{"url_path":"/sec/royl/10-k/2026/item-15","section_key":"item-15","section_title":"Item 15 Exhibits and Financial Statement Schedules**","topic":"sec","document":{"doc_type":"10-K","doc_date":"2026-07-13","source_url":"https://www.sec.gov/Archives/edgar/data/1694617/0001185185-26-002897-index.html","accession_number":"0001185185-26-002897","cik":"0001694617","ticker":"ROYL","issuer_name":"Royale Energy, Inc.","edgar_url":"https://www.sec.gov/Archives/edgar/data/1694617/0001185185-26-002897-index.html","primary_entity_key":"0001694617","primary_entity_name":"Royale Energy, Inc."},"word_count":14904,"has_tables":true,"body_markdown":"**Item 15 Exhibits and Financial Statement Schedules**\n\n \n\nThe agreements included as exhibits to this report are included to\nprovide information about their terms and not to provide any other factual or disclosure information about Royale or the other parties\nto the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were\nmade solely for the benefit of the other parties to the respective agreement, and:\n\n \n\n \n●\nshould not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;\n\n \n \n \n\n \n●\nhave been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;\n\n \n \n \n\n \n●\nmay apply standards of materiality in a way that is different from the way investors may view materiality; and\n\n \n \n \n\n \n●\nwere made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.\n\n \n\n1. Financial Statements. See Index to Financial Statements,\npage F-1\n\n \n\n2. Schedules. None.\n\n \n\n3. Exhibits. Certain of the exhibits listed in the following\nindex are incorporated by reference.\n\n \n\n3.1*\n \n[Certificate of Incorporation of Royale Energy, Inc. (formerly Royale Energy Holdings, Inc.) filed with the Secretary of State of Delaware on November 22, 2016 (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the Securities and Exchange Commission on April 9, 2025).](http://www.sec.gov/Archives/edgar/data/1694617/000118518525000271/roylex3-1.htm)\n\n3.2\n \n[Amendment to the Certificate of Incorporation of Royale Energy, Inc., a Delaware corporation, dated February 28th, 2018 (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 12, 2018.)](http://www.sec.gov/Archives/edgar/data/1694617/000118518518000398/ex3-1.htm)\n\n3.3*\n \n[Bylaws of Royale Energy, Inc. Bylaws of Royale Energy, Inc. (Incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the Securities and Exchange Commission on April 9, 2025).](http://www.sec.gov/Archives/edgar/data/1694617/000118518525000271/roylex3-3.htm)\n\n4.1\n \n[Royale Energy Holdings, Inc., Certificate of Designation of Series B 3.5% Redeemable Convertible Preferred Stock, filed with the Delaware Secretary of State on February 27, 2018, filed as Exhibit 2.5 to the Company’s Form 8-A, filed March 8, 2018](http://www.sec.gov/Archives/edgar/data/1694617/000118518518000381/ex2-5.htm)\n\n10.17†\n \n[Royale Energy, Inc., 2018 Equity Incentive Plan, filed as Exhibit 99.1 to the Company’s Form S-8 filed October 29, 2018](http://www.sec.gov/Archives/edgar/data/1694617/000118518518001883/ex_126467.htm)\n\n10.27†\n \n[Incentive Stock Option Agreement between the Company and Stephen M. Hosmer, filed as Exhibit 10.11 to the Company’s Form S-8 filed October 29, 2018](http://www.sec.gov/Archives/edgar/data/1694617/000118518518001883/ex_126463.htm)\n\n10.28\n \n[Secured Term Loan Note dated February 9, 2024, filed as Exhibit 10.1 to the Company’s form 8-K filed on February 15, 2024](https://www.sec.gov/Archives/edgar/data/1694617/000118518524000170/ex_627210.htm)\n\n10.29\n \n[Amendment to Secured Term Loan Note dated November 1, 2024 (Incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 10-Q filed with the Securities and Exchange Commission on November 14, 2024.)](http://www.sec.gov/Archives/edgar/data/1694617/000118518524001118/ex_748306.htm)\n\n10.30\n \n[Exchange Agreement, filed as Exhibit 10.1 to the Company’s Form 8-K filed on October 17, 2024](http://www.sec.gov/Archives/edgar/data/1694617/000118518524000993/ex_734071.htm)\n\n10.31\n \n[Form of Series 2024 Senior Promissory Note, filed as Exhibit 10.2 to the Company’s Form 8-K filed on October 17, 2024](http://www.sec.gov/Archives/edgar/data/1694617/000118518524000993/ex_734072.htm)\n\n10.32\n \n[Stock Option Agreement, filed as Exhibit 10.3 to the Company’s Form 8-K filed on October 17, 2024](http://www.sec.gov/Archives/edgar/data/1694617/000118518524000993/ex_734073.htm)\n\n10.33\n \n[Release Agreement, filed as Exhibit 10.4 to the Company’s Form 8-K filed on October 17, 2024](http://www.sec.gov/Archives/edgar/data/1694617/000118518524000993/ex_734074.htm)\n\n21.1*\n \n[Subsidiaries of Registrant](roylex21-1.htm)\n\n23.1*\n \n[Consent of BDO USA, P.C.](roylex23-1.htm)\n\n23.3*\n \n[Consent of Netherland, Sewell & Associates, Inc.](roylex23-3.htm)\n\n31.1*\n \n[Rule 13a-14(a), 115d-14(a) Certification](roylex31-1.htm)\n\n31.2*\n \n[Rule 13a-14(a), 115d-14(a) Certification](roylex31-2.htm)\n\n32.1*\n \n[Section 1350 Certification](roylex32-1.htm)\n\n32.2*\n \n[Section 1350 Certification](roylex32-2.htm)\n\n99.1*\n \n[Report of Netherland, Sewell & Associates, Inc.](roylex99-1.htm)\n\n101.INS\n \nInline XBRL Instance Document\n\n101.SCH\n \nInline XBRL Taxonomy Extension Schema\n\n101.CAL\n \nInline XBRL Taxonomy Extension Calculation Linkbase\n\n101.DEF\n \nInline XBRL Taxonomy Extension Definition Linkbase\n\n101.LAB\n \nInline XBRL Taxonomy Extension Label Linkbase\n\n101.PRE\n \nInline XBRL Taxonomy Extension Presentation Linkbase\n\n104\n \nCover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)\n\n  \n\n*\nFiled herewith.\n\n \n\n†\nManagement contract or compensatory plan or arrangement.\n\n \n\n21\n\n[Table of Contents](#toc) \n\n \n\n**SIGNATURES**\n\n \n\nPursuant to the requirements of Section 13 or 15(d) of the Securities\nExchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.\n\n \n\n \n**Royale Energy, Inc.**\n\n \n \n\nDate: July 10, 2026\n*/s/ Johnny Jordan*\n\n \nJohnny Jordan\n\n \nChief Executive Officer\n\n \n \n\nDate: July 10, 2026\n*/s/ Ronald Lipnick*\n\n \nRonald Lipnick\n\n \nChief Financial Officer\n\n \n\nPursuant to the requirements of the Securities Exchange Act of 1934,\nthis report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.\n\n \n\nDate: July 10, 2026\n*/s/ John Sullivan*\n\n \nJohn Sullivan\n\n \nChairman of the board of directors\n\n \n \n\nDate: July 10, 2026\n*/s/ Jonathan Gregory*\n\n \nJonathan Gregory\n\n \nVice-Chair of the board of directors\n\n \n \n\nDate: July 10, 2026\n*/s/ Chris Parada*\n\n \nChris Parada\n\n \nDirector\n\n \n \n\nDate: July 10, 2026\n*/s/ Jeff Kerns*\n\n \nJeff Kerns\n\n \nDirector\n\n \n \n\nDate: July 10, 2026\n*/s/ Stephen Hosmer*\n\n \nStephen Hosmer\n\n \nDirector\n\n \n\n22\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**INDEX TO CONSOLIDATED FINANCIAL STATEMENTS**\n\n**AND SUPPLEMENTARY DATA**\n\n \n\n[REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (BDO USA, P.C.(formerly HORNE, LLP); Houston, Texas; PCAOB ID #243)](#f_001)\n  F-2\n\n     \n\n[CONSOLIDATED BALANCE SHEETS](#f_002)   F-4\n\n     \n\n[CONSOLIDATED STATEMENTS OF OPERATIONS](#f_003)   F-6\n\n     \n\n[CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT](#f_004)   F-7\n\n     \n\n[CONSOLIDATED STATEMENTS OF CASH FLOWS](#f_005)   F-8\n\n     \n\n[NOTES TO CONSOLIDATED FINANCIAL STATEMENTS](#f_006)   F-9\n\n \n\nF-1\n\n[Table of Contents](#toc) \n\n \n\n**Report of Independent Registered Public Accounting\nFirm**\n\n \n\nShareholders and Board of Directors\n\nRoyale Energy, Inc.\n\nEl Cajon, California\n\n \n\n**Opinion on the Consolidated\nFinancial Statements**\n\n** **\n\nWe have audited the accompanying\nconsolidated balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2025 and 2024, the related consolidated\nstatements operations, stockholders’ deficit, and cash flows for the years then ended, and the related notes (collectively referred\nto as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in\nall material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its\ncash flows for the years then ended**,** in conformity with accounting principles generally accepted in the United States of America.\n\n \n\n**Going Concern Uncertainty**\n\n** **\n\nThe accompanying consolidated\nfinancial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated\nfinancial statements, the Company has suffered recurring losses from operations and has a working capital deficiency that raise substantial\ndoubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note\n1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.\n\n \n\n**Basis for Opinion**\n\n** **\n\nThese consolidated financial\nstatements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s\nconsolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting\nOversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal\nsecurities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.\n\n \n\nWe conducted our audits in accordance with the\nstandards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated\nfinancial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were\nwe engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an\nunderstanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the\nCompany’s internal control over financial reporting. Accordingly, we express no such opinion.\n\n \n\nOur audits included performing procedures to\nassess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures\nthat respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the\nconsolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made\nby management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide\na reasonable basis for our opinion.\n\n \n\nF-2\n\n[Table of Contents](#toc) \n\n \n\n**Critical Audit Matter**\n\n** **\n\nThe critical audit matter communicated below\nis a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated\nto the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and\n(2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter\nin any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit\nmatter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.\n\n \n\n**Estimation of Quantities\nof Future Production Volumes Used to Estimate Proved Oil and Gas Reserves and the Associated Effect on Depreciation, Depletion and Amortization\n(“DD&A”) Expense Related to Proved Oil and Gas Properties**\n\n** **\n\nAs disclosed by management\nand described in Notes 1 and 2 to the consolidated financial statements, the Company uses the successful efforts method of accounting\nfor its oil and gas producing activities. Management uses internal and independent petroleum engineers to make significant estimates,\nincluding estimating quantities of proved oil and gas reserves. The Company’s oil and gas properties, net as of December 31, 2025\nwas $5.7 million, which includes proved oil and gas properties of $10.5 million and accumulated depletion, depreciation, and amortization\n(“DD&A”) of $8.0 million. DD&A expense was $0.3 million for the year ended December 31, 2025.\n\n \n\nWe have\nidentified the estimation of future production volumes used to estimate proved oil and gas reserves and the associated effect on\nDD&A expense related to proved oil and gas properties as a critical audit matter. Estimating future production volumes involves\na high degree of subjectivity from management and their internal and independent petroleum engineers. Auditing the estimation of\nfuture production volumes required subjective and complex auditor judgement.\n\n \n\nThe primary procedures we performed\nto address this critical audit matter included:\n\n \n\n●Evaluating\nthe professional qualifications and objectivity of the internal and independent petroleum\nengineers, including their relationship to the Company.\n\n   \n\n●Assessing\nthe reasonableness of the future production volumes by comparing estimates of future production\nvolumes against historical results of production volumes on a summary basis for all wells\nand on a detailed basis for a sample of wells.\n\n   \n\n●\nPerforming a retrospective review over management estimates of future\nproduction volumes made in the prior period as compared to actual results.\n\n \n\n/s/ BDO USA, P.C.\n\n(formerly HORNE LLP)\n\nWe have served as the Company’s auditor since\n2023.\n\nHouston, Texas\n\nJuly 10, 2026\n\n \n\nF-3\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**CONSOLIDATED BALANCE SHEETS**\n\n**DECEMBER 31,**\n\n \n\n  \n2025  \n2024 \n\nASSETS \n   \n  \n\nCurrent Assets: \n   \n  \n\nCash and Cash Equivalents \n$1,099,044  \n$1,877,163 \n\nRestricted Cash \n 7,175,950  \n 6,025,000 \n\nOther Receivables, net \n 793,608  \n 868,429 \n\nRevenue Receivables \n 694,729  \n 764,653 \n\nPrepaid Expenses and Other Current Assets \n 746,862  \n 619,913 \n\nTotal Current Assets \n 10,510,193  \n 10,155,158 \n\n  \n    \n   \n\nOther Assets \n 576,265  \n 589,865 \n\nRight of Use Asset - Leases \n 141,417  \n 238,509 \n\nOil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net \n 5,774,178  \n 4,656,659 \n\nTotal Assets \n$17,002,053  \n$15,640,191 \n\n \n\nThe accompanying notes are an integral part of\nthese consolidated financial statements.\n\n \n\nF-4\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**CONSOLIDATED BALANCE SHEETS (Continued)**\n\n**DECEMBER 31,**\n\n** **\n\n  \n2025  \n2024 \n\nLIABILITIES AND STOCKHOLDERS’ DEFICIT \n   \n  \n\nCurrent Liabilities: \n   \n  \n\nAccounts Payable and Accrued Expenses \n$6,033,878  \n$6,776,825 \n\nRoyalties Payable \n 611,833  \n 611,833 \n\nRMX Resources, LLC \n 23,087  \n 23,087 \n\nLeases - Current \n 102,238  \n 94,070 \n\nAsset Retirement Obligation - Current \n 1,012,500  \n 1,012,500 \n\nDeferred Drilling Obligations \n 14,277,496  \n 11,457,996 \n\n  \n    \n   \n\nTotal Current Liabilities \n 22,061,032  \n 19,976,311 \n\n  \n    \n   \n\nNoncurrent Liabilities: \n    \n   \n\nAsset Retirement Obligation \n 4,065,352  \n 4,066,095 \n\nNotes Payable \n 4,121,112  \n 3,489,290 \n\nLeases - Non-current \n 43,386  \n 145,644 \n\nAccrued Unpaid Guaranteed Payments \n 90,000  \n 90,000 \n\nAccrued Liabilities - Non-current \n 12,386  \n 12,386 \n\n  \n    \n   \n\nTotal Liabilities \n 30,393,268  \n 27,779,726 \n\nCommitments and Contingencies (See Note 13) \n    \n   \n\nStockholders’ Deficit: \n    \n   \n\nCommon Stock, $0.001 Par Value, 280,000,000 Shares Authorized 96,600,302 and 96,600,302 shares issued and outstanding at December 31, 2025 and 2024, respectively \n 96,600  \n 96,600 \n\n  \n    \n   \n\nAdditional Paid in Capital \n 81,078,554  \n 81,078,554 \n\n  \n    \n   \n\nAccumulated Deficit \n (94,566,369) \n (93,314,689)\n\n  \n    \n   \n\nTotal Stockholder’s Deficit \n (13,391,215) \n (12,139,535)\n\n  \n    \n   \n\nTotal Liabilities, Stockholders’ Deficit \n$17,002,053  \n$15,640,191 \n\n \n\nThe accompanying notes are an integral part of\nthese consolidated financial statements.\n\n \n\nF-5\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**CONSOLIDATED STATEMENTS OF OPERATIONS**\n\n**FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024**\n\n \n\n  \n2025  \n2024 \n\nRevenues: \n   \n  \n\nOil, NGL and Gas Sales \n$1,926,442  \n$2,246,073 \n\nOther Operating Revenue \n 20,761  \n 16,266 \n\nTotal Revenues \n 1,947,203  \n 2,262,339 \n\n  \n    \n   \n\nCosts and Expenses: \n    \n   \n\nOil and Gas Lease Operating \n 1,323,333  \n 1,983,173 \n\nSeverance Taxes \n 73,377  \n 81,832 \n\nImpairment \n 27,250  \n 400,719 \n\nDepreciation, Depletion, Amortization, and Accretion \n 259,438  \n 308,523 \n\nSettlement of Asset Retirement Obligation \n (18,710) \n - \n\nGeneral and Administrative \n 1,632,103  \n 1,633,740 \n\nCredit Loss Expense \n 137,221  \n 450,743 \n\nLegal and Accounting \n 446,593  \n 582,413 \n\nMarketing \n 302,455  \n 347,044 \n\nTotal Costs and Expenses \n 4,183,060  \n 5,788,187 \n\n  \n    \n   \n\nGain on Turnkey Drilling Programs \n 1,322,149  \n 1,607,677 \n\n  \n    \n   \n\nLoss from Operations \n (913,708) \n (1,918,171)\n\n  \n    \n   \n\nOther Income (Expense): \n    \n   \n\nInterest Expense \n (404,051) \n (304,873)\n\nInterest Income \n 66,079  \n 46,528 \n\nGain on Sale of Assets \n -  \n 17,500 \n\nTotal Other Expense (net) \n (337,972) \n (240,845)\n\nNet Loss \n (1,251,680) \n (2,159,016)\n\n  \n    \n   \n\nBasic and Diluted Loss Per Share \n$(0.01) \n$(0.03)\n\n  \n    \n   \n\nWeighted average number of common shares outstanding, basic and diluted \n 96,600,302  \n 77,278,047 \n\n \n\nThe accompanying notes are an integral part of\nthese consolidated financial statements.\n\n \n\nF-6\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**CONSOLIDATED STATEMENTS OF STOCKHOLDERS**’\n**DEFICIT**\n\n**FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024**\n\n \n\n** **** **\n**Common Stock**** **** **\n** **** **** **\n** **** **** **\n** **** **\n\n** **** **\n**Number\nShares\nIssued and\nOutstanding**** **** **\n**Amount**** **** **\n**Additional Paid in\nCapital**** **** **\n**Accumulated  Deficit**** **** **\n**Total\nStockholders’\nDeficit**** **\n\nBalance,  December 31, 2023 \n 70,564,188  \n$70,564  \n$54,619,236  \n$(90,133,509) \n$(35,443,709)\n\nStock issued in lieu of Cash Compensation \n 1,299,641  \n 1,299  \n 34,700  \n -  \n 35,999 \n\nPreferred Series B 3.5% Dividend \n -  \n -  \n -  \n (653,730) \n (653,730)\n\nPreferred Series B Retirement & Conversion to Common \n 24,736,473  \n 24,737  \n 25,096,547  \n -  \n 25,121,284 \n\nEquity and Debt Restructuring \n -  \n -  \n 1,328,071  \n (368,434) \n 959,637 \n\nNet Loss \n -  \n -  \n -  \n (2,159,016) \n (2,159,016)\n\nBalance,  December 31, 2024 \n 96,600,302  \n 96,600  \n 81,078,554  \n (93,314,689) \n (12,139,535)\n\nNet Loss \n -  \n -  \n -  \n (1,251,680) \n (1,251,680)\n\nBalance,  December 31, 2025 \n 96,600,302  \n$96,600  \n$81,078,554  \n$(94,566,369) \n$(13,391,215)\n\n \n\nThe accompanying notes are an integral part\nof these consolidated financial statements.\n\n \n\nF-7\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**CONSOLIDATED STATEMENTS OF CASH FLOWS**\n\n**FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024**\n\n** **\n\n  \n2025  \n2024 \n\nCASH FLOWS FROM OPERATING ACTIVITIES: \n   \n  \n\nNet Loss \n$(1,251,680) \n$(2,159,016)\n\nAdjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: \n    \n   \n\nDepreciation, Depletion, and Amortization \n 259,438  \n 308,523 \n\nImpairment \n 27,250  \n 400,719 \n\nGain on Sale of Assets \n -  \n (17,500)\n\nGain on Turnkey Drilling Programs \n (1,322,149) \n (1,607,677)\n\nCredit Loss Expense \n 137,221  \n 450,743 \n\nSettlement on Asset Retirement Obligation \n (78,839) \n (151,856)\n\nStock-Based Compensation \n -  \n 35,999 \n\nAccretion of Debt Restructure Note Payable Interest \n 131,822  \n 31,514 \n\nRight of Use Asset Depreciation \n 14,615  \n 7,167 \n\n(Increase) Decrease in: \n    \n   \n\nOther & Revenue Receivables \n 69,924  \n (169,046)\n\nPrepaid Expenses and Other Assets \n (62,400) \n (44,244)\n\nIncrease (Decrease) in: \n    \n   \n\nAccounts Payable and Accrued Expenses \n (625,022) \n 552,911 \n\nRoyalties Payable \n -  \n (1,092)\n\nNet Cash Used in Operating Activities \n (2,699,820) \n (2,362,855)\n\n  \n    \n   \n\nCASH FLOWS FROM INVESTING ACTIVITIES: \n    \n   \n\nExpenditures for Oil and Gas Properties \n (1,490,736) \n (4,914,671)\n\nAcquisition of property \n (1,500,000) \n - \n\nProceeds from Turnkey Drilling Programs \n 5,575,000  \n 8,258,791 \n\nNet Cash Provided by Investing Activities \n 2,584,264  \n 3,344,120 \n\n  \n    \n   \n\nCASH FLOWS FROM FINANCING ACTIVITIES: \n    \n   \n\nProceeds from Long-Term Debt \n 500,000  \n 1,400,000 \n\nPrincipal Payments on Long-Term Debt \n (11,613) \n (6,623)\n\nNet Cash Provided by Financing Activities \n 488,387  \n 1,393,377 \n\n  \n    \n   \n\nNet Increase in Cash, Cash Equivalents, and Restricted Cash \n 372,831  \n 2,374,642 \n\n  \n    \n   \n\nCash, Cash Equivalents, and Restricted Cash at Beginning of Year \n 7,902,163  \n 5,527,521 \n\n  \n    \n   \n\nCash, Cash Equivalents, and Restricted Cash  at End of Year \n$8,274,994  \n$7,902,163 \n\n  \n    \n   \n\nSupplemental Schedule of Cashflow information \n    \n   \n\nCash Paid for Interest \n$272,229  \n$273,360 \n\nCash Paid for Taxes \n$9,218  \n$8,150 \n\n  \n    \n   \n\nSupplemental Schedule of Non-Cash Investing and Financing Transactions: \n    \n   \n\nConversion of Preferred Stock to Common \n$-  \n$24,664,543 \n\nAdditions to asset retirement obligation \n 112,417  \n 865 \n\nRevisions to asset retirement obligations \n (41,622) \n 63,224 \n\n** **\n\nThe accompanying notes are an integral part of\nthese consolidated financial statements.\n\n \n\nF-8\n\n[Table of Contents](#toc) \n\n \n\n**ROYALE ENERGY, INC.**\n\n**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**\n\n \n\n**NOTE 1**– **SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**\n\n \n\nThis summary of significant accounting policies of Royale Energy,\nInc. (in these notes sometimes called “we”, “us”, “our”, “the Company”) is presented\nto assist in understanding our financial statements.\n\n \n\nThese consolidated financial statements include the accounts of Royale\nEnergy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating\nassets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible\nfor their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States\nof America and have been consistently applied in the preparation of the financial statements.\n\n \n\nDescription of Business\n\n \n\nWe are an independent oil and gas producer and we also perform turnkey\ndrilling operations. We own wells and leases in major geological basins located primarily in California, Texas, and Oklahoma, and offer\nfractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which\ndo not include the use of debt financing.\n\n \n\nUse of Estimates\n\n \n\nThe accompanying consolidated financial statements have been prepared\nin conformity with accounting principles generally accepted in the United States of America and requires management to make estimates\nand assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the\ndate of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could\ndiffer from those estimates.\n\n \n\nEstimated quantities of crude oil and condensate, Natural Gas Liquids\n(“NGLs”) and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this\nForm 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate,\nNGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and\nnatural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological\ninterpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and\nnatural gas that are ultimately recovered. See Note 18 – Supplemental Information About Oil and Gas Producing Activities (Unaudited)\nto our Consolidated Financial Statements for further detail.\n\n \n\nOther items subject to estimates and assumptions include the carrying\namounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation\nallowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from\nthese estimates.\n\n \n\nLiquidity and Going Concern\n\n \n\nManagement evaluated whether conditions and events, considered in\nthe aggregate, raise substantial doubt about the Company’s ability to continue as a going concern within one year after\nthe date the accompanying consolidated financial statements are issued. The accompanying financial statements have been prepared\nassuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in\nthe normal course of business. The consolidated financial statements do not include any adjustments related to the recoverability\nand classification of recorded asset amounts or the amounts and classifications of liabilities that might result from the outcome of\nthis uncertainty.\n\n \n\nThe primary sources of liquidity have historically been issuances\nof common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise\nto substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from\nthe issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business\nand the sale of non-strategic assets.\n\n \n\nOur 2025 consolidated financial statements reflect a working capital\ndeficiency of $11,550,839, an accumulated deficit of $94,566,369 and recurring net losses from operations. These factors raise substantial\ndoubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments\nthat might be necessary if we are unable to continue as a going concern.\n\n \n\nF-9\n\n[Table of Contents](#toc) \n\n \n\nManagement’s plans to alleviate the going concern by implementing\ncost control measures that include the reduction of overhead costs and through the sale of non-strategic assets, and to seek additional\ndebt and/or equity financing. There is no assurance that additional financing will be available when needed or that management will be\nable to obtain financing on terms acceptable to us and whether we will generate positive operating cash flow or become profitable. If\nwe are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce\noverhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will\nbe successful.\n\n \n\nRevision of Previously Issued Financial Statements\n\n \n\nDuring the preparation of the 2025 consolidated financial\nstatements, immaterial errors were identified related to:  \n\n \n\n●Severance taxes were inappropriately netted against Sale of Oil and Gas Revenue within our statement of operations, resulting in the understatement of Sale of Oil & Gas Revenue and Lease Operating Expense of $81 thousand during 2024. \n\n   \n\n●Errors in the calculation of the tax basis of Oil and Gas Properties resulted in a $2.4 million overstatement of the disclosure of deferred tax assets and the related valuation allowance, resulting in zero net impact on Net Deferred Tax Assets.  \n\n   \n\n●An error in the treatment of future income tax expense resulted in an understatement of approximately $2 million (unaudited) in our disclosures of the standardized measure of discounted future cash flows as of December 31, 2024.  In addition, there were errors in the calculation of the various changes in the standardized measure (unaudited). \n\n   \n\n●Accrued liabilities and accumulated deficit were overstated by $189 thousand as a result of an error that occurred prior to 2023. This overaccrual was corrected by the Company during the quarter ended June 30, 2025.  \n\n   \n\n●Settlements of ARO liabilities of approximately $152 thousand were incorrectly presented in the statement of cash flows during the year ended December 31, 2024. \n\n \n\nWe assessed the materiality of the errors, both quantitatively\nand qualitatively, in accordance with the SEC’s Staff Accounting Bulletin No. 99 and Staff Accounting Bulletin No.\n108, and concluded the errors were not material to any of our previously issued financial statements. Notwithstanding the\nresults of the assessment, we have revised the applicable items in our previously issued financial statements to\ncorrect these misstatements. Accordingly, all consolidated financial information contained in\nthese consolidated financial statements and the accompanying notes have been revised to reflect the corrections.\nPreviously reported financial information will be corrected in future filings, as applicable. \n\n \n\nRestricted Cash\n\n \n\nWe sponsor turnkey drilling arrangements in proved and unproved properties.\nThe contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns\nan undivided interest in the well bore at the completion of the well. A portion of the funds received in advance of the drilling of a\nwell from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate\nthese funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant.\nOnce the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling\nas restricted cash. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current\nAssets.\n\n \n\nThe following table provides a reconciliation of cash, cash equivalents,\nand restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement\nof cash flows.\n\n \n\n** **** **\n**Year Ended December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nCash and cash equivalents \n$1,099,044  \n$1,877,163 \n\nRestricted cash \n 7,175,950  \n 6,025,000 \n\nTotal cash, cash equivalents, and restricted cash shown  in the statement of cash flows \n$8,274,994  \n$7,902,163 \n\n \n\nOther Receivables, net\n\n \n\nOur other receivables consist of receivables from direct working interest\ninvestors and industry partners. We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology.\nUnder this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current\nconditions, and reasonable and supportable forecasts of future economic conditions. The allowance account is increased or decreased in\nresponse to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables.\n\n \n\nAll amounts considered uncollectible are charged against the allowance\naccount and recoveries of previously charged off accounts are added to the allowance. At December 31, 2025 and 2024, we established an\nallowance for expected credit loses of $2,302,873 and $2,194,552, respectively, for receivables from direct working interest investors\nwhose expenses on non-producing wells were unlikely to be collected from revenue.\n\n \n\nF-10\n\n[Table of Contents](#toc) \n\n \n\nRevenue Receivables\n\n \n\nOur revenue receivables consist of receivables related to the sale\nof our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically,\nwe have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables\nis not currently necessary.\n\n \n\nAllowance for Credit Losses\n\n \n\nWe measure our allowance for losses on other receivables including,\nunder ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the\nperiod indicated:\n\n \n\nBalance at December 31, 2023 \n$1,837,551 \n\nProvision for credit loss \n 450,743 \n\nWrite-offs charged against the allowance \n (93,742)\n\nBalance at December 31, 2024 \n$2,194,552 \n\n  \n   \n\nBalance at December 31, 2024 \n$2,194,552 \n\nProvision for credit loss \n 137,221 \n\nWrite-offs charged against the allowance \n (28,900)\n\nBalance at December 31, 2025 \n$2,302,873 \n\n \n\nEquity Method Investments\n\n \n\nEquity method investments are assessed for impairment whenever changes\nin the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method\nand Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment\nis written down to fair value, and the amount of the write-down is included in income.\n\n \n\nThe Company’s only equity method investment is its holding in the\nRMX joint venture. At December 31, 2025, the Company had no balance related its investment in RMX, due to previously recognized impairments.\n\n \n\nRevenue Recognition\n\n \n\nA significant portion of our revenues are derived from the sale of\ncrude oil, condensate, NGL and natural gas under spot and term agreements with our customers as follows:\n\n \n\n** **** **\n**Year Ended December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nOil & Condensate Sales \n$1,664,862  \n$2,010,742 \n\nNatural Gas Sales \n 257,684  \n 231,765 \n\nNGL Sales \n 3,896  \n 3,566 \n\n  \n$1,926,442  \n$2,246,073 \n\n \n\nThe pricing in our hydrocarbon sales agreements are determined using\nvarious published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under\nour agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices\nrise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such,\nwe do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product\nspecifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity,\nand other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.\n\n \n\nIn limited cases, we may also collect advance payments from customers\nas stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance\nsheets.\n\n \n\nF-11\n\n[Table of Contents](#toc) \n\n \n\nUnder our hydrocarbon sales agreements, the entire consideration amount\nis variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct\nunits of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for\ncompleted deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance\nobligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire\nproduction from the dedicated wells or specified contractual volumes of hydrocarbons.\n\n \n\nWe often serve as the operator for jointly owned oil and gas properties.\nAs part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating\narrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our\nagreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded\nas cost reimbursements of Lease Operating Expense.\n\n \n\nWe commonly market the share of production belonging to other working\ninterest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative\narrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore,\nwe act as a principal only in regard to the sale of our share of production and recognize revenue for the volumes associated with our\nnet production.\n\n \n\nWe frequently sells a portion of the working interest in each well\nwe drill or participate in to third-party investors and retains a portion of the prospect for our own account. We typically guarantee\na cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and\nthe actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability\nas Deferred Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial\nviability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual\ncost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss.\n\n \n\nCrude oil and condensate\n\n \n\nFor the crude sales agreements, we satisfy our performance obligations\nand recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or\nvessels.\n\n \n\nNatural Gas and NGLs\n\n \n\nWhen selling natural gas and NGLs, we engage midstream entities to\nprocess our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural\ngas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the\ntailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate\nis the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership\nof the natural gas and NGLs.\n\n \n\nThe amounts due to midstream entities for gathering and processing\nservices are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations,\nsince we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation\ncost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed\nnatural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations\nare complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate\nof the processing plant or an alternative delivery point requested by the customer.\n\n \n\nTurnkey Drilling Obligations\n\n \n\nWe manage these Turnkey Agreements for the participants of the well.\nThe collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on\nthe Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and\n932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance\nobligation of the Turnkey Agreement has been satisfied.\n\n \n\nOther Operating Revenue\n\n \n\nFor the years ended December 31, 2025 and 2024, we recognized $20,761\nand $16,266, respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes.\n\n \n\nF-12\n\n[Table of Contents](#toc) \n\n \n\nOil and Gas Property and Equipment\n\n \n\n**Successful Efforts**\n\n \n\nWe use the “successful efforts” method to account for\nour exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis\nwith certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive\nwells. We amortize the costs of productive wells under the unit-of-production method.\n\n \n\nWe carry, as an asset, exploratory well costs when the well has found\na sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing\nthe reserves and the economic and operating viability of the well. Exploratory well costs not meeting these criteria are charged to expense.\nOther exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of\nproved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.\n\n \n\nCapitalized exploratory drilling and development costs associated\nwith productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed\nreserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production\nmethod, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction\npoints at the outlet valve on the lease or field storage tank.\n\n \n\n**Production Cost**\n\n \n\nProduction costs are expensed as incurred. Production involves lifting\nthe oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function\nnormally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate\nand maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes\nreferred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs\non the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative\nexpenses related to the production activity.\n\n \n\n**Depreciation, Depletion and Amortization**\n\n \n\nDepreciation, depletion and amortization, based on cost less estimated\nsalvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is\nbased on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance,\nare expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired.\n\n \n\nThe project drilling phase commences with the development of the detailed\nengineering design and ends when the assets are ready for their intended use. Interest costs, to the extent they are incurred to finance\nexpenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of\nthe related assets.\n\n \n\n**Impairment**\n\n \n\nWe evaluate our oil and gas producing properties, including capitalized\ncosts of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the\ncarrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset\nand its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value\nof the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical\ngrouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate,\ndiscrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted\nfuture net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based\non time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop\nacreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses\nin our consolidated statements of operations. During 2025 we recorded impairment losses of $27,250, on various capitalized lease and\nland costs where the carrying value exceeded the estimated fair value. In 2024 we recorded impairment losses of $400,719.\n\n \n\nUpon the sale or retirement of a complete field of a proved property,\nwe eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements of operations. Upon the\nsale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is\nrecognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are\naccounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling\nagreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received\nunder the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized\nand accounted for under the “successful efforts” method.\n\n \n\nF-13\n\n[Table of Contents](#toc) \n\n \n\n**Asset Retirement Obligations**\n\n \n\nThe Asset Retirement and Environmental Obligations Topic of the ASC\n410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset\nbe recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated\nincrease in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset\nretirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense\nwill be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included\nas part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820\nguidance) of the ARO is a Level 3 measurement using expected future cash outflows discounted at our credit-adjusted risk-free interest\nrate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the\nacquisition, development, and operation of a long-lived asset.\n\n \n\nLong-Lived Assets Classified as Held for Sale\n\n \n\nWe classify long-lived assets as Held-for-Sale when the criteria of\nASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below:\n\n \n\n \n●\nManagement has committed to a plan to sell the asset;\n\n \n \n \n\n \n●\nThe asset group is available for immediate sale in its present condition;\n\n \n \n \n\n \n●\nAn active program is underway to locate potential buyers;\n\n \n \n \n\n \n●\nThe sale is probable within one year;\n\n \n \n \n\n \n●\nThe asset group is being marketed at a price that is reasonable relative\nto its current fair value; and\n\n \n \n \n\n \n●\nActions required to complete the plan indicate that it is unlikely that significant changes to\nthe plan will be made or the plan will be withdrawn.\n\n \n\nAssets held for sale are carried at the lower of cost or fair market\nvalue less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration,\nthe associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 3, below).\n\n \n\nTurnkey Drilling\n\n \n\nWe sponsor turnkey drilling agreement arrangements in proved and unproved\nproperties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations,\nand then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce\nany basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess\nof all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred\non behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations\nhave been fulfilled.\n\n \n\nThe contracts require the participants pay us the full contract price\nupon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant\nretains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating\ncosts. We retain legal title to the lease. The participants purchase a working interest directly in the well bore.\n\n \n\nIn these working interest arrangements, the participants are responsible\nfor sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability\nfor the cost of operations after drilling is completed and the interest is conveyed to the participant.\n\n \n\nA certain portion of the turnkey drilling participant’s funds\nreceived are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling\nis delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31,\n2025 and 2024, we had Deferred Drilling Obligations of $14,277,496 and $11,457,996, respectively. During 2025, we disposed of $2,755,500\nof drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian\nbasin, while incurring expenses of $1,433,351, resulting in a gain of $1,322,149. During 2024, we disposed of $6,562,721 of drilling\nobligations as we participated in the drilling and completion of four gross (0.0722 net) wells in Texas Permian basin, while incurring\nexpenses of $4,955,044, resulting in a gain of $1,607,677.\n\n \n\nF-14\n\n[Table of Contents](#toc) \n\n \n\nIf we are unable to drill the wells, and a suitable replacement well\nis not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included\nin restricted cash are amounts for use in completion of turnkey drilling programs in progress.\n\n \n\nEquipment and Fixtures\n\n \n\nEquipment and fixtures are stated at cost and depreciated over the\nestimated useful lives of the assets, which range from three to seven years, using the straight-line method. Repairs and maintenance\nare charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the\naccounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of\nthe property nor appreciably prolong its life, are charged to expense as incurred.\n\n \n\nLoss Per Share\n\n \n\nBasic and diluted losses per share are calculated as follows:\n\n \n\n  \nYear Ended December 31, \n\n  \n2025  \n2024 \n\n  \nBasic  \nDiluted  \nBasic  \nDiluted \n\nNet Loss \n$(1,251,680) \n$(1,251,680) \n$(2,159,016) \n$(2,159,016)\n\nLess:  Preferred Stock Dividend \n -  \n -  \n 653,730  \n 653,730 \n\nLess:  Non-cash Restructuring Inducements \n -  \n -  \n 674,341  \n 674,341 \n\nNet Loss Attributable to Common Shareholders \n (1,251,680) \n (1,251,680) \n (3,487,087) \n (3,487,087)\n\nWeighted average common shares outstanding \n 96,600,302  \n 96,600,302  \n 77,278,047  \n 77,278,047 \n\nEffect of dilutive securities \n -  \n -  \n -  \n - \n\nWeighted average common shares, including Dilutive effect \n 96,600,302  \n 96,600,302  \n 77,278,047  \n 77,278,047 \n\nPer share: \n    \n    \n    \n   \n\nNet Loss \n$(0.01) \n$(0.01) \n$(0.03) \n$(0.03)\n\n  \n\nIncome Taxes\n\n \n\nWe utilize the asset and liability approach to measure deferred tax\nassets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance\nwith the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and\nrates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management,\nit is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.\n\n \n\nThe provision for income taxes is based on pretax financial accounting\nincome. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax\nbasis of assets and liabilities and their reported net amounts.\n\n \n\nFair Value Measurements\n\n \n\nAccording to Fair Value Measurements and Disclosures guidance as provided\nby ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent\nto initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs\nused to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the\nmeasurements on earnings for the period.\n\n \n\nFair value is defined as the price that would be received to sell\nan asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining\nfair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to\nthe extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments,\nincluding cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance\nsheet dates because of their generally short maturities.\n\n \n\nThe fair value hierarchy distinguishes between (1) market participant\nassumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions\nabout market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The\nfair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for\nidentical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value\nhierarchy are described below:\n\n \n\nLevel 1: Quoted prices (unadjusted) in active markets that are accessible\nat the measurement date for assets or liabilities.\n\n \n\nF-15\n\n[Table of Contents](#toc) \n\n \n\nLevel 2: Directly or indirectly observable inputs as of the reporting\ndate through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices\nin markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies\nthat do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors,\nare corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.\n\n \n\nLevel 3: Unobservable inputs that are supported by little or no market\nactivity and reflect the use of significant management judgment. These values are generally determined using pricing models for which\nthe assumptions utilize management’s estimates of market participant assumptions.\n\n \n\nAs of December 31, 2025, we have financial liabilities, including\noutstanding notes, that have been measured at fair value on a nonrecurring basis. The carrying values of financial instruments comprising\ncash, payables, and receivables, approximate fair values due to the short-term maturities of these instruments and are classified as\nLevel 1 in the fair value hierarchy. The carrying amounts of cash and cash equivalents, accounts receivable, and other current assets\napproximate their fair values due to the short-term maturities of these instruments.\n\n \n\nAs part of the Series B Convertible Preferred Stock restructuring\ntransaction, the Company issued Series 2024 Senior Unsecured Promissory Notes in exchange for approximately 10% of the outstanding Series\nB shares. These notes have varying interest rate periods:\n\n \n\n \n●\n0.0% interest through December 31, 2025\n\n \n\n \n●\n5.0% interest from January 1, 2026, to December 31, 2027\n\n \n\n \n●\n8.0% interest from January 1, 2028, to June 30, 2029 (maturity date)\n\n \n\nThe fair value of these notes was determined using a discounted cash\nflow model based on an assumed market interest rate of 11.912%, reflecting the Company’s estimated borrowing rate (Wall Street\nJournal Prime Rate plus 400 basis points as of October 1, 2024). Based on this valuation methodology, the following table sets out the\nfair value and carrying value of the notes issued.\n\n \n\nThe fair value measurement of these notes is classified as Level 3\nin the fair value hierarchy due to the use of significant unobservable inputs, including management’s assessment of credit risk\nand cash flow projections. The carrying amount of these notes will be accreted to their face value over the term using the effective\ninterest rate method.\n\n \n\nThe carrying values and estimated fair values of these notes were\nas follows:\n\n \n\n** **** **\n**Carrying Value**** **** **\n**Fair\nValue**** **\n\nDecember 31, 2025 \n   \n  \n\nSeries 2024 Senior Unsecured Promissory Notes \n$2,221,112  \n$2,369,158 \n\nWalou Note \n 1,900,000  \n 2,032,792 \n\nDecember 31, 2024 \n    \n   \n\nSeries 2024 Senior Unsecured Promissory Notes \n 2,057,775  \n 2,116,983 \n\nWalou Note \n 1,400,000  \n 1,497,847 \n\n \n\nAdditionally, the restructuring included the issuance of 25,000,000\nstock warrants exercisable at $0.10 per share, expiring June 30, 2029. The warrants were valued using the Black-Scholes-Merton model,\nresulting in a fair value of $0.04 per warrant or an aggregate value of $995,503, which is classified as equity and not a liability for\nfair value measurement purposes.\n\n \n\nSee Note 2 – Oil and Gas Properties, Equipment and Fixtures\nfor further discussion of our asset retirement obligations and property transactions.\n\n \n\nAccounts Payable and Accrued Expenses\n\n \n\nAt December 31, 2025 and 2024, the components of accounts payable\nand accrued expenses consisted of:\n\n \n\n  \n2025  \n2024 \n\nTrade Payables and accruals \n$3,235,457  \n$3,946,583 \n\nDirect working interest investors related accruals \n 2,050,399  \n 2,322,690 \n\nCurrent drilling efforts accrued expenses \n 335,041  \n 120,102 \n\nAccrued Liabilities \n 210,516  \n 210,516 \n\nEmployee related accruals \n 197,175  \n 169,079 \n\nDeferred rent \n 5,290  \n 7,855 \n\n  \n$6,033,878  \n$6,776,825 \n\n \n\nF-16\n\n[Table of Contents](#toc) \n\n \n\nAccrued – Non-current\n\n \n\nAt December 31, 2025 and 2024, we had non-current accrued liabilities\nof $12,386 and accrued unpaid guaranteed payment of $90,000. These were due to certain Matrix Oil Corp (“Matrix”) principals,\nfrom periods prior to the merger with the Matrix entities during March of 2018.\n\n \n\nBusiness Combinations\n\n \n\nFrom time-to-time, we acquire businesses in the oil and gas industry.\nWe primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated\nfinancial statements from the date of acquisition.\n\n \n\nWe recognize, separately from goodwill, the identifiable assets acquired\nand liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date\nas the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in\nthe acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the\nfair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date\nis incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items\nfor which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however,\nthis period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement\nperiod will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party\ntransaction-related costs as expense currently in the period in which they are incurred.\n\n \n\nIf the set of assets and activities acquired is not considered a business\nunder GAAP, the acquisition is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model,\nthe cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values,\nand no goodwill is recognized. The Pradera Fuego Acquisition was accounted for as an asset acquisition under GAAP.\n\n \n\nChanges in Accounting Standards\n\n \n\n**Recently Adopted**\n\n \n\nIn December 2023, the FASB issued Accounting Standards Update (“ASU”)\n2023-09, Income Taxes (Topic 740) (“ASC 740”): Improvements to Income Tax Disclosures (“ASU 2023-09”) to expand the\ndisclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective\nfor annual periods beginning January 1, 2025, with early adoption permitted. We have adopted ASU 2023-09 for the annual period ended\nDecember 31, 2025 and have conformed our income tax disclosures in Note 4 to reflect the new requirements.\n\n \n\nIn November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic\n280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s\nannual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December\n15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The Company adopted this update effective January\n1, 2024. See Note 14** - **Segments. The adoption and implementation of this standard did not have a material impact on\nthe Company’s disclosures.\n\n \n\n**Recently Issued, Not Yet Adopted**\n\n** **\n\nWe have reviewed all other recently issued accounting pronouncements\nthat are not yet effective and have determined that none are currently expected to have a material impact on our consolidated financial\nstatements upon adoption.\n\n \n\nIn November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic\n220-40) Reporting Comprehensive Income-Expense Disaggregation Disclosures, which broadens the disclosures required for certain costs\nand expenses in the Company’s annual and interim consolidated financial statements. This ASU is effective prospectively for fiscal\nyears beginning after December 15, 2026, and interim reporting periods within fiscal years beginning after December 15, 2027. The Company\nis currently evaluating disclosures related to our annual report for fiscal year 2027.\n\n \n\nF-17\n\n[Table of Contents](#toc) \n\n \n\n**NOTE 2**– **OIL AND GAS PROPERTIES, REAL PROPERTY AND\nEQUIPMENT AND FIXTURES**\n\n \n\nOil and gas properties, real property and equipment and fixtures consist\nof:\n\n \n\n** **** **\n**Year ended December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nOil and Gas \n   \n  \n\nProducing properties, including intangible drilling costs \n$7,229,767  \n$5,764,761 \n\nUndeveloped properties \n 3,237,624  \n 3,339,234 \n\nLease and well equipment \n 3,298,441  \n 3,295,028 \n\nTotal Oil and Gas Properties \n 13,765,832  \n 12,399,023 \n\nAccumulated depletion, depreciation and amortization \n (7,995,503) \n (7,748,190)\n\nNet capitalized costs Total \n$5,770,329  \n$4,650,833 \n\n \n\nCommercial and Other \n2025  \n 2024 \n\nVehicles \n 40,061  \n 40,061 \n\nFurniture and equipment \n 1,103,362  \n 1,103,362 \n\nTotal Commercial and Other \n 1,143,423  \n 1,143,423 \n\nAccumulated depreciation \n (1,139,574) \n (1,137,597)\n\n  \n 3,849  \n 5,826 \n\nNet capitalized costs Total \n$5,774,178  \n$4,656,659 \n\n \n\nThe guidance set forth in the Continued Capitalization of Exploratory\nWell Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory\nwell costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a\nfiscal period. We do not have any capitalized exploratory well costs. Undeveloped properties are not subject to depletion, depreciation\nor amortization.\n\n \n\n**NOTE 3**– **ASSET RETIREMENT OBLIGATION**\n\n \n\nThe Asset Retirement and Environmental Obligations Topic of the ASC\n410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset\nbe recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated\nincrease in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset\nretirement cost, is depreciated over the useful life of the asset.\n\n \n\nThere were no changes in estimates for the years ended December 31,\n2025 and 2024.\n\n \n\n  \n2025  \n2024 \n\nAsset retirement obligation \n   \n  \n\nBeginning of the year \n$5,078,595  \n$4,826,847 \n\nLiabilities incurred during the period \n 112,417  \n 865 \n\nSettlements \n (78,839) \n (151,856)\n\nChanges in Working Interest \n 26,085  \n (4,716)\n\nChanges in estimates \n (67,707) \n 405,440 \n\nAccretion expense \n 7,300  \n 2,015 \n\nEnd of year \n$5,077,852  \n$5,078,595 \n\n  \n\nWe record accretion expense as part of Depreciation, Depletion and\nAmortization. Accretion expense was $7,300 and $2,015 for the years ended December 31, 2025 and 2024, respectively.\n\n \n\nF-18\n\n[Table of Contents](#toc) \n\n \n\n**NOTE 4**– **INCOME TAXES**\n\n \n\nThe components of income (loss) before income taxes were as follows:\n\n \n\n  \n2025  \n2024 \n\n  \n   \n  \n\nU.S. \n$(1,251,680) \n$92,159,014)\n\nNon-U.S. \n$-  \n$- \n\n  \n\nThe reconciliation between the actual provision for income taxes and\nthat computed by applying the U.S. statutory rate to income (loss) before income taxes are outlined below based on the updated requirements\nof ASU 2023-09 for 2025.\n\n \n\n  \n2025  \n  \n\n  \n   \n  \n\nCurrent tax at U.S. statutory rate \n$(222,999) \n 21.00%\n\nState and local income taxes, net of federal taxes \n (37,891) \n 3.57%\n\nForeign Tax Effects \n -  \n -%\n\nEffects of Changes in Tax Law or Rates Enacted in the Current Period \n -  \n -%\n\nEffect of cross-border tax law \n -  \n -%\n\nTax Credits \n -  \n -%\n\nChanges in Valuation Allowance \n 176,562  \n 16.63%\n\nNondeductible/nontaxable items \n    \n   \n\nNondeductible/nontaxable items \n 1,642  \n (0.15%)\n\nChanges in Unrecognized Tax Benefit \n -  \n -%\n\nOther Adjustments \n    \n   \n\nDeferred Adjustment \n 82,686  \n 79%\n\nIncome tax expense \n$-  \n -%\n\n \n\nAs previously disclosed prior to the adoption of ASU 2023-09, the\neffective income tax rate differs from the statutory federal income tax rate as follows\n\n \n\n  \n2024 \n\nTax (benefit) computed at statutory rate of 21% at December 31, 2024,\nrespectively \n$(518,740)\n\n  \n   \n\nIncrease (decrease) in taxes resulting from: \n   \n\nMeals & Entertainment \n 915 \n\nPrior-year true-up for Books \n 2,380,175 \n\nDeferred State Taxes, net of federal benefit \n (102,681)\n\nOther non-deductible expenses \n - \n\nChange in valuation allowance \n (1,759,669)\n\nProvision (benefit) \n$- \n\n \n\nDeferred tax assets and liabilities reflect the net tax effect of\ntemporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income\ntax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not\nthat some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects\nof changes in tax laws and rates on the date of enactment.\n\n \n\nF-19\n\n[Table of Contents](#toc) \n\n \n\nSignificant components of our deferred assets and liabilities at December\n31, 2025 and 2024, respectively, are as follows:\n\n \n\n  \n2025  \n2024 \n\nDeferred Tax Assets (Liabilities): \n   \n  \n\nAccrued Expenses \n$98,999  \n$22,249 \n\nNet Operating Loss \n 9,450,310  \n 9,288,524 \n\nAccretion \n 615,894  \n 613,254 \n\nShare-Based Compensation \n 86,510  \n 86,510 \n\nCharitable Contributions Carry Forward \n 2,796  \n 2,743 \n\nOther \n    \n 14,266 \n\nAllowance for Doubtful Accounts \n 599,207  \n 571,022 \n\nInterest Expense Limitations \n    \n 67,221 \n\nOil and Gas Properties and Fixed Assets \n 3,292,967  \n 3,320,659 \n\nInvestment in RMX Joint Venture \n 139,969  \n 123,640 \n\nTotal deferred tax assets \n 14,286,652  \n$14,110,089 \n\nValuation Allowance \n (14,286,652) \n (14,110,089)\n\nNet Deferred Tax Asset \n$-  \n$- \n\n \n\nDuring the current year audit, it was determined that there were two\nimmaterial errors in the 2024 income tax disclosures. The deferred tax asset for Oil and Gas Properties and Fixed Assets was overstated\nby $2.4 million. The error was caused by two different items. The first error was to record a deferred tax liability in work in process\nwhere none should have been recorded. The second error was to have recorded a deferred tax liability twice related to the book impairment\non oil and gas properties. Both of these changes are completely offset by an equal offsetting change to the valuation allowance resulting\nin a net impact of $0 on the face of the financials. Only the income tax footnote disclosures were impacted by these errors.\n\n \n\nAs of December 31, 2025, management reviewed the reliability of our\nnet deferred tax assets, and due to our continued cumulative losses, we concluded it is not “more-likely-than-not” our deferred\ntax assets will be realized. As a result, we have continued to record a full valuation allowance against the deferred tax assets. We\nwill assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries\nhave available net operating loss carryforwards of $20.5 million generated in tax years ended before January 1, 2018, which if not utilized,\nexpire in varying amounts between 2026 and 2037. We have $13.7 million net operating loss carryforwards generated after December 31,\n2017, which can be carried forward indefinitely.\n\n \n\nAs of December 31, 2025, we did not recognize a liability for uncertain\ntax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences\nsuch as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized\ntax benefits to change significantly over the next 12 months. The tax years of 2020 through 2024 remain open to examination by the tax\njurisdictions in which we file income tax returns.\n\n \n\nNet income taxes paid (received) during the years ended December 31,\n2025 and 2024, by federal and state jurisdiction (all states combined), were as follows:\n\n \n\n** **** **\n**2025**** **** **\n**2024**** **\n\nFederal \n$-  \n$- \n\nState \n 9,218  \n 8,150 \n\nTotal income taxes paid, net \n$11,243  \n$10,174 \n\n  \n\n**NOTE 5 **– **SERIES B PREFERRED STOCK**\n\n \n\nPursuant to the terms of the merger completed in 2018, all Class A\nlimited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our Common stock using\nconversion ratios according to the relative value of the Class A limited partnership interests, and $20,124,000 of Matrix Investments\npreferred limited partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock. The Series\nB Convertible Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one\nshare of Series B Convertible Preferred Stock.\n\n \n\nFor 2024, the board authorized the payment of each quarterly dividend\nof Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the\nquarter. For the year ended December 31, 2023, we issued 62,899 shares with a value of $629,007. During 2024, no cash was used to pay\ndividends on Series B preferred shares.\n\n \n\nOn October 11, 2024, we completed a significant equity restructuring\ntransaction, eliminating our Series B, 3.5% Convertible Preferred Stock. See Note 14.\n\n \n\n**NOTE 6**– **COMMON STOCK**\n\n \n\nDuring 2024, we issued shares of our Common Stock in lieu of cash\npayments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’\nDeficit. Common stock was also issued on October 11, 2024, when we completed a significant equity restructuring transaction, see Note\n14.\n\n \n\nF-20\n\n[Table of Contents](#toc) \n\n \n\n**NOTE 7**– **LEASES**\n\n \n\nDuring 2024, we had one office lease, the location of our corporate\noffices. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with\ninitial monthly payments of $6,922 with escalations. We also rent office space on a month-to-month basis in Santa Barbara, California,\nthe location of our CEO for $1,000 per month. In addition, we have a finance lease for miscellaneous small office equipment, which commenced\nin the fourth quarter of 2024 with an 84-month term and an original balance of $71,622.\n\n \n\n**Lease Obligations**** **\n**Operating Lease Obligations**** **** **\n**Financing Lease Obligations**** **** **\n**Total   Lease Obligations**** **\n\n2026 \n$93,492  \n$19,080  \n$112,572 \n\n2027 \n -  \n 19,080  \n 19,080 \n\n2028 \n -  \n 19,080  \n 19,080 \n\nThereafter \n -  \n 14,310  \n 14,310 \n\nTotal undiscounted lease payments \n 93,492  \n 71,550  \n 165,042 \n\nLess:  Amount representing interest \n 4,308  \n 15,110  \n 19,418 \n\nTotal Operating & Financing lease liabilities \n 89,184  \n 56,440  \n 145,624 \n\nCurrent lease liabilities as of December 31, 2025 \n 89,184  \n 13,054  \n 102,238 \n\nLong-term lease liabilities as of December 31, 2025 \n$-  \n$43,386  \n$43,386 \n\n  \n\nWe have elected the short-term lease recognition exemption for all\nleases with an original term of 12 months or less. This means, for those leases that qualify, we will not recognize rights of use (“ROU”)\nassets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases. We elected\nthe practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases,\nwe have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized\nROU and lease liability.\n\n \n\nThe amounts are as follows:\n\n \n\n  \nYear ended December 31, \n\n  \n2025  \n2024 \n\nOperating lease expense \n$119,658  \n$161,858 \n\nFinancing lease expense \n 21,303  \n 17,567 \n\nShort Term - field \n 6,000  \n 6,000 \n\nTotal lease expense \n$146,961  \n$185,425 \n\n \n\nThe following tables summarized the operating and financing lease\nobligations.\n\n \n\n** **** **\n**Debit/Credit**** **\n\n** **** **\n**Financing\nLeases**** **** **\n**Operating Leases**** **** **\n**Total**** **\n\nRight of Use Asset - Leases \n$54,655  \n$89,184  \n$143,839 \n\nLeases - Current \n (9,725) \n (89,184) \n (98,909)\n\nLeases - Non-current \n (44,930) \n -  \n (44,930)\n\n \n\nOur two office leases do not contain implicit interest rates that\ncan be readily determined. As a result, we used the best estimate of our incremental borrowing rate. At December 31, 2025 and 2024 the\nweighted average annual discount rate for our operating leases was 4.83% and the weighted average remaining term was 3 and 4 years, respectively.\nThe weighted average annual discount rate for our finance lease was 11.91% for 2025 and 2024, and the weighted average remaining term\nwas 6 and 7 years.\n\n \n\n**NOTE 8**– **RELATED-PARTY TRANSACTIONS**\n\n \n\nAt December 31, 2025, and 2024, we had a receivable balance of $22,266\nand $22,226 respectively, due from Stephen Hosmer, a director and corporate secretary, for normal lease operating expenses, recorded\nin Other Receivables, net.\n\n \n\nAt December 31, 2025 and 2024, we had payables of $23,087 and $23,087,\nrespectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by\nRMX, included in accounts payable and accrued expenses on our Consolidated Balance Sheets.. For the same periods, we also had prepaid\nexpenses and other current assets, and deferred drilling obligations with RMX of $710,590 and $556,019, respectively. During 2025 and\n2024, RMX operated various oil wells we have interests in, from which we received revenues of approximately $236,900 and $372,028 respectively,\nand incurred lease operating costs of approximately $129,450 and $158,664 respectively. At December 31, 2025 and 2024, we had a total\nrevenue receivables of $122,262 and $108,344, respectively, due from RMX and its subsidiary, Matrix Oil Corporation.\n\n \n\nF-21\n\n[Table of Contents](#toc) \n\n \n\nWe had outstanding accrued unpaid guaranteed payments for unpaid salary\ndue to a certain Matrix employee for periods predating joining our company. At December 31, 2025 and 2024, the balance due was $90,000\nwhich is included in the Noncurrent Liabilities on our Consolidated Balance Sheets. At December 31, 2025 and 2024, Royale also had accrued\nunpaid liabilities of $12,386 due to a certain former Matrix employee for periods predating his employment.\n\n \n\nMichael McCaskey, Jeffery Kerns, and Stephen Hosmer, current directors,\neach provide services as directed and at our discretion directly or through an entity controlled by them. The following table sets amounts\npaid to entities owned or controlled by these individuals:\n\n \n\n** **** **\n**2025**** **** **\n**2024**** **\n\nMichael McCaskey \n$60,000  \n$60,000 \n\nJeffery Kerns \n -  \n 4,726 \n\nStephen Hosmer \n 83,873  \n 79,448 \n\n \n\nThe following table sets amounts owed to entities owned or controlled\nby these individuals at December 31, reflected in Accounts Payable and Accrued Expenses on the Consolidated Balance Sheet.\n\n \n\n** **** **\n**2025**** **** **\n**2024**** **\n\nMichael McCaskey \n$21,455  \n$21,455 \n\nJeffery Kerns \n 26,844  \n 26,844 \n\nStephen Hosmer \n 14,783  \n 11,400 \n\n \n\nOn February 7, 2024 the board of directors approved a debt facility\nof up to $3 million. On February 9, 2024, Royale Energy, Inc. entered into a Secured Term Loan Note with Walou Investments, LP, a Texas\nlimited partnership, which is under the direct and indirect control of Johnny Jordan, the Company’s Chief Executive Officer and\na member of the Company’s board of directors. In addition, Mr. Jordan is the beneficial owner of common stock. The initial loan\nto the Company was $1,400,000 which was received on February 9, 2024. The outstanding principal balance of the loan has an annual interest\nrate of 18.00%. On November 1, 2024 the maturity was extended from August 1, 2025 to January 1, 2026. Subsequently, on August 29, 2025,\nthe loan was further extended to April 1, 2027, and the Company executed an additional advance of $500,000 on the loan, increasing the\ntotal outstanding principal balance to $1,900,000. Effective September 1, 2025, the interest rate on the outstanding principal was reduced\nfrom 18.0% to 15.0% per annum.\n\n \n\n**NOTE 9**– **STOCK COMPENSATION PLAN**\n\n \n\nThere were no stock options issued for compensation during 2025 and\n2024.\n\n \n\n**NOTE 10**– **SIMPLE IRA PLAN**\n\n \n\nIn April 1998, we established a Simple IRA plan covering all employees.\nWe will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction\ncontributions up to a limit of 3% of the employee’s compensation for the year. The employer contribution for the years ending December\n31, 2025 and 2024, were $30,333 and $28,653 respectively.\n\n \n\n**NOTE 11**– **ENVIRONMENTAL MATTERS**\n\n \n\nWe have established procedures for the continuing evaluation of our\noperations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors\nthese laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental\nissues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material\nenvironmental investigation, compliance and remediation costs in 2025 or 2024.\n\n \n\nWe are unable to predict whether our future operations will be materially\naffected by these laws and regulations. We believe that legislation and regulations relating to environmental protection will not materially\naffect our results of operations.\n\n \n\n**NOTE 12**– **CONCENTRATIONS**\n\n \n\nWe bid our gas sales on a month-to-month basis and generally sell\nto a single customer without commitment to future gas sales to any particular customer. For both years presented we sold approximately\n36% of our yearly natural gas production to one customer on a month-to-month basis. Since we are able to sell our natural gas to other\nreadily available customers, we believe the loss of any one customer would not have an adverse effect on our overall sales operations.\n\n \n\nF-22\n\n[Table of Contents](#toc) \n\n \n\nWe maintain cash in depository institutions that are guaranteed by\nthe Federal Deposit Insurance Corporation (FDIC) up to $250,000 per institution for our interest-bearing accounts in the years ended\nDecember 31, 2025, and 2024. At December 31, 2025 and 2024, cash in banks exceeded the FDIC limits by approximately $8.0 million and\n$7.6 million, respectively. We have not experienced any losses on deposits.\n\n \n\n**NOTE 13**– **COMMITMENTS AND CONTINGENCIES**\n\n \n\nWe may become involved from time to time in litigation on various\nmatters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will\nhave a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the\ncosts of defending or settling such claims could have a material effect on our business.\n\n \n\nWe sponsor turnkey drilling agreement arrangements in proved and unproved\nproperties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations.\nThe contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling\nactivities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins.\n\n \n\n**Note 14 – Debt and\nEquity Restructuring Transaction**\n\n** **\n\nOn October 11, 2024, we completed a significant equity restructuring\ntransaction, eliminating our Series B, 3.5% Convertible Preferred Stock and simplifying our capital structure. The transaction was executed\nthrough a combination of common stock issuance, warrants, and senior promissory notes in exchange for the retirement of all outstanding\nSeries B Preferred Shares as of June 30, 2024. The preferred holders waived the payment of any unpaid dividends.\n\n \n\nThe restructuring involved the exchange and extinguishment of 2,466,455\nshares of Series B Preferred Stock, which carried an aggregate liquidation preference of $24.7 million. The exchange was structured as\nfollows:\n\n \n\n  1. 90% Conversion to Common Stock – Former holders of the Series B Preferred Stock received 22,198,095 shares of Royale common stock at an exchange ratio of 10 shares of common stock for each share of Series B Preferred Stock.\n\n \n\n \n2.\n10% Conversion to Notes Payable – The remaining portion of the Series B Preferred Stock was\nexchanged for Senior Unsecured Promissory Notes, totaling $1.85 million. These notes bear an interest rate of 0% until December 31,\n2025, increasing to 5% through 2027 and 8% through June 30, 2029, when all principal and interest is due.\n\n \n\n \n3.\nIssuance of Warrants – As part of the exchange, Royale issued 25 million warrants with an\nexercise price of $0.10 per share, expiring on June 30, 2029. The fair value of the warrants was determined to be $959,637 using\na Black-Scholes-Merton model.\n\n \n\n \n4.\nTransfer of Additional Assets – The Company transferred a 0.5% overriding royalty interest\n(ORRI) in an Alaskan property and three parcels of Bellevue, Kern County real estate to a holding entity controlled by the Preferred\nShareholders. The real estate was assigned a fair value of $368,434, which was recognized as an inducement to convert the preferred\nshares.\n\n \n\n \n5.\nSettlement of Historical Liabilities – Royale also settled approximately $3 million in pre-merger\nobligations by issuing 2,508,509 shares common stock and promissory notes for $278,724 on the same terms stated above.\n\n \n\nThe transaction was accounted for as an extinguishment of equity in\naccordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a fundamental change in the structure and rights of the preferred\nstockholders. No gain or loss was recognized on the conversion of Series B Preferred Stock, as it was deemed to be an equity transaction\nper authoritative guidance. However, the issuance of warrants and asset transfers was treated as an inducement expense. The excess of\nthe fair value of the warrants and assets transferred over the accrued dividend forgiven totaling $674,341 was treated as inducement.\nThe inducement was accounted for as an equity transaction and increases the net loss attributable to common shareholders in the Loss\nPer Share computation in Note 1.\n\n \n\nThe Company concurrently settled approximately $3.47 million of accrued\nliabilities and unpaid guaranteed payments through the issuance of common stock and additional promissory notes valued at fair market\nrates. The liabilities extinguished included obligations associated with prior merger activity and were held primarily by related parties.\nThe exchange of these liabilities was accounted for as a capital transaction with no gain or loss recognized on extinguishment, in accordance\nwith guidance in ASC 470-50. The fair value of the new instruments issued was allocated between notes payable, common stock, and additional\npaid-in capital.\n\n \n\nF-23\n\n[Table of Contents](#toc) \n\n \n\n**NOTE 15**– **Notes\nPayable**\n\n \n\nWalou Note\n\n \n\nOn February 7, 2024, the board of directors of the Company approved\na related-party debt facility of up to $3 million. On February 9, 2024, the Company entered into a Secured Term Loan Note with Walou\nInvestments, LP, a Texas limited partnership under the control of Johnny Jordan, the Company’s Chief Executive Officer and a member\nof the Company’s board of directors. Mr. Jordan is also the beneficial owner of approximately 29.2% of the Company’s issued\nand outstanding common stock. The initial advance to the Company was $1,400,000 on February 9, 2024.\n\n \n\nThe loan originally bore interest at 18.0% per annum, with monthly\ninterest-only payments beginning March 1, 2024. The loan is secured by a deed of trust recorded in Ector County, Texas, covering certain\nof the Company’s oil and gas assets located in Ector County.\n\n \n\nOn November 1, 2024, the maturity date of the loan was extended from\nAugust 1, 2025 to January 1, 2026. Subsequently, on August 29, 2025, the loan was further extended to April 1, 2027, and the Company\nexecuted an additional advance of $500,000 on the loan, increasing the total outstanding principal balance to $1,900,000. Effective September\n1, 2025, the interest rate on the outstanding principal was reduced from 18.0% to 15.0% per annum.\n\n \n\nExcept as modified by the amendments described above, all other original\nterms and conditions of the Secured Term Loan Note remain in full force and effect at December 31, 2025.\n\n \n\nSenior Unsecured Promissory Notes\n\n \n\nOn December 31, 2025 the outstanding balance of the Senior Unsecured\nPromissory Notes was $2,221,112 and is further discussed in Note 14 – Debt and Equity Restructuring Transaction. The carrying value\nand fair value is further discussed in note 1.\n\n \n\n**NOTE 16 – SEGMENT REPORTING**\n\n** **\n\nThe Company has one reportable segment, which encompasses the ownership\nand investment in onshore oil and natural gas properties in the United States and turnkey drilling programs. The segment’s revenues\nare derived from the Company’s interests in the sales of crude oil, natural gas, and NGL production.\n\n \n\nThe Company evaluates performance based on consolidated net income\n(loss), as reported in the consolidated statement of operations.. The Company’s chief executive officer, chief operating officer,\nand chief financial officer together function as the chief operating decision maker (“CODM”) and manage the Company’s\nbusiness activities as a single operating segment.\n\n \n\nThe accounting policies of the one reportable segment are identical\nto those described for the consolidated Company. The CODM uses income (loss), as reported in the consolidated statement of operations,\nto measure segment profitability, assess performance, and manage strategic capital resource allocations. The measure of segment assets\nis reported as “Total assets” on the consolidated balance sheets. The significant expense categories regularly provided to\nand reviewed by the CODM are those presented in the consolidated statements of operations.\n\n \n\nF-24\n\n[Table of Contents](#toc) \n\n \n\n**NOTE 17 – SUBSEQUENT EVENTS**\n\n** **\n\nOn March 1, 2026, the Company completed the purchase of 8 gross (0.14\nnet) wells for $200,000. Other than as disclosed above, the Company has determined that no events or transactions have occurred subsequent\nto December 31, 2025 that require recognition or disclosure in these consolidated financial statements.\n\n \n\n**NOTE 18**– **SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS\nPRODUCING ACTIVITIES (UNAUDITED)**\n\n \n\nThe following estimates of proved oil and gas reserves, both developed\nand undeveloped, represent interest we own, which are located solely in the United States. Proved reserves represent estimated quantities\nof crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future\nfrom known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be\nexpected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves\nare reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major\nexpenditures are required for completion.\n\n \n\nDisclosures of oil and gas reserves, which follow, are based on estimates\nprepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc. The net reserve value of our proved\ndeveloped and undeveloped reserves was approximately $20.5 million at December 31, 2025, based on the average Henry Hub natural gas price\nspot price of $3.387 per MCF and for oil volumes, the average West Texas Intermediate price of $66.01 per barrel as applied on a field-by-field\nbasis. Netherland, Sewell & Associates, Inc. provided reserve estimates for our California, Texas, and Oklahoma properties. Such\nestimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of\nfuture rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves.\n\n \n\nThe technical persons responsible for preparing the reserves estimates\npresented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity,\nand confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated\nby the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists,\ngeophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities\nand reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are\nreviewed by our management.\n\n \n\nThese estimates are furnished and calculated in accordance with requirements\nof the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes,\nand the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited.\nEstimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash\nflows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed\nby the SEC as well as probable reserves, and upon different price and cost assumptions from those used here.\n\n \n\nIt should be recognized that applying current costs and prices and\na 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value\nof proved reserves.\n\n \n\nF-25\n\n[Table of Contents](#toc) \n\n \n\nChanges in Estimated Reserve Quantities\n\n \n\n**Proved Oil and Gas Reserve Quantities**\n\n** **\n\nThe Company's proved reserves and changes\nin proved reserves are as follows:** **\n\n** **\n\n** **\n**Crude Oil (Bbls)**\n** **\n** **\n**Natural Gas (Mcf)**\n** **\n** **\n**Total Proved Reserves (Boe)**\n** **\n\n**Proved reserves:**\n \n \n \n \n \n \n \n \n \n\nDecember 31, 2023\n \n \n217,780\n \n \n \n473,540\n \n \n \n296,703\n \n\nExtensions and discoveries\n \n \n15,043\n \n \n \n31,511\n \n \n \n20,295\n \n\nRevisions of previous estimates\n \n \n32,490\n \n \n \n4,115\n \n \n \n33,176\n \n\nPurchases of reserves in place\n \n \n-\n \n \n \n-\n \n \n \n-\n \n\nProduction\n \n \n(26,573\n)\n \n \n(116,406\n)\n \n \n(45,974\n)\n\nDecember 31, 2024\n \n \n238,740\n \n \n \n392,760\n \n \n \n304,200\n \n\nExtensions and discoveries\n \n \n248,005\n \n \n \n746,679\n \n \n \n372,452\n \n\nRevisions of previous estimates\n \n \n107,313\n \n \n \n688,044\n \n \n \n221,987\n \n\nPurchases of reserves in place\n \n \n79,022\n \n \n \n105,496\n \n \n \n96,605\n \n\nProduction\n \n \n(25,980\n)\n \n \n(117,219\n)\n \n \n(45,517\n)\n\nDecember 31, 2025\n \n \n647,100\n \n \n \n1,815,760\n \n \n \n949,727\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\nProved developed producing reserves:\n \n \n \n \n \n \n \n \n \n \n \n \n\nDecember 31, 2024\n \n \n132,600\n \n \n \n199,800\n \n \n \n165,900\n \n\nDecember 1, 2025\n \n \n199,000\n \n \n \n569,500\n \n \n \n293,917\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\n**Proved developed non-producing reserves:**\n \n \n \n \n \n \n \n \n \n \n \n \n\nDecember 31, 2024\n \n \n19,900\n \n \n \n38,500\n \n \n \n26,350\n \n\nDecember 1, 2025\n \n \n18,700\n \n \n \n32,900\n \n \n \n24,183\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\n**Proved undeveloped reserves:**\n \n \n \n \n \n \n \n \n \n \n \n \n\nDecember 31, 2024\n \n \n86,240\n \n \n \n154,460\n \n \n \n111,950\n \n\nDecember 1, 2025\n \n \n429,400\n \n \n \n1,213,360\n \n \n \n631,627\n \n\n \n \n \n \n \n \n \n \n \n \n \n \n \n\nTotal proved reserves:\n \n \n \n \n \n \n \n \n \n \n \n \n\nDecember 31, 2024\n \n \n238,740\n \n \n \n392,760\n \n \n \n304,200\n \n\nDecember 1, 2025\n \n \n647,100\n \n \n \n1,815,760\n \n \n \n949,727\n \n\n** **\n\nProved oil and gas reserves are generally those quantities of crude\noil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically\nproducible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved\ndeveloped reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating\nmethods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves\ninclude reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major\nexpenditure is required for recompletion. Proved reserve quantities at December 31, 2024, and 2025 and the related\ndiscounted future net cash flows before income taxes are based on estimates prepared by Netherland, Sewell & Associates, Inc. Such\nestimates have been prepared in accordance with guidelines established by the SEC. All the Company’s proved reserves are attributable\nto properties within the United States. \n\n \n\n**Standardized Measure**\n\n \n\nThe standardized measure of discounted future net cash flows relating to proved reserves is as follows:\n\n \n\n** **** **\n**December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nFuture cash inflows \n$43,694,600  \n$17,957,800 \n\nFuture production costs \n (17,820,400) \n (6,885,000)\n\nFuture development costs \n (5,411,900) \n (34,600)\n\nFuture income taxes (1) \n -  \n - \n\nFuture net cash flows \n 20,462,300  \n 11,038,200 \n\nLess 10% annual discount to reflect timing of cash flows \n (9,286,200) \n (4,689,500)\n\n**Standardized measure of discounted future net cash flows** \n 11,176,100  \n 6,348,700 \n\n \n\n(1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2024, and 2025, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2024, and 2025.\n\n \n\nProved reserve estimates and future cash flows are based on the average\nrealized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The following average\nrealized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.\n\n \n\n** **** **\n**December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nCrude oil ($/Bbl) \n$61.92  \n$72.01 \n\nNatural gas ($/Mcf) \n$2.00  \n$1.95 \n\n \n\nF-26\n\n[Table of Contents](#toc) \n\n \n\nFuture operating and development costs are computed\nprimarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s\nproved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. A discount\nfactor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash\nflows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair\nvalue would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future\nchanges in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve\nestimates.\n\n \n\n** **** **\n**December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nStandardized measure at beginning of year \n$6,348,700  \n$6,503,720 \n\nRevisions to reserves proved in prior years: \n    \n   \n\nNet change in sales prices and production costs related to future production \n (2,084,125) \n (102,367)\n\nNet change in estimated future development costs \n (4,458,464) \n (34,600)\n\nNet change due to revisions in quantity estimates \n 3,216,276  \n 900,932 \n\nAccretion of discount \n 634,870  \n 650,372 \n\nChanges in production rates (timing) and other \n 191,993  \n (143,080)\n\nTotal revisions to reserves proved in prior years \n (2,499,450) \n 1,271,257 \n\nNet change due to extensions and discoveries, net of\nestimated future development and production costs \n 6,849,699  \n 448,423 \n\nNet change due to purchases of reserves in place \n 2,090,951  \n - \n\nSales of crude oil, NGLs and natural gas produced, net of production costs \n (1,613,800) \n (1,874,700)\n\nNet change in standardized measure of discounted future net cash flows \n 4,827,400  \n (155,020)\n\nStandardized measure at end of year \n$11,176,100  \n$6,348,700 \n\n  \n\nThe following sets forth costs incurred for oil and gas property acquisition\nand development activities, whether capitalized or expensed at December 31:\n\n \n\n** **** **\n**Year ended December 31,**** **\n\n** **** **\n**2025**** **** **\n**2024**** **\n\nAcquisition - Proved \n$1,508,167  \n$- \n\nAcquisition - Unproved \n -  \n - \n\nDevelopment \n 1,433,352  \n 4,955,045 \n\nExploration \n -  \n - \n\nTotal Costs \n$2,941,519  \n$4,955,045 \n\n  \n\nResults of Operations from Oil and Gas Producing and Exploration\nActivities\n\n \n\nThe results of operations from oil and gas producing and exploration\nactivities (excluding corporate overhead and interest costs) are as follows:\n\n \n\n  \n**Year ended December 31,** \n\n** **** **\n**2025**** **** **\n**2024**** **\n\nOil and gas sales \n$1,926,442  \n$2,246,073 \n\nProduction related costs (Lease Operating) \n (1,396,710) \n (2,065,005)\n\nImpairment \n (27,250) \n (400,719)\n\nDepreciation, depletion, amortization, and accretion \n (259,438) \n (308,524)\n\n  \n    \n   \n\nResults of operations from producing and exploration activities \n$243,044  \n$(528,175)\n\nIncome Taxes (Benefit) \n -  \n - \n\n  \n    \n   \n\nNet 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