \n \n \n** **\n \n\n**Change**\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Amount**\n\n \n \n\n**Percent**\n\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\nLease operating expenses\n\n \n$\n5,174\n \n \n$\n11,160\n \n \n$\n(5,986\n)\n \n \n-54\n%\n\nGathering, transportation, and treating\n\n \n \n59\n \n \n \n205\n \n \n \n(146\n)\n \n \n-71\n%\n\nProduction taxes\n\n \n \n539\n \n \n \n1,213\n \n \n \n(674\n)\n \n \n-56\n%\n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\nTotal\n\n \n$\n5,772\n \n \n$\n12,578\n \n \n$\n(6,806\n)\n \n \n-54\n%\n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\nLease operating expense per BOE\n\n \n$\n31.40\n \n \n$\n26.83\n \n \n \n4.57\n \n \n \n17\n%\n\n \n\n59\n\n[Table of Contents](#toc)\n\n \n\nFor the year ended December 31, 2025, aggregate lease operating expenses decreased as a result of divestitures in 2025 and 2024. On a per BOE basis, lease operating expense increased $4.57 per BOE produced relative to 2024. The increase in lease operating expense on a per BOE basis is in part due to inflation and due to the fixed cost components of our lease operating expense becoming a larger portion of total costs as we have divested of lower cost properties and a result of natural production declines.\n\n \n\nGathering, transportation, and treating costs decreased $146 thousand or 71%, for the year ended December 31, 2025 compared to 2024. The decrease was attributable to the divestitures of operated properties in 2025 and 2024. \n\n \n\nProduction taxes for our properties typically average 7% of revenue. Any change in the production taxes is attributable to revenue changes resulting from changes in production volumes and realized prices year to year.\n\n \n\n*Depreciation, Depletion, Accretion and Amortization.*DD&A was $3.6 million for the year ended December 31, 2025, compared to $8.3 million for the year ended December 31, 2024. Our depreciation, depletion, and amortization (\"DD&A\") includes depletion expense on our oil and gas properties, accretion expense on our asset retirement obligations, and depreciation expense on our fixed assets. Depletion expenses on our oil and gas properties are the primary driver of DD&A expense making up 63% and 78% of DD&A expense for the years ended December 31, 2025 and 2024, respectively. Our depletion rate for the year ended December 31, 2025, was $21.89 per BOE, compared to $19.64 per BOE for the year ended December 31, 2024. Our depletion rate fluctuates because of the impact of divestitures, impairments on the full cost pool, but other factors such as acquisitions, revisions in asset retirement obligation cost estimates or timing, and underlying proved reserve volumes can also impact the rate.\n\n \n\n*Impairment of oil and natural gas properties.* Ceiling test impairment of $3.6 million during the year ended December 31, 2025 was incurred as a result of a decrease in crude oil and natural gas prices. For the year ended December 31, 2024, the Company recorded ceiling test impairment of its oil and natural gas properties of $11.9 million as a result of a decrease in crude oil and natural gas prices and the reduction in reserves from divestitures. \n\n \n\n*Exploration expense.* **For the years ended December 31, 2025 and 2024, exploration expense consisted primarily of professional fees and other costs associated with evaluating potential acquisitions, including land title review, regulatory consultations and geological assessments. These costs do not qualify for capitalization under the full cost method and are therefore expensed as incurred. Exploration expense decreased by $139 thousand in 2025 compared to 2024, primarily due to a higher level of acquisition evaluation activity during 2024.\n\n \n\n*General and Administrative Expenses.*Presented below is a comparison of our general and administrative expenses for the years ended December 31, 2025 and 2024 (in thousands):\n\n \n\n \n \n \n \n** **\n \n \n \n** **\n \n\n**Change**\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Amount**\n\n \n \n\n**Percent**\n\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\nCompensation and benefits, including directors\n\n \n$\n2,596\n \n \n$\n3,871\n \n \n$\n(1,275\n)\n \n \n-33\n%\n\nStock-based compensation\n\n \n \n1,854\n \n \n \n1,268\n \n \n \n586\n \n \n \n46\n%\n\nProfessional fees, insurance and other\n\n \n \n3,614\n \n \n \n3,057\n \n \n \n557\n \n \n \n18\n%\n\nTotal\n\n \n$\n8,064\n \n \n$\n8,196\n \n \n$\n(132\n)\n \n \n-2\n%\n\n \n\nGeneral and administrative expenses decreased by $132 thousand during the year ended December 31, 2025, as compared to the prior year period. Compensation and benefits decreased $1.3 million due to decreased headcount as the Company focused on the development of the industrial gas business. Stock-based compensation increased $586 thousand primarily due to grant prices used in prior employee and director stock-based compensation awards that amortized during 2025. Professional fees, insurance and other expenses increased $557 thousand, primarily due to professional fees associated with outsourcing a portion of our accounting function.\n\n \n\n*Loss on sale of assets.*During the year ended December 31, 2025, we recognized a $411 thousand related to the final settlement on our sale of our East Texas properties.\n\n \n\n*Non-Operating Income (Expense).* Presented below is a comparison of our non-operating income (expense) for the years ended December 31, 2025 and 2024 (in thousands):\n\n \n\n \n \n \n \n** **\n \n \n \n** **\n \n\n**Change**\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Amount**\n\n \n \n\n**Percent**\n\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n\nCommodity derivative gain (loss), net\n\n \n$\n-\n \n \n$\n537\n \n \n \n(537\n)\n \n \n-100\n%\n\nInterest income (expense), net\n\n \n \n(208\n)\n \n \n(442\n)\n \n \n234\n \n \n \n-53\n%\n\nOther income (expense)\n\n \n \n199\n \n \n \n(33\n)\n \n \n232\n \n \n \n-703\n%\n\nTotal non-operating expense\n\n \n$\n(9\n)\n \n$\n62\n \n \n$\n(71\n)\n \n \n-115\n%\n\n \n\nCommodity derivative gain (loss), net is the result of changes in derivative fair values associated with fluctuations in forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. During 2024, the Company settled all of its then outstanding commodity derivative contracts and received proceeds of $1.8 million. As of and for the year ended December 31, 2025, the Company had no derivative positions.\n\n \n\n60\n\n[Table of Contents](#toc)\n\n \n\nInterest expense, net, represents the interest related to our Credit Facility. The decrease in interest expense, net is primarily driven by a decrease in the outstanding principal balance on our credit facility as we have paid down the amount borrowed on the facility with proceeds from the divestments of properties. As of December 31, 2025, we had borrowed $2.5 million on the credit facility as compared to zero outstanding as of December 31, 2024.\n\n \n\nOther income (expense), net is primarily impacted from changes in the fair value of our investment in Anfield Energy. We recognized a net gain of $199 thousand on these items for the year ended December 31, 2025, but recognized a loss of $33 thousand for the comparable period of 2024.\n\n   \n\n*Income Tax Benefit (Expense).* The Company generated losses for income tax purposes in 2025 and 2024, and any additional net deferred income tax assets were offset by a corresponding valuation allowance.\n\n \n\n**Liquidity and Capital Resources**\n\n \n\nBased on the current commodity price environment and our current working capital, we believe we have sufficient liquidity and capital resources to meet our current financial obligations. We continue to manage our commitments in order to maintain flexibility with regard to our activity level and capital expenditures.\n\n \n\nDuring 2026, the Company expects to seek financing in the equity and credit markets to fund the construction of its gas processing plant, production gathering and related utility infrastructure. The estimated cost of this next development phase is approximately $35.0 million. The Company may sell equity under its existing Form S-3 registration statement, and/or sell equity under the purchase agreement with Roth Principal; however, no financing commitments have been secured to date, other than the purchase agreement. Such funding may not be available on favorable terms, or at all, and any equity funding raised may be dilutive to existing stockholders. If the Company is unable to obtain sufficient financing on acceptable terms, the timing or scope of this development phase may be delayed or modified.\n\n \n\nWe anticipate funding our day-to-day expenditures primarily with cash on hand, operating or investing cash inflows, and if necessary, borrowings under our credit facility or purchase agreement. If readily available sources of cash flow are insufficient to fund our capital needs, we may utilize equity and credit markets as a funding mechanism. In the event we sell equity, such sales may cause dilution to existing stockholders. \n\n \n\nAll of our sources of liquidity can be affected by the changes in economic conditions, rising interest rates, changes in debt and equity markets, force majeure events, fluctuations in commodity prices, operating costs, tax law changes, and volumes produced, all of which would affect us and our industry.\n\n \n\n*Sources of Cash*\n\n \n\nFor the year ended December 31, 2025, we funded our capital expenditures with cash on hand, proceeds from the divestitures of oil and gas producing properties and borrowings under our credit facility. In January 2025, we raised net proceeds of $10.3 million after the related party share Repurchase in an underwritten offering of 4,236,000 shares of our common stock discussed in greater detail above under [\"Item 1. Business—Material Events—Underwritten Offering\" and \"—Related Party Shares Repurchase\"](#item1).\n\n \n\n61\n\n[Table of Contents](#toc)\n\n \n\nCredit Agreement\n\n \n\nOn January 5, 2022, we entered into a four-year credit agreement with FirstBank Southwest as administrative agent, which provides for a revolving line of credit with a borrowing base of $20 million, and a maximum credit amount of $100 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. The Credit Agreement contains customary indemnification requirements, representations and warranties and customary affirmative and negative covenants applicable to the Company and its subsidiaries. In addition, the Credit Agreement contains financial covenants that limit our ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 3:1 and require our ratio of consolidated current assets to consolidated current liabilities (as each is described in the Credit Agreement) to remain at 1:1 or higher.\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*.*\n\n \n\nThe borrowing base is subject to redetermination semi-annually, commencing on or about April 1 and October 1 of each year during the four-year term of the Credit Agreement.  Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement. We were in compliance with our financial covenants as of December 31, 2025. The amount outstanding on the Credit Agreement as of December 31, 2025, was $2.5 million.  \n\n \n\n*Uses of Cash*\n\n \n\nWe use cash for the acquisition and development of our industrial gas properties, capital expenditures, workovers and operating costs related to our oil and gas properties, and general and administrative costs, settlements of commodity derivative contracts, debt obligations including interest, and share repurchases.  During the year ended December 31, 2025, we spent approximately $12.0 million on the acquisition and development of our industrial gas properties.\n\n \n\nThe amount, timing and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, and the number and size of acquisitions that we complete. In addition, the impact of industrial gas, oil and natural gas prices on investment opportunities, the availability of capital, tax law changes, and the timing and results of our development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, and other factors. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.\n\n \n\n The following table sets forth certain measures about our liquidity as of December 31, 2025 and 2024 ($ in thousands):\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Change**\n\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\nCash and equivalents\n\n \n$\n429\n \n \n$\n7,723\n \n \n$\n(7,294\n)\n\nWorking capital deficit (1)\n\n \n \n(4,038\n)\n \n \n(2,244\n)\n \n \n(1,794\n)\n\nTotal assets\n\n \n \n40,630\n \n \n \n49,667\n \n \n \n(9,037\n)\n\nOutstanding debt\n\n \n \n2,500\n \n \n \n-\n \n \n \n2,500\n \n\nTotal shareholders’ equity\n\n \n \n24,195\n \n \n \n24,201\n \n \n \n(6\n)\n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\nSelect Ratios:\n\n \n \n \n \n \n \n \n \n \n \n \n \n\nCurrent ratio (2)\n\n \n \n0.33 to 1.00\n \n \n \n0.81 to 1.00\n \n \n \n \n \n\nDebt-to-equity ratio (3)\n\n \n \n0.1 to 1.00\n \n \n \n\n0 to 1.00\n\n \n \n \n \n \n\n \n\n \n\n(1)\n\nWorking capital is computed by subtracting total current liabilities from total current assets.\n\n \n\n(2)\n\nThe current ratio is computed by dividing total current assets by total current liabilities.\n\n \n\n(3)\n\nThe debt-to-equity ratio is computed by dividing total debt by total shareholders’ equity.\n\n \n\nAs of December 31, 2025, we had a working capital deficit of $4.0 million compared to a working capital deficit of $2.2 million as of December 31, 2024, a decrease in working capital deficit of $1.8 million. However, when including the available borrowing capacity under the credit facility of $7.5 million as of December 31, 2025, we have a working capital surplus of $3.5 million, not including the cash proceeds received from the equity offering noted above.\n\n \n\n62\n\n[Table of Contents](#toc)\n\n \n\nAs of December 31, 2025, we had cash and cash equivalents of $429 thousand and accounts payable and accrued liabilities of $1.5 million. As of December 31, 2024, we had cash and cash equivalents of $7.7 million and accounts payable and accrued liabilities of approximately $5.1 million. Revenue and royalties payable decreased $915 thousand year over year.\n\n \n\nIf we have needs for financing in 2026, alternatives that we will consider would include borrowing amounts on our Credit Agreement, selling shares under the purchase agreement, selling all or a partial interest in certain of our oil and natural gas assets, issuing additional shares of our common stock for cash or as consideration for acquisitions in public or private offerings, and other alternatives, as we determine how to best fund our capital programs and meet our financial obligations.\n\n \n\n**Cash Flows**\n\n \n\nThe following table summarizes our cash flows for the years ended December 31, 2025 and 2024 (in thousands):\n\n \n\n \n \n\n**2025**\n\n \n \n\n**2024**\n\n \n \n\n**Change**\n\n \n\nNet cash provided by (used in):\n\n \n \n \n \n \n \n \n \n \n \n \n \n\nOperating activities\n\n \n$\n(7,138\n)\n \n$\n4,587\n \n \n$\n(11,725\n)\n\nInvesting activities\n\n \n \n(11,882\n)\n \n \n5,768\n \n \n \n(17,650\n)\n\nFinancing activities\n\n \n \n11,726\n \n \n \n(5,983\n)\n \n \n17,709\n \n\n \n\n*Operating Activities.* Cash used in operating activities for the year ended December 31, 2025, was $7.1 million as compared to cash provided by operating activities of $4.6 million for 2024, a decrease of $11.7 million. The decrease in cash provided by operating activities is mainly attributable to a reduction in cash receipts for revenues as a result of divestments and a decrease in prices we received for our oil and natural gas production.\n\n \n\n*Investing Activities.* Cash used in investing activities for the year ended December 31, 2025, was $11.9 million compared to cash provided by investing activities of $5.8 million for 2024, a decrease of $17.7 million. The use of cash in our investing activities for the year ended December 31, 2025 was due primarily to capital expenditures to acquire and develop our industrial gas project. In 2024 cash provided by investing activities consisted of proceeds from divestitures offset by capital expenditures on our oil and gas and industrial gas properties.\n\n \n\n*Financing Activities.* Cash provided by financing activities for the year ended December 31, 2025, was $11.7 million as compared to cash used in financing activities of $6.0 million for the comparable period in 2024. The cash provided by financing activities during the year ended December 31, 2025 was primarily attributable to proceeds from equity issuances under our January 2025 underwritten offering and borrowing under our credit facility. The use of cash in 2024 mainly represents net payments of borrowings on our credit facility of $5.0 million."}