{"url_path":"/sec/useg/10-k/2026/item-1","section_key":"item-1","section_title":"Item 1 Business.**","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":8875,"has_tables":true,"body_markdown":"**Item 1. Business.**\n\n \n\n**General Information**\n\n \n\nIn this Annual Report on Form 10-K (this “Report”), we may rely on and refer to information regarding the oil and gas industry or the industrial gas industry in general from market research reports, analyst reports and other publicly available information. Although we believe that this information is reliable, we cannot guarantee the accuracy and completeness of this information, we have not independently verified any of it and we have not commissioned any of the market or survey data that is presented in this Report.\n\n \n\nPlease see the “Glossary of Oil, Natural and Industrial Gas Terms” above for a list of abbreviations and definitions used throughout this Report.\n\n \n\nOur fiscal year ends on December 31st. Interim results are presented on a quarterly basis for the quarters ended March 31st, June 30th, and September 30th, the first quarter, second quarter and third quarter, respectively, with the quarter ending December 31st being referenced herein as our fourth quarter. Fiscal 2025 means the year ended December 31, 2025, whereas fiscal 2024 means the year ended December 31, 2024.\n\n \n\nUnless the context requires otherwise, references to the “Company,” “we,” “us,” “our,” “U.S. Energy,” and “U.S. Energy Corp.” refer specifically to U.S. Energy Corp. and its consolidated subsidiaries.\n\n \n\nIn addition, unless the context otherwise requires and for the purposes of this Report only:\n\n \n\n \n\n●\n\n“Exchange Act” refers to the Securities Exchange Act of 1934, as amended;\n\n \n \n \n\n \n\n●\n\n“SEC” or the “Commission” refers to the United States Securities and Exchange Commission; and\n\n \n \n \n\n \n\n●\n\n“Securities Act” refers to the Securities Act of 1933, as amended.\n\n \n\n**Overview**\n\n \n\nU.S. Energy Corp. was incorporated in the State of Wyoming on January 26, 1966, and reincorporated to Delaware effective on August 3, 2022. We are an industrial gas and energy company focused on the acquisition and development of industrial gases, oil and natural gas producing properties in the continental United States. Our principal properties and operations are in the Rockies region (Montana and Wyoming), the Mid-Continent (Oklahoma, and North and East Texas), and the Gulf Coast region.\n\n \n\nWe previously explored for and produced oil and natural gas through a non-operator business model, however, during 2020 we acquired operated properties in North Dakota, New Mexico, Wyoming and the Texas Gulf Coast, and on January 5, 2022, we closed the acquisitions of certain oil and gas properties from three separate sellers, representing a diversified portfolio of primarily operated, producing, oil-weighted assets located across the Rockies, West Texas, Eagle Ford, and Mid-Continent regions. Beginning in the fourth quarter 2023 and continuing through year-end 2025, we sold several legacy oil and natural gas assets and redeployed the capital into our industrial gas focus area. Our current oil and natural gas production is primarily located in the Rockies and Mid-Continent regions.\n\n \n\nOur business strategy going forward is to enhance the value of our acquired operated assets through evaluation of selected properties with the goal of increasing production and reserves. We plan to deploy our capital in a conservative and strategic manner and pursue value-enhancing transactions. We also continuously evaluate strategic alternative opportunities that we believe will enhance stockholder value.\n\n \n\n**Industrial Gas Operations**\n\n \n\nIn June 2024, the Company acquired approximately 144,000 acres across the Kevin Dome in Toole County, Montana for the purposes of exploring and exploiting multiple, industrial gas streams. On January 7, 2025, we acquired an additional 24,000 net acres that are contiguous to our existing positions in Toole County including a non-producing well that is expected to be completed and tested in the first half of 2026. Additionally, we drilled and completed two new industrial gas wells in 2025 and have filed monitoring, reporting and verifications applications with the government regulators that, assuming approved, will allow us to inject or dispose of carbon dioxide and waste gases, which is complementary to our ongoing development activities. Other ongoing activities include the detail design of a processing facility, gathering and transportation system, and power infrastructure, as well as securing rights of way, injection agreements, and negotiating an offtake agreement with a third party.\n\n \n\n**Office Location**\n\n \n\nOur principal executive office is located at 1616 S. Voss Road, Suite 725, Houston, Texas 77057. Our telephone number is (346) 509-8734.\n\n \n\n**Oil and Natural Gas Operations**\n\n \n\nWe participate in oil and natural gas projects primarily as an operator. Our working interest varies by project and may change over time based on the terms of our leases and operating agreements. Key attributes of our oil and natural gas properties include the following:\n\n \n\n \n\n●\n\nEstimated proved reserves of 1,451,821 barrels of oil equivalent (BOE) (75% oil and 25% natural gas) as of December 31, 2025, with a standardized measure of value of $16.7 million, utilizing prices of $ 65.34 per barrel for oil and $ 3.39 per Mcf for natural gas in accordance with Securities and Exchange Commission requirements.\n\n \n \n \n\n \n\n●\n\nAs of December 31, 2025, our oil and natural gas leases covered 160,714 gross acres and 134,025 net acres.\n\n \n \n \n\n \n\n●\n\n231 gross (209 net) producing wells as of December 31, 2025.\n\n \n \n \n\n \n\n●\n\n451 BOE per day average net production for 2025.\n\n \n\nAdditional information about our oil and gas properties and operations can be found in \"Item 2. Properties\".\n\n \n\n6\n\n[Table of Contents](#toc)\n\n \n\n**Material Events:**\n\n \n\n**Divestment of Properties**\n\n \n\nIn South Texas, the Company divested its assets in Karnes County, Texas, for approximately $5.2 million in net cash proceeds after customary purchase price adjustments, effective April 1, 2024, with the transaction closing on July 31, 2024. These primarily operated properties, consisting of 8 gross wells, which averaged 155 barrels of oil equivalent per day (85% oil) during the first quarter of 2024, representing 13% of our total production over that period.\n\n \n\nIn East Texas, the Company sold the majority of its assets across Anderson, Chambers, Henderson, and Liberty Counties, Texas, for $6.8 million in net cash proceeds, effective November 1, 2024, with the transaction closing on December 31, 2024. This package, comprising 122 gross wells, averaged approximately 1.1 million cubic feet per day of natural gas and 168 barrels of oil per day (48% oil) for the quarter ending September 30, 2024.\n\n \n\nIn the Mid-con region, the Company divested all of its operated properties in the state of Kansas and Kay County, Oklahoma, for $1.2 million in net cash proceeds, effective November 1, 2024, with the transaction closing on October 31, 2024. This package comprised 21 gross wells.\n\n \n\nProperties divested during 2024 represented 42% of the beginning of the year reserve volumes. The Company recognized a $5.0 million loss on the sale of its East Texas properties in the fourth quarter of 2024. The Company considered this a significant divestment that would significantly alter the relationship between capitalized costs and proved reserves as the divestiture represented 36% of our reserve volumes and 30% of our reserve value at the date of the divestiture.\n\n \n\nThe net proceeds from these divestitures were used to fund the continued development of the Company's industrial gas project in Montana, as well as for general corporate purposes. These divestitures reflect the Company's strategic portfolio management, exiting non-core geographic regions to enhance liquidity, strengthen the balance sheet, and redirect capital toward high-growth opportunities.\n\n \n\nIn 2025, the Company entered into a negotiated post-closing cash settlement and recognized a loss of $424 thousand on our $6.8 million divestment of properties located in Henderson, Anderson, Liberty, and Chambers County, Texas that closed on December 31, 2024 (as discussed above). The Company also closed on the sale of a portion of our Wyoming properties for approximately $500 thousand.\n\n \n\n**Acquisition of Properties**\n\n \n\n*Wavetech*\n\n \n\nOn June 26, 2024, we 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, we 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. 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, we agreed to be responsible for 100% of capital costs, including costs related to project exploration, appraisal, development drilling and completion until $20 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*Synergy*\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.\n\n \n\n***Derivative Activities***\n\n \n\nOn September 10, 2024, the Company settled all of its then outstanding commodity derivative contracts for 2024 and 2025 production receiving $1.8 million. As of December 31, 2025 and 2024, we no longer have any commodity derivative contracts outstanding.\n\n \n\n**Underwritten Offering**\n\n \n\nOn January 22, 2025, the Company entered into an underwriting agreement (the “Underwriting Agreement”) with Roth Capital Partners, LLC (the “Representative”), as representative of the several underwriters named in the Underwriting Agreement (the “Underwriters”), relating to an underwritten offering of 4,236,000 shares of common stock, par value $0.01 per share, of the Company at a price to the public of $2.65 per share (such offering, the “Offering”). \n\n \n\nUnder the terms of the Underwriting Agreement, the Company granted the Underwriters a 30-day option to purchase up to 635,400 additional shares of common stock (the “Option”), which was exercised in full on January 25, 2025.\n\n \n\n7\n\n[Table of Contents](#toc)\n\n \n\nThe sale of 4,871,400 shares of common stock (including the full 635,400 Option) in connection with the Offering, closed on January 23, 2025. The Company intends to use the approximately $12.1 million of net proceeds from the Offering, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, 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 had the ability, pursuant to the terms of the Underwriting Agreement, to use up to the entire amount of proceeds from the Option exercise to purchase shares of common stock from Sage Road Capital, LLC (a current shareholder of the Company whose co-manager is Joshua L. Batchelor, a member of the Board of Directors of the Company) or its affiliates at a price up 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 $1,574,362 or $2.47775 per share, which is the price per share of the 4,871,400 shares of common stock which we 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\nThe Share Repurchase Agreement contains customary representations, warranties and covenants of the parties. The share repurchase was approved by the disinterested members of the Board of Directors of the Company, as well as the Company’s Audit Committee, comprised solely of independent directors not affiliated with Mr. Batchelor or the Selling Stockholders.\n\n \n\n***Stock Repurchase Program***\n\nOn January 29, 2025, the Board of Directors of the Company authorized and approved an extension of a then ongoing share repurchase program for up to $5.0 million of the outstanding shares of the Company’s common stock originally approved by the Board of Directors on April 26, 2023 and subsequently extended, subject to any future extensions in the discretion of the Board of Directors of the Company, the repurchase program is now scheduled to expire on June 30, 2026, when a maximum of $5.0 million of the Company’s common stock has been repurchased, or when such program is discontinued by the Board of Directors.\n\n \n\nUnder the stock repurchase program, shares may be 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 will be 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 will be funded using the Company’s working capital.\n\nFor the year ended December 31, 2025, the Company repurchased 197,400 shares of common stock for $317 thousand, at a weighted average price of $1.61 per share. For the year ended December 31, 2024, the Company repurchased 617,000 shares for $730 thousand at a weighted average price of $1.18 per share. As of December 31, 2025, a total of $3.5 million remained available under the repurchase program for future repurchases.\n \n\n***Credit Facility***\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.\nSignificant 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 $20.0 million to $10.0 million, and deferring the next test period for the ratio of total debt to EBITDAX to March 31, 2026.\n\n \n\n***Committed Equity Facility***\n\n \n\nOn October 9, 2025, we entered into a purchase agreement and a related registration rights agreement (the “Registration Rights Agreement”) with Roth Principal Investments, LLC (“Roth Principal Investments”). Subject to the terms and conditions of the purchase agreement, we may, in our sole discretion, sell to Roth Principal Investments up to $25,000,000 of shares of our common stock (the “Commitment Amount”) from time to time during the term of the purchase agreement. We are under no obligation to sell any shares, and Roth Principal Investments is required to purchase shares only as directed by us and subject to the Purchase Agreement.\n\n \n\nPursuant to the Registration Rights Agreement, we filed a registration statement to register the resale of up to 24,100,000 shares of common stock, consisting of (i) up to 23,876,859 shares of common stock that we may elect to sell to Roth Principal Investments (the “Purchase Shares”) and (ii) 223,141 shares of common stock issued to Roth Principal Investments upon execution of the Purchase Agreement (the “Commitment Shares”).\n\n \n\nFrom and after December 1, 2025, and for a period of up to 24 months (the “Commitment Period”), unless earlier terminated, we may direct Roth Principal Investments to purchase shares of common stock through one or more “Market Open Purchases” or “Intraday Purchases,” each subject to the terms, conditions, notice requirements, and limitations set forth in the Purchase Agreement, including the requirement that the closing sale price of our common stock on the trading day immediately prior to the applicable Purchase Date is not less than the “Threshold Price.”\n\n \n\nThe per share purchase price for shares sold in a Market Open Purchase or an Intraday Purchase is based on the volume weighted average price (“VWAP”) of our common stock during the applicable valuation period, less a fixed 2.5% discount, subject to the applicable minimum price thresholds and other adjustments set forth in the Purchase Agreement. There is no upper limit on the per share price that Roth Principal Investments may be required to pay.\n\n \n\nWe control the timing and amount of any sales under the purchase agreement. Actual sales, if any, will depend on market conditions, the trading price of our common stock and our capital needs. Net proceeds, if any, are expected to be used for working capital and general corporate purposes.\n\n \n\nUnder applicable Nasdaq rules, issuances under the purchase agreement may not exceed 7,123,382 shares of common stock, representing 19.99% of the shares outstanding immediately prior to execution of the purchase agreement (the “Exchange Cap”), unless stockholder approval is obtained or the average price paid by Roth Principal Investments equals or exceeds $1.2788, in which case the Exchange Cap will not apply. In addition, issuances may not result in Roth Principal Investments and its affiliates beneficially owning more than 4.99% of our outstanding common stock (the “Beneficial Ownership Limitation”).\n\n \n\nThe purchase agreement will terminate upon the earliest to occur of the expiration of the Commitment Period, the purchase of the full Commitment Amount, certain listing or bankruptcy events, or earlier termination by us upon 10 trading days’ prior written notice. Neither the purchase agreement nor the Registration Rights Agreement may be assigned or amended except as expressly permitted therein.\n\n \n\nAs consideration for Roth Principal Investments’ commitment, we paid a $25,000 structuring fee, issued 223,141 Commitment Shares, agreed to pay a $180,000 cash commitment fee (the “Cash Commitment Fee”), and agreed to potential make-whole payments of up to $270,000 under certain circumstances. We also agreed to reimburse Roth Principal Investments’ legal fees in the amounts specified in the purchase agreement.\n\n \n\nBecause the purchase price for Purchase Shares is based on future VWAP calculations, we cannot determine the actual number of shares that may be issued under the purchase agreement. If all shares registered for resale under this prospectus were issued, such issuances would result in significant dilution to existing stockholders.\n\n \n\n8\n\n[Table of Contents](#toc)\n\n \n\n**Environmental Laws and Regulations**\n\n \n\n*Environmental Matters*\n\n \n\nOur operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:\n\n \n\n \n\n●\n\nRequire the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;\n\n \n \n \n\n \n\n●\n\nLimit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and\n\n \n \n \n\n \n\n●\n\nImpose substantial liabilities for pollution resulting from operations.\n\n \n\nThe permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations and have no significant commitments for capital expenditures to comply with existing environmental requirements, although future regulatory changes could require additional capital expenditures. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.\n\n \n\n**Comprehensive Environmental, Response, Compensation, and Liability Act (**“**CERCLA**”**)****.**CERCLA and comparable state statutes impose strict, joint and several liabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. These persons include the owner or operator of the site where the release occurred, persons who disposed or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA authorizes the Environmental Protection Agency (“EPA”), state environmental agencies, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products.\n\n \n\n**Waste Handling****.**The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be reclassified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.\n\n \n\n**Endangered Species****.** The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.\n\n \n\n**Air Emissions.** The federal Clean Air Act (the “CAA”) and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. Applicable to our business and operations, the CAA regulates emissions from oil and natural gas production and processing operations. The CAA includes New Source Performance Standards (\"NSPS\") for the oil and natural gas source category addressing emissions of methane, volatile organic compounds (\"VOCs\"), and other pollutants, as well as National Emissions Stands for Hazardous Air Pollutants (\"NESHAP\"). Further, the CAA regulates the emissions from compressors, dehydrators, storage tanks and other production equipment as well as leak detection for natural gas processing plants. These rules have required a number of modifications to the operations of our third-party operating partners, including the installation of new equipment to control emissions from compressors.\n\n \n\n9\n\n[Table of Contents](#toc)\n\n \n\nIn addition, the EPA has adopted, and continues to adopt and revise, regulations governing emissions from oil and natural gas operations. These regulations include expanded methane emission standards and leak detection requirements applicable to both new and existing sources. We do not expect that currently applicable NSPS or NESHAP requirements will have a material adverse effect on our business, financial condition or results of operations; however, future regulatory changes could require additional permitting, operational modifications or capital expenditures.\n\n \n\nOn December 17, 2014, the EPA proposed to revise and lower the existing 75 pounds per barrel (ppb) National Ambient Air Quality Standard (“NAAQS”) for ozone under the CAA to a range within 65-70 ppb. On October 1, 2015, the EPA finalized a rule that lowered the standard to 70 ppb. This lowered ozone NAAQS could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas likely would be subject to more stringent emission controls, emission offset requirements for new sources, and increased permitting delays and costs. \n\n \n\nPermit and related compliance obligations under the CAA, each state’s development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and natural gas exploration and production operators to incur future capital and operating expenditures in connection with the addition or modification of existing air emission control equipment and strategies.\n\n \n\n**Global Warming and Climate Change***.*Various state governments and regional organizations have enacted, or are considering enacting, new legislation and promulgating new regulations governing or restricting the emission of Greenhouse Gases (\"GHGs\"), including from facilities, vehicles and equipment. Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell or the cost of the equipment and other materials we use. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment, install new emission controls on our equipment, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.\n\n \n\nAdditionally, the development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for the oil and gas we produce, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.\n\n \n\nIn addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this may make it more difficult and expensive for us to secure funding. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our securities. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.\n\n \n\n10\n\n[Table of Contents](#toc)\n\n \n\nThese various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.\n\n \n\nCompliance with GHG laws or taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources.\n\n \n\n**Water discharges.**The federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. This includes the discharge of certain storm water without a permit which requires periodic monitoring and sampling. In addition, the Clean Water Act regulates wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state, if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.\n\n \n\n**Oil Pollution Act of 1990 (**“**OPA**”**).**OPA addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.\n\n \n\n**Safe Drinking Water Act (**“**SDWA**”**).** The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended, and analogous state laws. The SDWA’s Underground Injection Control (“UIC”) Program establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. In response to concerns related to increased seismic activity in the vicinity of injection wells, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) has adopted oil and natural gas permit rules for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. In addition, any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.\n\n \n\n11\n\n[Table of Contents](#toc)\n\n \n\n**The Occupational Safety and Health Act (**“**OSHA**”**).** OSHA and comparable state laws regulate the protection of the health and safety of employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and disclose information about hazardous materials used or produced in our operations.\n\n \n\n**Hydraulic Fracturing****.**Substantially all of the oil and natural gas production in which we have interests is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight shale formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, even on private lands, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation’s public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.\n\n \n\nIncreased regulation and scrutiny on oil and gas activities involving hydraulic fracturing techniques could potentially lead to a decrease in the completion of new oil and gas wells, an increase in compliance costs, delays, and changes in federal income tax laws, all of which could adversely affect our financial position, results of operations, and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local levels, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.\n\n \n\nWe believe the trend in local, state, and federal environmental legislation and regulation will continue toward stricter standards, particularly under President Biden’s administration. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.\n\n \n\n**National Environmental Policy Act (**“**NEPA**”**).** Oil and natural gas exploration, development and production activities on federal lands, including tribal lands and lands administered by the BLM, are subject to NEPA. NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities may need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Many of our activities and those of our third-party operating partners are covered under categorical exclusions which results in a shorter NEPA review process, however, the impact of the NEPA review process on our activities and those of our third-party operating partners is uncertain at this time and could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.\n\n \n\n12\n\n[Table of Contents](#toc)\n\n \n\n**Governmental Regulation**\n\n \n\nOur operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole.\n\n \n\n*Regulation of Oil and Natural Gas Production*\n\n \n\nOur oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota requires permits for drilling operations, drilling bonds and reports concerning operations and imposes other requirements relating to the exploration and production of oil and natural gas. Many states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, the flaring of natural gas, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.\n\n \n\n*Regulation of Transportation of Oil*\n\n \n\nSales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could re-enact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. The FERC has implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost-of-service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs.\n\n \n\nIntrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.\n\n \n\nFurther, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.\n\n \n\n13\n\n[Table of Contents](#toc)\n\n \n\n*Regulation of Transportation and Sales of Natural Gas*\n\n \n\nHistorically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.\n\n \n\nOnshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.\n\n \n\nIntrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.\n\n \n\n**Research and Development**\n\n \n\nNo research and development expenditures have been incurred during the past two fiscal years.\n\n \n\n**Insurance**\n\n \n\nWe have general liability and property insurance coverage in amounts we deem sufficient for our business operations, consisting of property loss insurance on major assets for the approximate value of the assets and additional liability and operator’s and control of well insurance for our industrial gas, oil and natural gas operations and drilling programs. We do not have insurance coverage for the lost revenues associated with a business interruption, nor do we have coverage for the loss of our oil and natural gas reserves. There is no guarantee that any insurance coverage would be sufficient to protect the value of our assets or to fully cover any losses sustained. Payment of substantial liabilities in excess of coverage could require diversion of internal capital away from regular business, which could result in curtailment of projected future operations.\n\n \n\n**Human Capital**\n\n \n\nAs of March 6, 2026, we had 20 employees, none of whom were subject to a collective bargaining agreement. In addition, we utilize several consultants on an as-needed basis. We recognize that our employees are our most valuable assets and drive the way we pursue our short-term and long-term goals. To attract and retain talent we promote:\n\n \n\n \n\n●\n\nintegrity and ethical behavior in the conduct of our business;\n\n \n \n \n\n \n\n●\n\nenvironmental, health and safety priorities:\n\n \n \n \n\n \n\n●\n\nprioritizing the success of others and the team;\n\n \n \n \n\n \n\n●\n\ncommunicating why we do what we do and how every employee contributes to achieving success; and\n\n \n \n \n\n \n\n●\n\nsupport for team members’ professional and personal development.\n\n \n\nThe core values of integrity and ethical behavior are the pillars of our culture, and as a result, the health and safety of our employees and contractors is our highest priority. All employees are responsible for upholding Company-wide standards and values. We have policies designed to promote ethical conduct and integrity that employees are required to read and acknowledge.\n\n \n\n14\n\n[Table of Contents](#toc)\n\n \n\nWe strive to provide competitive, performance-based compensation and benefits to our employees, including market-competitive pay, and various healthcare, retirement, and other benefit packages. The Compensation Committee of our Board of Directors oversees our compensation programs and designs programs to incentivize achievement of our corporate strategy and the matters of importance to our stakeholders.\n\n \n\n**Forward Plan and Development**\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 begin 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 generating capital to fully fund development. Our share repurchase program was extended to June 30, 2026. Repurchases of shares may resume in 2026 so long as share prices remain attractive and repurchases remain in the best interests of both the Company and its stockholders.\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**Industry Operating Environment**\n\n \n\nThe industrial gas and oil and natural gas industries are affected by many factors that we cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on operations and profitability. Significant factors that may impact commodity prices in the current fiscal year and future periods include international conflicts, the level of inflation and interest rates, access to capital at commercial reasonable costs, and related political developments in response to tariffs and international conflicts, demand in domestic, Asian and European markets, and the extent to which exporting nations manage commodity supply or incentivize incremental production. Seasonal weather patterns and economic cycles also have a significant impact on commodity prices in both the industrial gas and oil and gas industries.\n\n \n\nThese factors may adversely impact the supply and demand for our products and influence our ability to develop, produce, process and transport industrial gas, oil and natural gas. This uncertainty also affects management’s accounting estimates and assumptions, which could result in greater variability in a variety of areas that depend on these estimates and assumptions, including investments, receivables, and forward-looking guidance.\n\n \n\n15\n\n[Table of Contents](#toc)\n\n \n\n**Seasonality**\n\n \n\nWinter weather conditions can limit or temporarily halt our drilling and development activities. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose timing challenges and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations and those of our operating partners.\n\n \n\n**Title to Properties**\n\n \n\nTitle to properties is subject to royalty, overriding royalty, carried working, net profits, working and other similar interests and contractual arrangements, liens for current taxes not yet due and other encumbrances. As is customary in the case of undeveloped properties, limited investigation of record title is made at the time of acquisition (other than preliminary review of local records).\n\n \n\nInvestigation, including a title opinion of local counsel, generally is made before commencement of drilling operations.\n\n \n\n**Marketing, Major Customers and Delivery Commitments**\n\n \n\nMarkets for industrial gases, oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions, actions by exporting countries, and domestic demand, government regulations and policies. All of our existing oil and gas production is marketed by our industry partners for our benefit and is sold to competing buyers, including large oil refining companies and independent marketers. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. Our industrial gas project is under development and as such, there is no industrial gas production that is currently marketed.   We had no significant delivery commitments as of  December 31, 2025.\n\n \n\n**Competition**\n\n \n\nOur operations are highly competitive in the search for and acquisition of oil, natural gas, and industrial gas resources. Our competitors principally consist of independent operators, small, and intermediate-sized industrial gas, oil and natural gas companies. Specifically, we compete for property acquisitions and our operating partners compete for the equipment and labor required to operate and develop our properties. Our competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Ultimately, our future success will depend on our ability to develop or acquire additional reserves and resources at costs that allow us to remain competitive.\n\n \n\n16\n\n[Table of Contents](#toc)\n\n \n\n**Available Information**\n\n \n\nThe Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act, are filed with the U.S. Securities and Exchange Commission. Such reports and other information filed by the Company with the SEC are available free of charge at https://investors.usnrg.com/investors/sec-filings when such reports are available on the SEC’s website. The Company periodically provides other information for investors on its corporate website, https://usnrg.com. Further, the Company’s references to website URLs are intended to be inactive textual references only. Copies of documents filed by us with the SEC are also available from us without charge, upon oral or written request to our Secretary, who can be contacted at the address and telephone number set forth on the cover page of this Report. You may also find information related to our corporate governance, board committees and code of ethics on our website.\n\n \n\nThe Company uses, and will continue to use, its website (https://usnrg.com) and press releases, as additional means of disclosing public information to investors, the media and others interested in the Company. It is possible that certain information that the Company posts on its website, and/or disseminated in press releases could be deemed to be material information, and the Company encourages investors, the media and others interested in the Company to review the business and financial information that the Company posts on its website and disseminates in press releases, as such information could be deemed to be material information.\n\n \n\nThe information contained on the websites referenced in this Form 10-K is not incorporated by reference into this filing."}