Royale Energy, Inc. 10-K

Item 9A Controls and Procedures Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rules 13a-15(e) or 15d-15(e) under the Exchange Act. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this annual report, as a result of a material weakness in our internal control over financial reporting discussed below. Management ’ s Report on Internal Control Over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over our financial reporting. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, management has conducted an assessment, including testing, using the criteria in the 2013 Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Based on our evaluation under the framework in Internal Control-Integrated Framework, our Chief Executive Officer and Chief Financial Officer concluded that our internal control over financial reporting was not effective as of December 31, 2025, due to a material weakness described below. Material Weakness and Remediation Management identified a material weakness that existed because we lack sufficient financial reporting personnel, proper review controls and proper segregation of duties, including within our financial reporting systems, to produce accurate and complete financial records in accordance with SEC and US GAAP requirements. The material weakness continues to exist as of December 31, 2025. Management is in the process of developing a remediation plan designed to improve its internal control over financial reporting and address the identified material weakness. Management will not be able to conclude that it has remediated the material weakness until controls are implemented, operate for a sufficient period of time, and management is able to conclude, through formal testing, that the controls are operating effectively. 13 Table of Contents PART III Item 10 Directors, Executive Officers and Corporate Governance All of our directors serve one-year terms from the time of their election to the time their successor is elected and qualified. The following information is furnished with respect to each director and executive officer who served as such during the fiscal year ended December 31, 2025: Name Age First Became Director or Executive Officer Positions Held Chris Parada (1) (2)(3)(4) 55 2021 Chairman of the Board Jonathan Gregory (2)(3) 62 2014 Vice-Chair of the Board of Directors Johnny Jordan 66 2018 Chief Executive and Operating officer and Director Ronald Lipnick 66 2021 Chief Financial Officer John Sullivan (1)(2)(3)(4) 68 2021 Director Jeff Kerns (1) (2)(3)(4) 69 2021 Director Stephen Hosmer 59 1995 Director (1) Members of the audit committee (2) Members of the compensation committee (3) Members of the nominations committee (4) Members indentified as independent The board has determined that directors John Sullivan, Chris Parada, and Jeff Kerns qualify as independent directors. The following summarizes the business experience of each director and executive officer for the past six years. Chris Parada – Chairman of the Board Mr. Parada currently serves as Managing Director – Energy Finance for Cornerstone Capital Bank, a position he has held since January 2023. With over 30 years of experience in energy finance, Mr. Parada specializes in providing debt capital and structured solutions to private exploration and production (E&P) and midstream oil and gas companies throughout the United States. From April 2021 through December 2022, Mr. Parada was an energy banker, with the title of Vice President of Business Development for Finergy Capital/EnRes Resources, an alternative investment fund providing structured capital solutions to upstream oil and gas companies. From 2013-2019 he served as Managing Director - Head of Energy Finance at LegacyTexas Bank, where his team executed over $1.5 billion of transactions. Mr. Parada has over 25 years of experience in oil and gas banking and finance. Mr. Parada holds a Bachelor of Business Administration in Finance from Texas A&M University. Jonathan Gregory – Vice-Chair of the board of directors Mr. Gregory became a director of Royale in March 2014 and served as Royale’s chief executive officer from September 10, 2015, until June 1, 2018. Prior to becoming Royale’s CEO, Mr. Gregory, from March 2014 to July 2015, served as Chief Financial Officer and Chief Business Development Strategist for Americo Energy Resources, a private exploration and production company located in Houston, Texas. Prior to serving as CFO of Americo Energy, Mr. Gregory was CFO of J&S Oil & Gas, LLC, from April 2012 to February 2014. From December 2004 to April 2012, Mr. Gregory was head of the energy lending group in Houston, Texas for Texas Capital Bank, N.A. Mr. Gregory is presently CEO of RMX, a private Texas based oil and gas company with oil and gas properties primarily located in California, in which, Royale holds an equity interest. Mr. Gregory is also a Credit Advisor to Anvil Capital Partners, a private debt capital provider to upstream energy companies and serves on the advisory board of the Center for Compassionate Leadership. Mr. Gregory graduated from Lamar University in 1986 with a Bachelor’s degree in Finance. John Sullivan – Director Mr. Sullivan first became a director and began serving as the Chairman of the board in 2021. Mr. Sullivan is the President of LTD Consulting Services LLC, which provides consulting and management services to private and public companies in the US and SE Asia, a position he has held since 2017. Previously, he held the position of Sr. Director at MMI International, a privately held, global supplier to the Data Storage, Aerospace and Oil and Gas industries from 2011-2017. In this role, he oversaw the sales and global operations for the Precision Forming Group, a division of MMI, with $250 million in annual sales. 14 Table of Contents Prior to this, as Director of Operations, COO and President, he spent eleven years, from 1999 until 2011, with Intri-Plex Technologies Inc., a leading design, engineering and manufacturing company to the Data Storage, Semi-conductor and Medical industries. In his various roles, he led the development and implementation of strategic sales and operating initiatives that resulted in significant top and bottom line growth. Overseeing the expansion of the business from a domestic manufacturing company to an international supplier of precision components with manufacturing facilities located in the US and SE Asia. Previously, he served as COO and President of KR Precision Public Co. Ltd., a publicly held, global supplier of precision mechanical components, John was instrumental in transforming a small privately held company from a niche supplier to a publicly held industry leader listed on the SET 50. John began his career in 1980 as an entrepreneur, spending ten years as a small business owner in the security and life safety industry. He grew his company organically and through acquisition, diversified its offerings and expanded its geographic footprint prior to it being acquired by ADT International in, a global leader in security and life safety industry, in 1990. Johnny Jordan – Chief Executive Officer, President, Chief Operating Officer and Director Mr. Jordan is a petroleum engineer with expertise in acquisitions, field economics and reserves analysis, bank negotiations, reservoir and field operations, and multi-team interaction. Mr. Jordan has been Royale Energy’s Chief Executive Officer since 2019. Mr. Jordan served on the board of directors of Matrix Oil Corporation (“Matrix”) and currently serves on the board of directors of both RMX Resources and CIPA. Mr. Jordan has been active in the oil and gas industry since 1980 beginning as a floor hand on a well service rig. He has held various staff and supervisory positions for Exxon, Mack Energy, Enron Oil and Gas and Venoco Corporation. He co-founded Matrix in 1999 and served as its president until its merger with Royale in 2018. Mr. Jordan is a member of the Society of Petroleum Engineers, American Petroleum Institute and the Texas Independent Producers and Royalty Owners Association. Mr. Jordan has managed acquisition evaluations in many of the oil and gas producing basins in the US. Mr. Jordan received a B.S. in Chemical Engineering from the University of Oklahoma in 1983. Jeff Kerns – Director Mr. Kerns was a founding partner of Matrix in 1999, which merged with Royale Energy, Inc. nearly 20 years later in 2018. As a director and officer of Matrix, Mr. Kerns participated in growing Matrix from zero production to owning and operating nearly 500 bbls of oil per day. Mr. Kerns was involved in all aspects of Matrix’s growth, but his primary focus was day to day operations. Mr. Kerns has served as a consulting engineer to Royale Energy and Matrix from 2018 to present. Mr. Kerns started in the oil and gas business over 40 years ago as a roughneck in North Dakota working on rigs that drilled through the now famous Bakken Shale heading for deeper targets. Prior to Matrix, Mr. Kerns has held various staff and supervisory positions with Mobil Oil Corp (now ExxonMobil) and Venoco Inc, a small independent company headquartered in Santa Barbara, CA. He also gained broad skills working for many years as a consultant in the oil and gas business. Mr. Kerns is a registered Professional Engineer in the state of CA. He received a BS degree from Stanford University in 1979. He served as an elected public official for 10 years on the local sanitary district board of directors as well as serving as a past president of a local Rotary International club and president of the San Joaquin Chapter of the American Petroleum Institute and has maintained a long term affiliation with SPE. Stephen Hosmer – Director, Corporate Secretary Mr. Hosmer first became a director in 1998, and served through 2018. He was then reappointed in January 2022, following his departure as the Company’s Chief Financial Officer, where he served since 1995. Mr. Hosmer also served as the Company’s Co-Chief Executive Officer from 2008 until September 2015. During his tenure as CFO, Mr. Hosmer managed the development of over 178 wells, raised capital through a combination of debt and equity sources, and led the acquisition of more than 200 square miles of 3D seismic data. Mr. Hosmer holds a Bachelor of Science degree in Business Administration from Oral Roberts University in Tulsa, Oklahoma and an MBA degree from the President/Key Executive program at Pepperdine University. Mr. Hosmer currently serves as the CFO for Owners in Honor, Managing Partner of Provident Ventures, and has also served on the board and/or consults for a number of not-for-profit organizations, including Venture Expeditions and Exile International, and Wycliffe Bible Translators. 15 Table of Contents Ronald Lipnick – Chief Financial Officer Mr. Lipnick has been with the Company since May 1993 and has been the Chief Financial Officer since February 2022. Prior to that he had been the Controller since February 1994. He is responsible for the Company’s accounting operations from daily accounting activities and general ledger reconciliation to the preparation of financial statements for the Company’s SEC filings. He also works closely with Royale’s certified public accountants during their yearly audits. Mr. Lipnick has more than 37 years of experience in the accounting field. He has a Bachelor of Science in Accounting and a Master of Business Administration in Finance from Oral Roberts University, Tulsa, Oklahoma. Audit Committee The board has appointed an audit committee to assist the board of directors in carrying out its responsibility as to the independence and competence of the Company’s independent public accountants. All members of the audit committee are independent members of the board of directors. The audit committee operates pursuant to an audit committee charter, which has been adopted by the board of directors to define the committee’s responsibilities. A copy of the audit committee charter is posted on our website, www.royl.com . The board has determined that Chris Parada qualifies as an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K. At the end of 2025, the members of the audit committee were John Sullivan (Chair), Jeff Kerns, Chris Parada and Jonathan Gregory. In 2025 there were four meetings of the audit committee, at which all members participated. Compensation Committee Although the Company is not required to maintain a compensation committee, the board has nonetheless appointed a compensation committee to assist the board of directors with respect to executive recruitment, selection, evaluation and compensation. This committee reviews and advises the board of directors on matters involving the personnel/human resource policies, its compensation program, and corporate strategy in compliance with public policy personnel/employment regulations in a changing environment. The compensation committee operates pursuant to a charter, which has been adopted by the board of directors to define the committee’s responsibilities. The compensation committee charter provides that the committee consist of at least two (2) independent directors. A copy of the compensation committee charter is posted on our website, www.royl.com. At the end of 2025, the members of the compensation committee were Jeff Kerns, John Sullivan, Chris Parada, Jonathan Gregory. In 2025, there was 1 meeting of the compensation committee, at which all members participated. Nominating Committee Although the Company is not required to maintain a nominating committee, the board has nonetheless appointed a nominating committee to assist the board of directors in identifying qualified individuals to become board members, receive and review recommendations by shareholders for board nominations, and determine whether existing board members should be nominated for re-election. The nominating committee operates pursuant to a charter, which has been adopted by the board of directors to define the committee’s responsibilities. The nominating committee charter provides that the committee consist of at least two independent directors. A copy of the nominating committee charter is posted on our website, www.royl.com. At the end of 2025, the members of the nominating committee were Chris Parada, John Sullivan (Chair), and Jeff Kerns, each of whom is an independent director. In 2025, there was 1 meeting of the nominating committee, at which all members participated. Code of Business Conduct and Ethics We have adopted a code of business conduct and ethics for our directors and executive officers. The code is posted on our website, www.royl.com . 16 Table of Contents Delinquent Section 16(a) Reports Section 16(a) of the Exchange Act and Securities and Exchange Commission regulations require that Royale’s directors, certain officers, and greater than 10 percent shareholders file reports of ownership and changes in ownership with the SEC and furnish Royale with copies of all such reports they file. The following Form 4’s for common stock issued to current and former board members were filed late, each of these filings consisted of two transactions that occurred in 2024: Form 4 2024 Common Stock Issuance - Late Filings: Recipient Shares issued 2024 Form 4 Filing Status Johnny Jordan 10,498,464 In Process Jeffrey Kerns 9,836,649 In Process Item 11 Executive Compensation The following table summarizes the compensation of the chief executive officer, chief financial officer and the one other most highly compensated non-executive employee of Royale and its subsidiaries during the past two years. SUMMARY COMPENSATION TABLE Year Salary (3) Bonus Option Awards All Other Compensation (1) Total Johnny Jordan (2)(3)(4) 2025 $ 255,769 $ - $ - $ 7,673 $ 263,442 (CEO) 2024 $ 255,769 $ - $ - $ 10,018 $ 265,787 Donald Hosmer 2025 $ 185,175 $ 42,500 $ - $ 27,930 $ 255,605 (Business Development) 2024 $ 185,175 $ 81,080 $ - $ 27,930 $ 294,185 Ronald Lipnick 2025 $ 184,154 $ - $ - $ 5,525 $ 189,679 (CFO) 2024 $ 184,154 $ - $ - $ 5,525 $ 189,679 (1) All other compensation consists of matching contributions to the Company’s simple IRA plan, except for Donald H. Hosmer, who also received a $12,000 car allowance. (2) Salary represents either direct payroll or common stock paid in lieu of taking a cash salary. (3) Mr. Jordan became CEO of the Company in January 2019. Mr. Jordan joined the Company as an officer on March 7, 2018. (4) There was no compensation paid to Mr. Johnny Jordan for performance (Pay Versus Performance). In 2025, Johnny Jordan received a salary of $255,769. He did not receive any bonus or option awards. His additional compensation amounted to $7,673, resulting in a total compensation of $263,442. In 2024, Johnny Jordan received a salary of $255,769. He did not receive any bonus or option awards. His additional compensation amounted to $10,018, resulting in a total compensation of $265,787. For 2025, Donald Hosmer’s salary was $185,175. He received a bonus of $42,500 but no option awards. His additional compensation was $27,930, resulting in a total compensation of $255,605. In 2024, Donald Hosmer’s salary was $185,175. He received a bonus of $81,080 but no option awards. His additional compensation was $27,930, resulting in a total compensation of $294,185. Ronald Lipnick’s 2025 salary was $184,154. He received no option awards. His additional compensation was $5,525, resulting in a total compensation of $189,679. In 2024, his salary was $184,154. He received no option awards. His additional compensation was $5,525, resulting in a total compensation of $189,679. 17 Table of Contents Stock Options and Equity Compensation; Outstanding Equity Awards at Fiscal Year End No unvested stock awards were outstanding at the end of 2025. Compensation Committee Report Our compensation committee has reviewed and discussed the following Compensation Discussion and Analysis with management and, based on its discussion and review, has recommended that the Compensation Discussion and Analysis be included in this annual report. Members of the compensation committee: Chris Parada, John Sullivan (Chair), and Jeff Kerns All members of the compensation committee are independent members of the board of directors. Compensation Discussion and Analysis Our executive compensation policy is designed to motivate, reward and retain the key executive talent necessary to achieve our business objectives and contribute to our long-term success. Our compensation policy for our executive officers focuses primarily on determining appropriate salary levels and performance-based cash bonuses. The elements of executive compensation at Royale consist mainly of cash salary and, if appropriate, a cash bonus at yearend. The compensation committee makes recommendations to the board of directors annually on the compensation of the three top executives: Johnny Jordan, Chief Executive Officer, Donald H. Hosmer, Business Development, and Ronald Lipnick, Chief Financial Officer . Royale also does not provide extensive personal benefits to its executives beyond those benefits, such as health insurance, that are provided to all employees. Donald Hosmer receives an annual car allowance. Policy The compensation committee’s primary responsibility is making recommendations to the board of directors relating to compensation of our officers. The committee also makes recommendations to the board of directors regarding employee benefits, our defined benefit plans, defined contribution plans, and stock-based plans. Determination To determine executive compensation, the committee, from time-to-time, meets with our officers to review our compensation programs, discuss the performance of the Company, the duties and responsibilities of each of the officers pay levels and business results compared to others similarly situated within the industry. The committee then makes recommendations to the board of directors for any adjustment to the officers’ compensation levels. The committee does not employ compensation consultants to make recommendations on executive compensation. Compensation Elements Base. Base salaries for our executive officers are established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peers. Base salaries are reviewed annually. The salaries we paid to our most highly paid executive officers and next most highly compensated non-executive officer for the last three years are set forth in the Summary Compensation Table included under Executive Compensation . Bonus . The compensation committee meets annually to determine the quantity, if any, of the cash bonuses of executive officers. The amount granted is based, subjectively, upon the Company’s stock price performance, earnings, revenue, reserves and production. The committee does not use quantifiable metrics for these criteria; but rather uses each in balance to assess the strength of the Company’s performance. The committee believes that formulaic approaches to cash incentives can foster an unhealthy balance between short-term and long-term goals. No cash bonuses were paid to executive officers in 2025 or 2024, other than those listed for Donald Hosmer in the table above. 18 Table of Contents Compensation of Directors In 2025, board members or committee member accrued or received fees for attendance at board meetings or committee meetings during the year. In addition to cash payments, Common Stock was issued in lieu of compensation or reimbursements. Royale also reimbursed directors for the expenses incurred for their services. The following table describes the compensation paid to our directors who are not also named executives for their services in 2025. Name Fees paid in Cash or Common Stock Stock awards Option awards All Other Compensation Total John Sullivan $ 36,000 $ - $ - $ - $ 36,000 Chris Parada $ 36,000 $ - $ - $ - $ 36,000 Jeff Kerns $ 24,000 $ - $ - $ - $ 24,000 Stephen Hosmer $ 36,000 $ - $ - $ - $ 36,000 Jonathan Gregory $ 24,000 $ - $ - $ - $ 24,000 Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Common Stock At March 31, 2026, 96,600,302 shares of Royale’s common stock were outstanding. The following table contains information regarding the ownership of Royale’s common stock as March 19, 2025, by each director and executive officer of Royale, and all directors and officers of Royale as a group and persons owning greater than 5% of the issued and outstanding shares of common stock. Except pursuant to applicable community property laws and except as otherwise indicated, each shareholder identified in the table below possesses sole voting and investment power with respect to her or his shares. The holdings reported are based on reports filed with the Securities and Exchange Commission and the Company by the officers and directors. Stockholder (1) Number Percent Johnny Jordan 28,162,723 29.15 % Jeff Kerns 20,225,636 20.94 % Stephen M. Hosmer (2) 2,820,782 2.92 % John Sullivan 2,732,865 2.83 % Jonathan Gregory (3) 2,257,865 2.34 % Chris Parada 1,756,465 1.82 % All officers and directors as a group 57,956,336 60.00 % (1) The mailing address of each listed stockholder is 1530 Hilton Head Rd, Suite 205, El Cajon, California 92021. (2) Includes 6,000 shares owned by Stephen M. Hosmer’s minor children. (3) Includes 35,000 shares owned by Mr. Gregory’s son. Other than Messrs. Jordan and Kerns, as disclosed above, there is no shareholder known by Royale to own beneficially more than 5% of our common stock. 19 Table of Contents Item 13. Certain Relationships and Related Transactions, and Director Independence Our Chief Executive Officer, Johnny Jordan, had accrued certain unpaid salary, at December 31, 2024, Mr. Jordan was owed $46,926, in accrued unpaid guaranteed payments. These amounts were discharged in the restructuring transaction described in Note 14. In 2018 the board of directors terminated the policy allowing employees and directors to participate, at cost, in wells drilled by the Company. Under the prior policy our former Chief Financial Officer and current board of director’s secretary, Stephen Hosmer, had participated individually in 179 wells. At December 31, 2025, the Company had a receivable balance of $22,266 due from Stephen Hosmer and $13,149 from Donald Hosmer for normal lease operating expenses. At December 31, 2025, we had a total payable of $23,087 due to RMX and its subsidiary, Matrix, related to certain lease operating expenses for wells operated by RMX, and also had prepaid expenses of $710,590 primarily for future plugging and abandonment costs for wells operated by RMX. At December 31, 2025, we had a total payable of $146,596 owed to current and former board members for directors fees. Royale had outstanding accrued unpaid guaranteed payments for unpaid salaries for employees for periods predating their joining the Company due to a former Matrix employee. At December 31, 2025, the balance due was $90,000. At December 31, 2025, Royale also had accrued unpaid liabilities of $12,386 due to a former Matrix employees for periods predating their joining the Company. Item 14. Principal Accountant Fees and Services HORNE LLP (“HORNE”) was the Company’s independent registered public accounting firm for the year ended December 31, 2024. Effective as of November 1, 2025, the partners and professional staff of HORNE joined BDO USA, P.C. (“BDO”). As a result of this transaction, HORNE resigned as the Company’s independent registered public accounting firm effective as of November 1, 2025 and the Company, through and with the approval of the Audit Committee, appointed BDO as its independent registered public accounting firm. The following table sets forth the aggregate fees incurred by HORNE for the fiscal year ended December 31, 2024 and by HORNE and BDO for the fiscal year ended December 31, 2025. 2025 2024 Audit fees (1) $ 280,000 $ 250,000 Tax fees (2) - - All other fees (3) - 6,500 Total $ 280,000 $ 256,500 (1) Audit fees are fees for professional services rendered for the audit of Royale Energy’s annual financial statements, reviews of financial statements included in the Company’s Forms 10-Q, audit and review of financial statements of an acquired asset, and reviews of documents filed with the U.S. Securities and Exchange Commission. (2) Tax fees consist of tax planning, consulting and tax return reviews. (3) Additional fees related to debt and equity restructuring transaction. The Company’s audit committee has adopted policies for the pre-approval of all audit and non-audit services provided by the Company’s independent auditor. The policy requires pre-approval by the audit committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the audit committee must approve the permitted service before the independent auditor is engaged to perform it. During 2025 and 2024 all such audit services and their fees were pre-approved by the audit committee. 20 Table of Contents PART IV Item 15 Exhibits and Financial Statement Schedules The agreements included as exhibits to this report are included to provide information about their terms and not to provide any other factual or disclosure information about Royale or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement that were made solely for the benefit of the other parties to the respective agreement, and: ● should 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; ● have 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; ● may apply standards of materiality in a way that is different from the way investors may view materiality; and ● were 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. 1. Financial Statements . See Index to Financial Statements, page F-1 2. Schedules . None. 3. Exhibits . Certain of the exhibits listed in the following index are incorporated by reference. 3.1* 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). 3.2 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.) 3.3* 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). 4.1 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 10.17† Royale Energy, Inc., 2018 Equity Incentive Plan, filed as Exhibit 99.1 to the Company’s Form S-8 filed October 29, 2018 10.27† 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 10.28 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 10.29 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.) 10.30 Exchange Agreement, filed as Exhibit 10.1 to the Company’s Form 8-K filed on October 17, 2024 10.31 Form of Series 2024 Senior Promissory Note, filed as Exhibit 10.2 to the Company’s Form 8-K filed on October 17, 2024 10.32 Stock Option Agreement, filed as Exhibit 10.3 to the Company’s Form 8-K filed on October 17, 2024 10.33 Release Agreement, filed as Exhibit 10.4 to the Company’s Form 8-K filed on October 17, 2024 21.1* Subsidiaries of Registrant 23.1* Consent of BDO USA, P.C. 23.3* Consent of Netherland, Sewell & Associates, Inc. 31.1* Rule 13a-14(a), 115d-14(a) Certification 31.2* Rule 13a-14(a), 115d-14(a) Certification 32.1* Section 1350 Certification 32.2* Section 1350 Certification 99.1* Report of Netherland, Sewell & Associates, Inc. 101.INS Inline XBRL Instance Document 101.SCH Inline XBRL Taxonomy Extension Schema 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase 101.LAB Inline XBRL Taxonomy Extension Label Linkbase 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) * Filed herewith. † Management contract or compensatory plan or arrangement. 21 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Royale Energy, Inc. Date: July 10, 2026 /s/ Johnny Jordan Johnny Jordan Chief Executive Officer Date: July 10, 2026 /s/ Ronald Lipnick Ronald Lipnick Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Date: July 10, 2026 /s/ John Sullivan John Sullivan Chairman of the board of directors Date: July 10, 2026 /s/ Jonathan Gregory Jonathan Gregory Vice-Chair of the board of directors Date: July 10, 2026 /s/ Chris Parada Chris Parada Director Date: July 10, 2026 /s/ Jeff Kerns Jeff Kerns Director Date: July 10, 2026 /s/ Stephen Hosmer Stephen Hosmer Director 22 Table of Contents ROYALE ENERGY, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (BDO USA, P.C.(formerly HORNE, LLP); Houston, Texas; PCAOB ID # 243 ) F-2 CONSOLIDATED BALANCE SHEETS F-4 CONSOLIDATED STATEMENTS OF OPERATIONS F-6 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT F-7 CONSOLIDATED STATEMENTS OF CASH FLOWS F-8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS F-9 F- 1 Table of Contents Report of Independent Registered Public Accounting Firm Shareholders and Board of Directors Royale Energy, Inc. El Cajon, California Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Royale Energy, Inc. (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements operations, stockholders’ deficit, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for the years then ended , in conformity with accounting principles generally accepted in the United States of America. Going Concern Uncertainty The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a working capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. F- 2 Table of Contents Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Estimation of Quantities of Future Production Volumes Used to Estimate Proved Oil and Gas Reserves and the Associated Effect on Depreciation, Depletion and Amortization (“DD&A”) Expense Related to Proved Oil and Gas Properties As disclosed by management and described in Notes 1 and 2 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and gas producing activities. Management uses internal and independent petroleum engineers to make significant estimates, including estimating quantities of proved oil and gas reserves. The Company’s oil and gas properties, net as of December 31, 2025 was $5.7 million, which includes proved oil and gas properties of $10.5 million and accumulated depletion, depreciation, and amortization (“DD&A”) of $8.0 million. DD&A expense was $0.3 million for the year ended December 31, 2025. We have identified the estimation of future production volumes used to estimate proved oil and gas reserves and the associated effect on DD&A expense related to proved oil and gas properties as a critical audit matter. Estimating future production volumes involves a high degree of subjectivity from management and their internal and independent petroleum engineers. Auditing the estimation of future production volumes required subjective and complex auditor judgement. The primary procedures we performed to address this critical audit matter included: ● Evaluating the professional qualifications and objectivity of the internal and independent petroleum engineers, including their relationship to the Company. ● Assessing the reasonableness of the future production volumes by comparing estimates of future production volumes against historical results of production volumes on a summary basis for all wells and on a detailed basis for a sample of wells. ● Performing a retrospective review over management estimates of future production volumes made in the prior period as compared to actual results. /s/ BDO USA, P.C. (formerly HORNE LLP ) We have served as the Company’s auditor since 2023. Houston, Texas July 10, 2026 F- 3 Table of Contents ROYALE ENERGY, INC. CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2025 2024 ASSETS Current Assets: Cash and Cash Equivalents $ 1,099,044 $ 1,877,163 Restricted Cash 7,175,950 6,025,000 Other Receivables, net 793,608 868,429 Revenue Receivables 694,729 764,653 Prepaid Expenses and Other Current Assets 746,862 619,913 Total Current Assets 10,510,193 10,155,158 Other Assets 576,265 589,865 Right of Use Asset - Leases 141,417 238,509 Oil and Gas Properties (Successful Efforts Basis), Real Property and Equipment and Fixtures, net 5,774,178 4,656,659 Total Assets $ 17,002,053 $ 15,640,191 The accompanying notes are an integral part of these consolidated financial statements. F- 4 Table of Contents ROYALE ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Continued) DECEMBER 31, 2025 2024 LIABILITIES AND STOCKHOLDERS’ DEFICIT Current Liabilities: Accounts Payable and Accrued Expenses $ 6,033,878 $ 6,776,825 Royalties Payable 611,833 611,833 RMX Resources, LLC 23,087 23,087 Leases - Current 102,238 94,070 Asset Retirement Obligation - Current 1,012,500 1,012,500 Deferred Drilling Obligations 14,277,496 11,457,996 Total Current Liabilities 22,061,032 19,976,311 Noncurrent Liabilities: Asset Retirement Obligation 4,065,352 4,066,095 Notes Payable 4,121,112 3,489,290 Leases - Non-current 43,386 145,644 Accrued Unpaid Guaranteed Payments 90,000 90,000 Accrued Liabilities - Non-current 12,386 12,386 Total Liabilities 30,393,268 27,779,726 Commitments and Contingencies (See Note 13) Stockholders’ Deficit: Common 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 96,600 96,600 Additional Paid in Capital 81,078,554 81,078,554 Accumulated Deficit ( 94,566,369 ) ( 93,314,689 ) Total Stockholder’s Deficit ( 13,391,215 ) ( 12,139,535 ) Total Liabilities, Stockholders’ Deficit $ 17,002,053 $ 15,640,191 The accompanying notes are an integral part of these consolidated financial statements. F- 5 Table of Contents ROYALE ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024 2025 2024 Revenues: Oil, NGL and Gas Sales $ 1,926,442 $ 2,246,073 Other Operating Revenue 20,761 16,266 Total Revenues 1,947,203 2,262,339 Costs and Expenses: Oil and Gas Lease Operating 1,323,333 1,983,173 Severance Taxes 73,377 81,832 Impairment 27,250 400,719 Depreciation, Depletion, Amortization, and Accretion 259,438 308,523 Settlement of Asset Retirement Obligation ( 18,710 ) - General and Administrative 1,632,103 1,633,740 Credit Loss Expense 137,221 450,743 Legal and Accounting 446,593 582,413 Marketing 302,455 347,044 Total Costs and Expenses 4,183,060 5,788,187 Gain on Turnkey Drilling Programs 1,322,149 1,607,677 Loss from Operations ( 913,708 ) ( 1,918,171 ) Other Income (Expense): Interest Expense ( 404,051 ) ( 304,873 ) Interest Income 66,079 46,528 Gain on Sale of Assets - 17,500 Total Other Expense (net) ( 337,972 ) ( 240,845 ) Net Loss ( 1,251,680 ) ( 2,159,016 ) Basic and Diluted Loss Per Share $ ( 0.01 ) $ ( 0.03 ) Weighted average number of common shares outstanding, basic and diluted 96,600,302 77,278,047 The accompanying notes are an integral part of these consolidated financial statements. F- 6 Table of Contents ROYALE ENERGY, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS ’ DEFICIT FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024 Common Stock Number Shares Issued and Outstanding Amount Additional Paid in Capital Accumulated Deficit Total Stockholders’ Deficit Balance, December 31, 2023 70,564,188 $ 70,564 $ 54,619,236 $ ( 90,133,509 ) $ ( 35,443,709 ) Stock issued in lieu of Cash Compensation 1,299,641 1,299 34,700 - 35,999 Preferred Series B 3.5 % Dividend - - - ( 653,730 ) ( 653,730 ) Preferred Series B Retirement & Conversion to Common 24,736,473 24,737 25,096,547 - 25,121,284 Equity and Debt Restructuring - - 1,328,071 ( 368,434 ) 959,637 Net Loss - - - ( 2,159,016 ) ( 2,159,016 ) Balance, December 31, 2024 96,600,302 96,600 81,078,554 ( 93,314,689 ) ( 12,139,535 ) Net Loss - - - ( 1,251,680 ) ( 1,251,680 ) Balance, December 31, 2025 96,600,302 $ 96,600 $ 81,078,554 $ ( 94,566,369 ) $ ( 13,391,215 ) The accompanying notes are an integral part of these consolidated financial statements. F- 7 Table of Contents ROYALE ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024 2025 2024 CASH FLOWS FROM OPERATING ACTIVITIES: Net Loss $ ( 1,251,680 ) $ ( 2,159,016 ) Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities: Depreciation, Depletion, and Amortization 259,438 308,523 Impairment 27,250 400,719 Gain on Sale of Assets - ( 17,500 ) Gain on Turnkey Drilling Programs ( 1,322,149 ) ( 1,607,677 ) Credit Loss Expense 137,221 450,743 Settlement on Asset Retirement Obligation ( 78,839 ) ( 151,856 ) Stock-Based Compensation - 35,999 Accretion of Debt Restructure Note Payable Interest 131,822 31,514 Right of Use Asset Depreciation 14,615 7,167 (Increase) Decrease in: Other & Revenue Receivables 69,924 ( 169,046 ) Prepaid Expenses and Other Assets ( 62,400 ) ( 44,244 ) Increase (Decrease) in: Accounts Payable and Accrued Expenses ( 625,022 ) 552,911 Royalties Payable - ( 1,092 ) Net Cash Used in Operating Activities ( 2,699,820 ) ( 2,362,855 ) CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for Oil and Gas Properties ( 1,490,736 ) ( 4,914,671 ) Acquisition of property ( 1,500,000 ) - Proceeds from Turnkey Drilling Programs 5,575,000 8,258,791 Net Cash Provided by Investing Activities 2,584,264 3,344,120 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from Long-Term Debt 500,000 1,400,000 Principal Payments on Long-Term Debt ( 11,613 ) ( 6,623 ) Net Cash Provided by Financing Activities 488,387 1,393,377 Net Increase in Cash, Cash Equivalents, and Restricted Cash 372,831 2,374,642 Cash, Cash Equivalents, and Restricted Cash at Beginning of Year 7,902,163 5,527,521 Cash, Cash Equivalents, and Restricted Cash at End of Year $ 8,274,994 $ 7,902,163 Supplemental Schedule of Cashflow information Cash Paid for Interest $ 272,229 $ 273,360 Cash Paid for Taxes $ 9,218 $ 8,150 Supplemental Schedule of Non-Cash Investing and Financing Transactions: Conversion of Preferred Stock to Common $ - $ 24,664,543 Additions to asset retirement obligation 112,417 865 Revisions to asset retirement obligations ( 41,622 ) 63,224 The accompanying notes are an integral part of these consolidated financial statements. F- 8 Table of Contents ROYALE ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES This summary of significant accounting policies of Royale Energy, Inc. (in these notes sometimes called “we”, “us”, “our”, “the Company”) is presented to assist in understanding our financial statements. These consolidated financial statements include the accounts of Royale Energy Inc and our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis. The financial statements and notes are representations of our management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements. Description of Business We are an independent oil and gas producer and we also perform turnkey drilling operations. We own wells and leases in major geological basins located primarily in California, Texas, and Oklahoma, and offer fractional working interests and seek to minimize the risks of oil and gas drilling by selling multiple well drilling projects which do not include the use of debt financing. Use of Estimates The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimated quantities of crude oil and condensate, Natural Gas Liquids (“NGLs”) and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Note 18 – Supplemental Information About Oil and Gas Producing Activities (Unaudited) to our Consolidated Financial Statements for further detail. Other items subject to estimates and assumptions include the carrying amounts of accounts receivable, property, plant and equipment, equity method investments, asset retirement obligations, and valuation allowances for deferred tax assets, among others. Although we believe these estimates are accurate, actual results could differ from these estimates. Liquidity and Going Concern Management evaluated whether conditions and events, considered in the aggregate, raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date the accompanying consolidated financial statements are issued. The accompanying financial statements have been prepared assuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classifications of liabilities that might result from the outcome of this uncertainty. The primary sources of liquidity have historically been issuances of common stock, oil and gas sales through ongoing operations and the sale of oil and gas properties. There are factors that give rise to substantial doubt about our ability to meet liquidity demands, and we anticipate that our primary sources of liquidity will be from the issuance of debt and/or equity, the sale of oil and natural gas property participation interests through our normal course of business and the sale of non-strategic assets. Our 2025 consolidated financial statements reflect a working capital deficiency of $ 11,550,839 , an accumulated deficit of $ 94,566,369 and recurring net losses from operations. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern. F- 9 Table of Contents Management’s plans to alleviate the going concern by implementing cost control measures that include the reduction of overhead costs and through the sale of non-strategic assets, and to seek additional debt and/or equity financing. There is no assurance that additional financing will be available when needed or that management will be able to obtain financing on terms acceptable to us and whether we will generate positive operating cash flow or become profitable. If we are unable to raise sufficient additional funds, we will have to develop and implement a plan to further extend payables and reduce overhead until sufficient additional capital is raised to support further operations. There can be no assurance that such a plan will be successful. Revision of Previously Issued Financial Statements During the preparation of the 2025 consolidated financial statements, immaterial errors were identified related to: ● 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. ● 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. ● 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). ● 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. ● Settlements of ARO liabilities of approximately $ 152 thousand were incorrectly presented in the statement of cash flows during the year ended December 31, 2024. We assessed the materiality of the errors, both quantitatively and qualitatively, in accordance with the SEC’s Staff Accounting Bulletin No. 99 and Staff Accounting Bulletin No. 108, and concluded the errors were not material to any of our previously issued financial statements. Notwithstanding the results of the assessment, we have revised the applicable items in our previously issued financial statements to correct these misstatements. Accordingly, all consolidated financial information contained in these consolidated financial statements and the accompanying notes have been revised to reflect the corrections. Previously reported financial information will be corrected in future filings, as applicable. Restricted Cash We sponsor turnkey drilling arrangements in proved and unproved properties. The contracts require that participants pay us the full contract price upon execution of the drilling agreement. Each participant earns an 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 well from a working interest participant are held for the expressed purpose of drilling a well. If something changes, we may designate these funds for a substitute well. Under certain conditions, a portion of these funds may be required to be returned to a participant. Once the well is drilled, the funds are used to satisfy the drilling cost. We classify these funds prior to commencement of drilling as restricted cash. In the event that progress payments are made from these funds; they are recorded as Prepaid Expenses and Other Current Assets. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets that sum to the total of the same amounts shown in the statement of cash flows. Year Ended December 31, 2025 2024 Cash and cash equivalents $ 1,099,044 $ 1,877,163 Restricted cash 7,175,950 6,025,000 Total cash, cash equivalents, and restricted cash shown in the statement of cash flows $ 8,274,994 $ 7,902,163 Other Receivables, net Our other receivables consist of receivables from direct working interest investors and industry partners. We account for expected credit losses on receivables using the Current Expected Credit Loss (CECL) methodology. Under this standard, an allowance for expected credit losses is established and adjusted based on historical loss experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The allowance account is increased or decreased in response to changes in these factors, reflecting our best estimate of credit losses over the remaining life of the receivables. All amounts considered uncollectible are charged against the allowance account and recoveries of previously charged off accounts are added to the allowance. At December 31, 2025 and 2024, we established an allowance for expected credit loses of $ 2,302,873 and $ 2,194,552 , respectively, for receivables from direct working interest investors whose expenses on non-producing wells were unlikely to be collected from revenue. F- 10 Table of Contents Revenue Receivables Our revenue receivables consist of receivables related to the sale of our natural gas and oil. Once a production month is completed, we receive payment approximately 15 to 30 days later. Historically, we have not had issues related to the collection of revenue receivables, and as such have determined that an allowance for revenue receivables is not currently necessary. Allowance for Credit Losses We measure our allowance for losses on other receivables including, under ASC 326. The following table summarizes the activity in the balance of allowance for credit losses on other receivables for the period indicated: Balance at December 31, 2023 $ 1,837,551 Provision for credit loss 450,743 Write-offs charged against the allowance ( 93,742 ) Balance at December 31, 2024 $ 2,194,552 Balance at December 31, 2024 $ 2,194,552 Provision for credit loss 137,221 Write-offs charged against the allowance ( 28,900 ) Balance at December 31, 2025 $ 2,302,873 Equity Method Investments Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred as called for under ASC 323, Investments—Equity Method and Joint Ventures. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. The Company’s only equity method investment is its holding in the RMX joint venture. At December 31, 2025, the Company had no balance related its investment in RMX, due to previously recognized impairments. Revenue Recognition A significant portion of our revenues are derived from the sale of crude oil, condensate, NGL and natural gas under spot and term agreements with our customers as follows: Year Ended December 31, 2025 2024 Oil & Condensate Sales $ 1,664,862 $ 2,010,742 Natural Gas Sales 257,684 231,765 NGL Sales 3,896 3,566 $ 1,926,442 $ 2,246,073 The pricing in our hydrocarbon sales agreements are determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications. In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheets. F- 11 Table of Contents Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenues in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons. We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, and such reimbursements are recorded as cost reimbursements of Lease Operating Expense. We commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. Those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regard to the sale of our share of production and recognize revenue for the volumes associated with our net production. We frequently sells a portion of the working interest in each well we drill or participate in to third-party investors and retains a portion of the prospect for our own account. We typically guarantee a cost to drill to the third-party drilling participants and record a loss or gain on the difference between the guaranteed price and the actual cost to drill the well. When monies are received from third parties for future drilling obligations, we record the liability as Deferred Drilling Obligations. Once the contracted depth for the drilling of the well is reached and a determination as to the commercial viability of the well (typically call “Casing Point Election” or “Logging Point”), the difference in the actual cost to drill and the guaranteed cost is recorded as income or expense depending on whether there was a gain or loss. Crude oil and condensate For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels. Natural Gas and NGLs When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs. The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost and included as lease operating expense in our consolidated Statement of Operations, since we make those payments in exchange for distinct services with the exception of natural gas sold to PG&E where transportation cost is netted directly against revenues. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer. Turnkey Drilling Obligations We manage these Turnkey Agreements for the participants of the well. The collections of pre-drilling Authorization for Expenditure (“AFE”) amounts are segregated and the gains and losses on the Turnkey Agreements are recorded in income or expense at the time of the casing point election in accordance with ASC 932-323-25 and 932-360. We manage the performance obligation for the well participants and only record revenue or expense at the time the performance obligation of the Turnkey Agreement has been satisfied. Other Operating Revenue For the years ended December 31, 2025 and 2024, we recognized $ 20,761 and $ 16,266 , respectively in supervisory fees in Pipeline and Compressor fees which were received and allocated based on production volumes. F- 12 Table of Contents Oil and Gas Property and Equipment Successful Efforts We use the “successful efforts” method to account for our exploration and production activities. Under this method, we accumulate our proportionate share of costs on a well-by-well basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred, and capitalize expenditures for productive wells. We amortize the costs of productive wells under the unit-of-production method. We carry, as an asset, exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where we are making sufficient progress assessing the reserves and the economic and operating viability of the well. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production Cost Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain our wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Depreciation, Depletion and Amortization Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. The project drilling phase commences with the development of the detailed engineering design and ends when the assets are ready for their intended use. Interest costs, to the extent they are incurred to finance expenditures during the construction phase, are included in property, plant and equipment and are depreciated over the service life of the related assets. Impairment We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of operations. During 2025 we recorded impairment losses of $ 27,250 , on various capitalized lease and land costs where the carrying value exceeded the estimated fair value. In 2024 we recorded impairment losses of $ 400,719 . Upon the sale or retirement of a complete field of a proved property, we eliminate the cost from our books, and the resultant gain or loss is recorded to our consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property has been assessed for impairment individually, a gain or loss is recognized in our consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a recovery of the cost in the interest retained with any excess funds recognized as a gain. Should our turnkey drilling agreements include unproved property, total drilling costs incurred to satisfy our obligations are recovered by the total funds received under the agreements. Any excess funds are recorded as a Gain on Turnkey Drilling Programs, and any costs not recovered are capitalized and accounted for under the “successful efforts” method. F- 13 Table of Contents Asset Retirement Obligations The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. The ARO is recorded at the estimated fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is included as part of Depreciation, Depletion and Amortization in the Consolidated Statement of Operations. The fair value (as provided in ASC 820 guidance) of the ARO is a Level 3 measurement using expected future cash outflows discounted at our credit-adjusted risk-free interest rate. The provisions of this Topic apply to legal obligations associated with the retirement of long-lived assets that result from the acquisition, development, and operation of a long-lived asset. Long-Lived Assets Classified as Held for Sale We classify long-lived assets as Held-for-Sale when the criteria of ASC 360-10-45-9 through 45-11, Impairment and Disposal of Long-Lived Assets, have been met. This criterion is listed below: ● Management has committed to a plan to sell the asset; ● The asset group is available for immediate sale in its present condition; ● An active program is underway to locate potential buyers; ● The sale is probable within one year; ● The asset group is being marketed at a price that is reasonable relative to its current fair value; and ● Actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or the plan will be withdrawn. Assets held for sale are carried at the lower of cost or fair market value less cost of disposal in current assets. If we retain the responsibility for the P&A, equipment removal or site restoration, the associated anticipated expense is carried as current an asset retirement obligation (“ARO”) (See Note 3, below). Turnkey Drilling We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations, and then reduced as costs to complete our obligations and are incurred with any excess booked against our property account to reduce any basis in our own interest. Gains on Turnkey Drilling Programs represent funds received from turnkey drilling participants in excess of all costs we incur during the drilling programs (e.g., lease acquisition, exploration and development costs), including costs incurred on behalf of participants and costs incurred for our own account; and are recognized only upon making this determination after our obligations have been fulfilled. The contracts require the participants pay us the full contract price upon execution of the agreement. We complete the drilling activities typically between 10 and 30 days after drilling begins. The participant retains an undivided or proportional beneficial interest in the property, and is also responsible for its proportionate share of operating costs. We retain legal title to the lease. The participants purchase a working interest directly in the well bore. In these working interest arrangements, the participants are responsible for sharing in the risk of development, but also sharing in a proportional interest in rights to revenues and proportional liability for the cost of operations after drilling is completed and the interest is conveyed to the participant. A certain portion of the turnkey drilling participant’s funds received are non-refundable. We hold all funds invested as Deferred Drilling Obligations until drilling is complete. Occasionally, drilling is delayed for various reasons such as weather, permitting, drilling rig availability and/or contractual obligations. At December 31, 2025 and 2024, we had Deferred Drilling Obligations of $ 14,277,496 and $ 11,457,996 , respectively. During 2025, we disposed of $ 2,755,500 of drilling obligations as we participated in drilling and completion of one gross (0.0035 net) successful oil well in the Texas Permian basin, 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 obligations as we participated in the drilling and completion of four gross (0.0722 net) wells in Texas Permian basin, while incurring expenses of $ 4,955,044 , resulting in a gain of $ 1,607,677 . F- 14 Table of Contents If we are unable to drill the wells, and a suitable replacement well is not found, we would retain the non-refundable portion of the contract and return the remaining funds to the participant. Included in restricted cash are amounts for use in completion of turnkey drilling programs in progress. Equipment and Fixtures Equipment and fixtures are stated at cost and depreciated over the estimated useful lives of the assets, which range from three to seven years , using the straight-line method. Repairs and maintenance are charged to expense as incurred. When assets are sold or retired, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. Maintenance and repairs, which neither materially add to the value of the property nor appreciably prolong its life, are charged to expense as incurred. Loss Per Share Basic and diluted losses per share are calculated as follows: Year Ended December 31, 2025 2024 Basic Diluted Basic Diluted Net Loss $ ( 1,251,680 ) $ ( 1,251,680 ) $ ( 2,159,016 ) $ ( 2,159,016 ) Less: Preferred Stock Dividend - - 653,730 653,730 Less: Non-cash Restructuring Inducements - - 674,341 674,341 Net Loss Attributable to Common Shareholders ( 1,251,680 ) ( 1,251,680 ) ( 3,487,087 ) ( 3,487,087 ) Weighted average common shares outstanding 96,600,302 96,600,302 77,278,047 77,278,047 Effect of dilutive securities - - - - Weighted average common shares, including Dilutive effect 96,600,302 96,600,302 77,278,047 77,278,047 Per share: Net Loss $ ( 0.01 ) $ ( 0.01 ) $ ( 0.03 ) $ ( 0.03 ) Income Taxes We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with the Income Taxes Topic of the ASC 740. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under the Topic, deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The provision for income taxes is based on pretax financial accounting income. Deferred tax assets and liabilities are recognized for the expected tax consequences of temporary differences between the tax basis of assets and liabilities and their reported net amounts. Fair Value Measurements According to Fair Value Measurements and Disclosures guidance as provided by ASC 820 and 825, assets and liabilities that are measured at fair value on a recurring and nonrecurring basis in periods subsequent to initial recognition, the reporting entity shall disclose information that enable users of our financial statements to assess the inputs used to develop those measurements and for recurring fair value measurements using significant unobservable inputs, the effect of the measurements on earnings for the period. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible as well as consider counterparty credit risk in our assessment of fair value. Carrying amounts of our financial instruments, including cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate their fair values as of the balance sheet dates because of their generally short maturities. The fair value hierarchy distinguishes between (1) market participant assumptions developed based on market data obtained from independent sources (observable inputs) and (2) an entity’s own assumptions about market participant assumptions developed based on the best information available in the circumstances (unobservable inputs). The fair value hierarchy consists of three broad levels, which gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are described below: Level 1: Quoted prices (unadjusted) in active markets that are accessible at the measurement date for assets or liabilities. F- 15 Table of Contents Level 2: Directly or indirectly observable inputs as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument. Level 3: Unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions. As of December 31, 2025, we have financial liabilities, including outstanding notes, that have been measured at fair value on a nonrecurring basis. The carrying values of financial instruments comprising cash, payables, and receivables, approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying amounts of cash and cash equivalents, accounts receivable, and other current assets approximate their fair values due to the short-term maturities of these instruments. As part of the Series B Convertible Preferred Stock restructuring transaction, the Company issued Series 2024 Senior Unsecured Promissory Notes in exchange for approximately 10% of the outstanding Series B shares. These notes have varying interest rate periods: ● 0.0% interest through December 31, 2025 ● 5.0% interest from January 1, 2026, to December 31, 2027 ● 8.0% interest from January 1, 2028, to June 30, 2029 (maturity date) The fair value of these notes was determined using a discounted cash flow model based on an assumed market interest rate of 11.912%, reflecting the Company’s estimated borrowing rate (Wall Street Journal Prime Rate plus 400 basis points as of October 1, 2024). Based on this valuation methodology, the following table sets out the fair value and carrying value of the notes issued. The fair value measurement of these notes is classified as Level 3 in the fair value hierarchy due to the use of significant unobservable inputs, including management’s assessment of credit risk and cash flow projections. The carrying amount of these notes will be accreted to their face value over the term using the effective interest rate method. The carrying values and estimated fair values of these notes were as follows: Carrying Value Fair Value December 31, 2025 Series 2024 Senior Unsecured Promissory Notes $ 2,221,112 $ 2,369,158 Walou Note 1,900,000 2,032,792 December 31, 2024 Series 2024 Senior Unsecured Promissory Notes 2,057,775 2,116,983 Walou Note 1,400,000 1,497,847 Additionally, the restructuring included the issuance of 25,000,000 stock warrants exercisable at $ 0.10 per share, expiring June 30, 2029. The warrants were valued using the Black-Scholes-Merton model, resulting 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 fair value measurement purposes. See Note 2 – Oil and Gas Properties, Equipment and Fixtures for further discussion of our asset retirement obligations and property transactions. Accounts Payable and Accrued Expenses At December 31, 2025 and 2024, the components of accounts payable and accrued expenses consisted of: 2025 2024 Trade Payables and accruals $ 3,235,457 $ 3,946,583 Direct working interest investors related accruals 2,050,399 2,322,690 Current drilling efforts accrued expenses 335,041 120,102 Accrued Liabilities 210,516 210,516 Employee related accruals 197,175 169,079 Deferred rent 5,290 7,855 $ 6,033,878 $ 6,776,825 F- 16 Table of Contents Accrued – Non-current At December 31, 2025 and 2024, we had non-current accrued liabilities of $ 12,386 and accrued unpaid guaranteed payment of $ 90,000 . These were due to certain Matrix Oil Corp (“Matrix”) principals, from periods prior to the merger with the Matrix entities during March of 2018. Business Combinations From time-to-time, we acquire businesses in the oil and gas industry. We primarily target businesses in geological basins that we consider to be in a focus area. Businesses are included in the consolidated financial statements from the date of acquisition. We recognize, separately from goodwill, the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. We measure and recognize goodwill as of the acquisition date as the excess of: (1) the aggregate of the fair value of consideration transferred, the fair value of any noncontrolling interest in the acquiree (if any) and the acquisition date fair value of our previously held equity interest in the acquiree (if any), over (2) the fair value of assets acquired and liabilities assumed. If information about facts and circumstances existing as of the acquisition date is incomplete by the end of the reporting period in which a business combination occurs, we report provisional amounts for the items for which the accounting is incomplete. The measurement or allocation period ends once we receive the information we are seeking; however, this period will generally not exceed one year from the acquisition date. Any material adjustments recognized during the measurement period will be reflected retrospectively in the consolidated financial statements of the subsequent period. We recognize third-party transaction-related costs as expense currently in the period in which they are incurred. If the set of assets and activities acquired is not considered a business under GAAP, the acquisition is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values, and no goodwill is recognized. The Pradera Fuego Acquisition was accounted for as an asset acquisition under GAAP. Changes in Accounting Standards Recently Adopted In December 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740) (“ASC 740”): Improvements to Income Tax Disclosures (“ASU 2023-09”) to expand the disclosure requirements for income taxes, specifically related to the rate reconciliation and income taxes paid. ASU 2023-09 is effective for annual periods beginning January 1, 2025, with early adoption permitted. We have adopted ASU 2023-09 for the annual period ended December 31, 2025 and have conformed our income tax disclosures in Note 4 to reflect the new requirements. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The Company adopted this update effective January 1, 2024. See Note 14 - Segments. The adoption and implementation of this standard did not have a material impact on the Company’s disclosures. Recently Issued, Not Yet Adopted We have reviewed all other recently issued accounting pronouncements that are not yet effective and have determined that none are currently expected to have a material impact on our consolidated financial statements upon adoption. In November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40) Reporting Comprehensive Income-Expense Disaggregation Disclosures, which broadens the disclosures required for certain costs and expenses in the Company’s annual and interim consolidated financial statements. This ASU is effective prospectively for fiscal years beginning after December 15, 2026, and interim reporting periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating disclosures related to our annual report for fiscal year 2027. F- 17 Table of Contents NOTE 2 – OIL AND GAS PROPERTIES, REAL PROPERTY AND EQUIPMENT AND FIXTURES Oil and gas properties, real property and equipment and fixtures consist of: Year ended December 31, 2025 2024 Oil and Gas Producing properties, including intangible drilling costs $ 7,229,767 $ 5,764,761 Undeveloped properties 3,237,624 3,339,234 Lease and well equipment 3,298,441 3,295,028 Total Oil and Gas Properties 13,765,832 12,399,023 Accumulated depletion, depreciation and amortization ( 7,995,503 ) ( 7,748,190 ) Net capitalized costs Total $ 5,770,329 $ 4,650,833 Commercial and Other 2025 2024 Vehicles 40,061 40,061 Furniture and equipment 1,103,362 1,103,362 Total Commercial and Other 1,143,423 1,143,423 Accumulated depreciation ( 1,139,574 ) ( 1,137,597 ) 3,849 5,826 Net capitalized costs Total $ 5,774,178 $ 4,656,659 The guidance set forth in the Continued Capitalization of Exploratory Well Costs paragraph of the Extractive Activities Topic of the FASB ASC requires that we evaluate all existing capitalized exploratory well costs and disclose the extent to which any such capitalized costs have become impaired and are expensed or reclassified during a fiscal period. We do not have any capitalized exploratory well costs. Undeveloped properties are not subject to depletion, depreciation or amortization. NOTE 3 – ASSET RETIREMENT OBLIGATION The Asset Retirement and Environmental Obligations Topic of the ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset. There were no changes in estimates for the years ended December 31, 2025 and 2024. 2025 2024 Asset retirement obligation Beginning of the year $ 5,078,595 $ 4,826,847 Liabilities incurred during the period 112,417 865 Settlements ( 78,839 ) ( 151,856 ) Changes in Working Interest 26,085 ( 4,716 ) Changes in estimates ( 67,707 ) 405,440 Accretion expense 7,300 2,015 End of year $ 5,077,852 $ 5,078,595 We record accretion expense as part of Depreciation, Depletion and Amortization. Accretion expense was $ 7,300 and $ 2,015 for the years ended December 31, 2025 and 2024, respectively. F- 18 Table of Contents NOTE 4 – INCOME TAXES The components of income (loss) before income taxes were as follows: 2025 2024 U.S. $ ( 1,251,680 ) $ 92,159,014 ) Non-U.S. $ - $ - The reconciliation between the actual provision for income taxes and that computed by applying the U.S. statutory rate to income (loss) before income taxes are outlined below based on the updated requirements of ASU 2023-09 for 2025. 2025 Current tax at U.S. statutory rate $ ( 222,999 ) 21.00 % State and local income taxes, net of federal taxes ( 37,891 ) 3.57 % Foreign Tax Effects - - % Effects of Changes in Tax Law or Rates Enacted in the Current Period - - % Effect of cross-border tax law - - % Tax Credits - - % Changes in Valuation Allowance 176,562 16.63 % Nondeductible/nontaxable items Nondeductible/nontaxable items 1,642 ( 0.15 %) Changes in Unrecognized Tax Benefit - - % Other Adjustments Deferred Adjustment 82,686 79 % Income tax expense $ - - % As previously disclosed prior to the adoption of ASU 2023-09, the effective income tax rate differs from the statutory federal income tax rate as follows 2024 Tax (benefit) computed at statutory rate of 21% at December 31, 2024, respectively $ ( 518,740 ) Increase (decrease) in taxes resulting from: Meals & Entertainment 915 Prior-year true-up for Books 2,380,175 Deferred State Taxes, net of federal benefit ( 102,681 ) Other non-deductible expenses - Change in valuation allowance ( 1,759,669 ) Provision (benefit) $ - Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. F- 19 Table of Contents Significant components of our deferred assets and liabilities at December 31, 2025 and 2024, respectively, are as follows: 2025 2024 Deferred Tax Assets (Liabilities): Accrued Expenses $ 98,999 $ 22,249 Net Operating Loss 9,450,310 9,288,524 Accretion 615,894 613,254 Share-Based Compensation 86,510 86,510 Charitable Contributions Carry Forward 2,796 2,743 Other 14,266 Allowance for Doubtful Accounts 599,207 571,022 Interest Expense Limitations 67,221 Oil and Gas Properties and Fixed Assets 3,292,967 3,320,659 Investment in RMX Joint Venture 139,969 123,640 Total deferred tax assets 14,286,652 $ 14,110,089 Valuation Allowance ( 14,286,652 ) ( 14,110,089 ) Net Deferred Tax Asset $ - $ - During the current year audit, it was determined that there were two immaterial errors in the 2024 income tax disclosures. The deferred tax asset for Oil and Gas Properties and Fixed Assets was overstated by $ 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 where none should have been recorded. The second error was to have recorded a deferred tax liability twice related to the book impairment on oil and gas properties. Both of these changes are completely offset by an equal offsetting change to the valuation allowance resulting in a net impact of $ 0 on the face of the financials. Only the income tax footnote disclosures were impacted by these errors. As of December 31, 2025, management reviewed the reliability of our net deferred tax assets, and due to our continued cumulative losses, we concluded it is not “more-likely-than-not” our deferred tax assets will be realized. As a result, we have continued to record a full valuation allowance against the deferred tax assets. We will assess the realizability of the deferred tax assets at least yearly and make appropriate updates as needed. We and our subsidiaries have available net operating loss carryforwards of $ 20.5 million generated in tax years ended before January 1, 2018, which if not utilized, expire in varying amounts between 2026 and 2037. We have $ 13.7 million net operating loss carryforwards generated after December 31, 2017, which can be carried forward indefinitely. As of December 31, 2025, we did not recognize a liability for uncertain tax positions. Currently, the only differences between our financial statements and our income tax returns relate to normal timing differences such as depreciation, depletion and amortization, which are recorded as deferred taxes on our balance sheets. We do not expect our unrecognized tax benefits to change significantly over the next 12 months. The tax years of 2020 through 2024 remain open to examination by the tax jurisdictions in which we file income tax returns. Net income taxes paid (received) during the years ended December 31, 2025 and 2024, by federal and state jurisdiction (all states combined), were as follows: 2025 2024 Federal $ - $ - State 9,218 8,150 Total income taxes paid, net $ 11,243 $ 10,174 NOTE 5 – SERIES B PREFERRED STOCK Pursuant to the terms of the merger completed in 2018, all Class A limited partnership interests of Matrix Investments, LP (“Matrix Investments”) were exchanged for our Common stock using conversion ratios according to the relative value of the Class A limited partnership interests, and $ 20,124,000 of Matrix Investments preferred limited partnership interests were converted into 2,012,400 shares of our Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock was convertible at the option of the security holder at the rate of ten shares of common stock for one share of Series B Convertible Preferred Stock. For 2024, the board authorized the payment of each quarterly dividend of Series B Convertible Preferred shares, as Paid-In-Kind shares (“PIK”) to be paid immediately following the end of the quarter. 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 dividends on Series B preferred shares. On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock. See Note 14. NOTE 6 – COMMON STOCK During 2024, we issued shares of our Common Stock in lieu of cash payments for salaries, fees or incentives to various officers and board members, including our CEO, as noted in the Statement of Stockholders’ Deficit. Common stock was also issued on October 11, 2024, when we completed a significant equity restructuring transaction, see Note 14. F- 20 Table of Contents NOTE 7 – LEASES During 2024, we had one office lease, the location of our corporate offices. The corporate office lease was entered into on August 12, 2021, began on January 1, 2022 and expires on December 31, 2026, with initial monthly payments of $ 6,922 with escalations. We also rent office space on a month-to-month basis in Santa Barbara, California, the location of our CEO for $ 1,000 per month. In addition, we have a finance lease for miscellaneous small office equipment, which commenced in the fourth quarter of 2024 with an 84-month term and an original balance of $ 71,622 . Lease Obligations Operating Lease Obligations Financing Lease Obligations Total Lease Obligations 2026 $ 93,492 $ 19,080 $ 112,572 2027 - 19,080 19,080 2028 - 19,080 19,080 Thereafter - 14,310 14,310 Total undiscounted lease payments 93,492 71,550 165,042 Less: Amount representing interest 4,308 15,110 19,418 Total Operating & Financing lease liabilities 89,184 56,440 145,624 Current lease liabilities as of December 31, 2025 89,184 13,054 102,238 Long-term lease liabilities as of December 31, 2025 $ - $ 43,386 $ 43,386 We have elected the short-term lease recognition exemption for all leases with an original term of 12 months or less. This means, for those leases that qualify, we will not recognize rights of use (“ROU”) assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases. We elected the practical expedient to not separate lease and non-lease components for all of our finance leases. For our real estate operating leases, we have only considered the fixed portion of our lease payment commitment and have excluded the variable components from the capitalized ROU and lease liability. The amounts are as follows: Year ended December 31, 2025 2024 Operating lease expense $ 119,658 $ 161,858 Financing lease expense 21,303 17,567 Short Term - field 6,000 6,000 Total lease expense $ 146,961 $ 185,425 The following tables summarized the operating and financing lease obligations. Debit/Credit Financing Leases Operating Leases Total Right of Use Asset - Leases $ 54,655 $ 89,184 $ 143,839 Leases - Current ( 9,725 ) ( 89,184 ) ( 98,909 ) Leases - Non-current ( 44,930 ) - ( 44,930 ) Our two office leases do not contain implicit interest rates that can be readily determined. As a result, we used the best estimate of our incremental borrowing rate. At December 31, 2025 and 2024 the weighted average annual discount rate for our operating leases was 4.83 % and the weighted average remaining term was 3 and 4 years, respectively. The weighted average annual discount rate for our finance lease was 11.91 % for 2025 and 2024, and the weighted average remaining term was 6 and 7 years. NOTE 8 – RELATED-PARTY TRANSACTIONS At December 31, 2025, and 2024, we had a receivable balance of $ 22,266 and $ 22,226 respectively, due from Stephen Hosmer, a director and corporate secretary, for normal lease operating expenses, recorded in Other Receivables, net. At December 31, 2025 and 2024, we had payables of $ 23,087 and $ 23,087 , respectively, due to RMX and its subsidiary, Matrix Oil Corporation, related to certain lease operating expenses for wells operated by RMX, included in accounts payable and accrued expenses on our Consolidated Balance Sheets.. For the same periods, we also had prepaid expenses and other current assets, and deferred drilling obligations with RMX of $ 710,590 and $ 556,019 , respectively. During 2025 and 2024, RMX operated various oil wells we have interests in, from which we received revenues of approximately $ 236,900 and $ 372,028 respectively, and incurred lease operating costs of approximately $ 129,450 and $ 158,664 respectively. At December 31, 2025 and 2024, we had a total revenue receivables of $ 122,262 and $ 108,344 , respectively, due from RMX and its subsidiary, Matrix Oil Corporation. F- 21 Table of Contents We had outstanding accrued unpaid guaranteed payments for unpaid salary due to a certain Matrix employee for periods predating joining our company. At December 31, 2025 and 2024, the balance due was $ 90,000 which is included in the Noncurrent Liabilities on our Consolidated Balance Sheets. At December 31, 2025 and 2024, Royale also had accrued unpaid liabilities of $ 12,386 due to a certain former Matrix employee for periods predating his employment. Michael McCaskey, Jeffery Kerns, and Stephen Hosmer, current directors, each provide services as directed and at our discretion directly or through an entity controlled by them. The following table sets amounts paid to entities owned or controlled by these individuals: 2025 2024 Michael McCaskey $ 60,000 $ 60,000 Jeffery Kerns - 4,726 Stephen Hosmer 83,873 79,448 The following table sets amounts owed to entities owned or controlled by these individuals at December 31, reflected in Accounts Payable and Accrued Expenses on the Consolidated Balance Sheet. 2025 2024 Michael McCaskey $ 21,455 $ 21,455 Jeffery Kerns 26,844 26,844 Stephen Hosmer 14,783 11,400 On February 7, 2024 the board of directors approved a debt facility of up to $ 3 million. On February 9, 2024, Royale Energy, Inc. entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership, which is under the direct and indirect control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s board of directors. In addition, Mr. Jordan is the beneficial owner of common stock. The initial loan to the Company was $ 1,400,000 which was received on February 9, 2024. The outstanding principal balance of the loan has an annual interest rate of 18.00 %. On November 1, 2024 the maturity was extended from August 1, 2025 to January 1, 2026. Subsequently, on August 29, 2025, the loan was further extended to April 1, 2027, and the Company executed an additional advance of $ 500,000 on the loan, increasing the total outstanding principal balance to $ 1,900,000 . Effective September 1, 2025, the interest rate on the outstanding principal was reduced from 18.0% to 15.0% per annum. NOTE 9 – STOCK COMPENSATION PLAN There were no stock options issued for compensation during 2025 and 2024. NOTE 10 – SIMPLE IRA PLAN In April 1998, we established a Simple IRA plan covering all employees. We will contribute a matching contribution to each eligible employee’s Simple IRA equal to the employee’s salary reduction contributions up to a limit of 3 % of the employee’s compensation for the year. The employer contribution for the years ending December 31, 2025 and 2024, were $ 30,333 and $ 28,653 respectively. NOTE 11 – ENVIRONMENTAL MATTERS We have established procedures for the continuing evaluation of our operations to identify potential environmental exposures and ensure compliance with regulatory policies and procedures. Management monitors these laws and regulations and periodically assesses the propriety of our operational and accounting policies related to environmental issues. The nature of our business requires routine day-to-day compliance with environmental laws and regulations. We incurred no material environmental investigation, compliance and remediation costs in 2025 or 2024. We are unable to predict whether our future operations will be materially affected by these laws and regulations. We believe that legislation and regulations relating to environmental protection will not materially affect our results of operations. NOTE 12 – CONCENTRATIONS We bid our gas sales on a month-to-month basis and generally sell to a single customer without commitment to future gas sales to any particular customer. For both years presented we sold approximately 36 % 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 readily available customers, we believe the loss of any one customer would not have an adverse effect on our overall sales operations. F- 22 Table of Contents We maintain cash in depository institutions that are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $ 250,000 per institution for our interest-bearing accounts in the years ended December 31, 2025, and 2024. At December 31, 2025 and 2024, cash in banks exceeded the FDIC limits by approximately $ 8.0 million and $ 7.6 million, respectively. We have not experienced any losses on deposits. NOTE 13 – COMMITMENTS AND CONTINGENCIES We may become involved from time to time in litigation on various matters, which are routine to the conduct of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial position or results of operations, though any adverse decision in these cases or the costs of defending or settling such claims could have a material effect on our business. We sponsor turnkey drilling agreement arrangements in proved and unproved properties as a pooling of assets in a joint undertaking, whereby proceeds from participants are reported as Deferred Drilling Obligations. The contracts require the participants pay us the full contract price upon execution of the agreement. We typically begin the drilling activities within 12 months of funding and reach total depth between 10 and 30 days after drilling begins. Note 14 – Debt and Equity Restructuring Transaction On October 11, 2024, we completed a significant equity restructuring transaction, eliminating our Series B, 3.5 % Convertible Preferred Stock and simplifying our capital structure. The transaction was executed through a combination of common stock issuance, warrants, and senior promissory notes in exchange for the retirement of all outstanding Series B Preferred Shares as of June 30, 2024. The preferred holders waived the payment of any unpaid dividends. The restructuring involved the exchange and extinguishment of 2,466,455 shares of Series B Preferred Stock, which carried an aggregate liquidation preference of $ 24.7 million. The exchange was structured as follows: 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. 2. 10% Conversion to Notes Payable – The remaining portion of the Series B Preferred Stock was exchanged for Senior Unsecured Promissory Notes, totaling $1.85 million. These notes bear an interest rate of 0% until December 31, 2025, increasing to 5% through 2027 and 8% through June 30, 2029, when all principal and interest is due. 3. Issuance of Warrants – As part of the exchange, Royale issued 25 million warrants with an exercise price of $0.10 per share, expiring on June 30, 2029. The fair value of the warrants was determined to be $959,637 using a Black-Scholes-Merton model. 4. Transfer of Additional Assets – The Company transferred a 0.5% overriding royalty interest (ORRI) in an Alaskan property and three parcels of Bellevue, Kern County real estate to a holding entity controlled by the Preferred Shareholders. The real estate was assigned a fair value of $368,434, which was recognized as an inducement to convert the preferred shares. 5. Settlement of Historical Liabilities – Royale also settled approximately $3 million in pre-merger obligations by issuing 2,508,509 shares common stock and promissory notes for $278,724 on the same terms stated above. The transaction was accounted for as an extinguishment of equity in accordance with ASC 470-50 and ASC 260-10-S99-2, as it represented a fundamental change in the structure and rights of the preferred stockholders. No gain or loss was recognized on the conversion of Series B Preferred Stock, as it was deemed to be an equity transaction per authoritative guidance. However, the issuance of warrants and asset transfers was treated as an inducement expense. The excess of the fair value of the warrants and assets transferred over the accrued dividend forgiven totaling $ 674,341 was treated as inducement. The inducement was accounted for as an equity transaction and increases the net loss attributable to common shareholders in the Loss Per Share computation in Note 1. The Company concurrently settled approximately $ 3.47 million of accrued liabilities and unpaid guaranteed payments through the issuance of common stock and additional promissory notes valued at fair market rates. The liabilities extinguished included obligations associated with prior merger activity and were held primarily by related parties. The exchange of these liabilities was accounted for as a capital transaction with no gain or loss recognized on extinguishment, in accordance with guidance in ASC 470-50. The fair value of the new instruments issued was allocated between notes payable, common stock, and additional paid-in capital. F- 23 Table of Contents NOTE 15 – Notes Payable Walou Note On February 7, 2024, the board of directors of the Company approved a related-party debt facility of up to $ 3 million. On February 9, 2024, the Company entered into a Secured Term Loan Note with Walou Investments, LP, a Texas limited partnership under the control of Johnny Jordan, the Company’s Chief Executive Officer and a member of the Company’s board of directors. Mr. Jordan is also the beneficial owner of approximately 29.2 % of the Company’s issued and outstanding common stock. The initial advance to the Company was $ 1,400,000 on February 9, 2024. The loan originally bore interest at 18.0 % per annum, with monthly interest-only payments beginning March 1, 2024. The loan is secured by a deed of trust recorded in Ector County, Texas, covering certain of the Company’s oil and gas assets located in Ector County. On November 1, 2024, the maturity date of the loan was extended from August 1, 2025 to January 1, 2026. Subsequently, on August 29, 2025, the loan was further extended to April 1, 2027, and the Company executed an additional advance of $ 500,000 on the loan, increasing the total outstanding principal balance to $ 1,900,000 . Effective September 1, 2025, the interest rate on the outstanding principal was reduced from 18.0% to 15.0% per annum. Except as modified by the amendments described above, all other original terms and conditions of the Secured Term Loan Note remain in full force and effect at December 31, 2025. Senior Unsecured Promissory Notes On December 31, 2025 the outstanding balance of the Senior Unsecured Promissory Notes was $ 2,221,112 and is further discussed in Note 14 – Debt and Equity Restructuring Transaction. The carrying value and fair value is further discussed in note 1. NOTE 16 – SEGMENT REPORTING The Company has one reportable segment, which encompasses the ownership and investment in onshore oil and natural gas properties in the United States and turnkey drilling programs. The segment’s revenues are derived from the Company’s interests in the sales of crude oil, natural gas, and NGL production. The Company evaluates performance based on consolidated net income (loss), as reported in the consolidated statement of operations.. The Company’s chief executive officer, chief operating officer, and chief financial officer together function as the chief operating decision maker (“CODM”) and manage the Company’s business activities as a single operating segment. The accounting policies of the one reportable segment are identical to those described for the consolidated Company. The CODM uses income (loss), as reported in the consolidated statement of operations, to measure segment profitability, assess performance, and manage strategic capital resource allocations. The measure of segment assets is reported as “Total assets” on the consolidated balance sheets. The significant expense categories regularly provided to and reviewed by the CODM are those presented in the consolidated statements of operations. F- 24 Table of Contents NOTE 17 – SUBSEQUENT EVENTS On March 1, 2026, the Company completed the purchase of 8 gross ( 0.14 net) wells for $ 200,000 . Other than as disclosed above, the Company has determined that no events or transactions have occurred subsequent to December 31, 2025 that require recognition or disclosure in these consolidated financial statements. NOTE 18 – SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interest we own, which are located solely in the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells, with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively major expenditures are required for completion. Disclosures of oil and gas reserves, which follow, are based on estimates prepared by independent petroleum engineering consultant Netherland, Sewell & Associates, Inc. The net reserve value of our proved developed and undeveloped reserves was approximately $ 20.5 million at December 31, 2025, based on the average Henry Hub natural gas price spot 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 basis. Netherland, Sewell & Associates, Inc. provided reserve estimates for our California, Texas, and Oklahoma properties. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable or possible reserves. The technical persons responsible for preparing the reserves estimates presented in the report of Netherland, Sewell & Associates, Inc., meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland, Sewell & Associates, Inc. is a firm of independent petroleum engineers, geologists, geophysicists, and petrophysicists; and do not own an interest in our properties and are not employed on a contingent basis. All activities and reports performed and completed by Netherland, Sewell & Associates, Inc. with regards to our reserve valuation estimates are reviewed by our management. These estimates are furnished and calculated in accordance with requirements of the FASB and the SEC. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, and the fact that the bases for such estimates vary significantly, management believes the usefulness of these projections is limited. Estimates of future net cash flows presented do not represent our management’s assessment of future profitability or future cash flows. Management’s investment and operating decisions are based upon reserve estimates that include proved reserves prescribed by the SEC as well as probable reserves, and upon different price and cost assumptions from those used here. It should be recognized that applying current costs and prices and a 10 percent standard discount rate does not convey absolute value. The discounted amounts arrived at are only one measure of the value of proved reserves. F- 25 Table of Contents Changes in Estimated Reserve Quantities Proved Oil and Gas Reserve Quantities The Company's proved reserves and changes in proved reserves are as follows: Crude Oil (Bbls) Natural Gas (Mcf) Total Proved Reserves (Boe) Proved reserves: December 31, 2023 217,780 473,540 296,703 Extensions and discoveries 15,043 31,511 20,295 Revisions of previous estimates 32,490 4,115 33,176 Purchases of reserves in place - - - Production ( 26,573 ) ( 116,406 ) ( 45,974 ) December 31, 2024 238,740 392,760 304,200 Extensions and discoveries 248,005 746,679 372,452 Revisions of previous estimates 107,313 688,044 221,987 Purchases of reserves in place 79,022 105,496 96,605 Production ( 25,980 ) ( 117,219 ) ( 45,517 ) December 31, 2025 647,100 1,815,760 949,727 Proved developed producing reserves: December 31, 2024 132,600 199,800 165,900 December 1, 2025 199,000 569,500 293,917 Proved developed non-producing reserves: December 31, 2024 19,900 38,500 26,350 December 1, 2025 18,700 32,900 24,183 Proved undeveloped reserves: December 31, 2024 86,240 154,460 111,950 December 1, 2025 429,400 1,213,360 631,627 Total proved reserves: December 31, 2024 238,740 392,760 304,200 December 1, 2025 647,100 1,815,760 949,727 Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2024, and 2025 and the related discounted future net cash flows before income taxes are based on estimates prepared by Netherland, Sewell & Associates, Inc. Such estimates have been prepared in accordance with guidelines established by the SEC. All the Company’s proved reserves are attributable to properties within the United States. Standardized Measure The standardized measure of discounted future net cash flows relating to proved reserves is as follows: December 31, 2025 2024 Future cash inflows $ 43,694,600 $ 17,957,800 Future production costs ( 17,820,400 ) ( 6,885,000 ) Future development costs ( 5,411,900 ) ( 34,600 ) Future income taxes (1) - - Future net cash flows 20,462,300 11,038,200 Less 10% annual discount to reflect timing of cash flows ( 9,286,200 ) ( 4,689,500 ) Standardized measure of discounted future net cash flows 11,176,100 6,348,700 (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. Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows. December 31, 2025 2024 Crude oil ($/Bbl) $ 61.92 $ 72.01 Natural gas ($/Mcf) $ 2.00 $ 1.95 F- 26 Table of Contents Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. A discount factor of 10 % was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates. December 31, 2025 2024 Standardized measure at beginning of year $ 6,348,700 $ 6,503,720 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production ( 2,084,125 ) ( 102,367 ) Net change in estimated future development costs ( 4,458,464 ) ( 34,600 ) Net change due to revisions in quantity estimates 3,216,276 900,932 Accretion of discount 634,870 650,372 Changes in production rates (timing) and other 191,993 ( 143,080 ) Total revisions to reserves proved in prior years ( 2,499,450 ) 1,271,257 Net change due to extensions and discoveries, net of estimated future development and production costs 6,849,699 448,423 Net change due to purchases of reserves in place 2,090,951 - Sales of crude oil, NGLs and natural gas produced, net of production costs ( 1,613,800 ) ( 1,874,700 ) Net change in standardized measure of discounted future net cash flows 4,827,400 ( 155,020 ) Standardized measure at end of year $ 11,176,100 $ 6,348,700 The following sets forth costs incurred for oil and gas property acquisition and development activities, whether capitalized or expensed at December 31: Year ended December 31, 2025 2024 Acquisition - Proved $ 1,508,167 $ - Acquisition - Unproved - - Development 1,433,352 4,955,045 Exploration - - Total Costs $ 2,941,519 $ 4,955,045 Results of Operations from Oil and Gas Producing and Exploration Activities The results of operations from oil and gas producing and exploration activities (excluding corporate overhead and interest costs) are as follows: Year ended December 31, 2025 2024 Oil and gas sales $ 1,926,442 $ 2,246,073 Production related costs (Lease Operating) ( 1,396,710 ) ( 2,065,005 ) Impairment ( 27,250 ) ( 400,719 ) Depreciation, depletion, amortization, and accretion ( 259,438 ) ( 308,524 ) Results of operations from producing and exploration activities $ 243,044 $ ( 528,175 ) Income Taxes (Benefit) - - Net Results $ 243,044 $ ( 528,175 ) F- 27