RING ENERGY, INC. 10-K

Item 9A: Controls and Procedures Evaluation of disclosure controls and procedures. Under the direction of our Chief Executive Officer and Interim Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Interim Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs. As of December 31, 2025, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Interim Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Interim Chief Financial Officer have concluded that as of December 31, 2025, our disclosure controls and procedures are effective. Changes in internal control over financial reporting. We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change. In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework (2013) . Based on our assessment, we believe that, as of December 31, 2025, our internal control over financial reporting is effective based on those criteria. The independent registered public accounting firm, Grant Thornton LLP, has audited the financial statements and internal control over financial reporting included in this Annual Report on Form 10-K, and has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2025, is set forth below. 66 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders Ring Energy, Inc. Opinion on internal control over financial reporting We have audited the internal control over financial reporting of Ring Energy, Inc. (a Nevada corporation) (the “Company”) as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements of the Company as of and for the year ended December 31, 2025, and our report dated March 4, 2026 expressed an unqualified opinion on those financial statements. Basis for opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reporting A company’s internal control over financial reporting is a process 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ GRANT THORNTON LLP Houston, Texas March 4, 2026 67 Table of Contents Item 9B: Other Information During the quarter ended December 31, 2025, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted , terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K). Item 9C: Disclosure Regarding Foreign Jurisdictions that Prevent Inspections None. PART III Item 10: Directors, Executive Officers and Corporate Governance The information required by this item, including information on our insider trading policy under the caption " Insider Trading Policy ," is incorporated by reference herein from the Company's 2026 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2025. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time. Item 11: Executive Compensation The information required by this item is incorporated by reference herein from the Company's 2026 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2025. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time. Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information required by this item is incorporated by reference herein from the Company's 2026 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2025. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time. Item 13: Certain Relationships and Related Transactions, and Director Independence The information required by this item is incorporated by reference herein from the Company's 2026 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2025. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time. Item 14: Principal Accountant Fees and Services The information required by this item is incorporated by reference herein from the Company's 2026 Proxy Statement to be filed with the SEC no later than 120 days after December 31, 2025. If the Proxy Statement is not filed with the SEC by such time, such information will be included in an amendment to this Annual Report by such time. 68 Table of Contents PART IV Item 15: Exhibits and Financial Statement Schedules Incorporated by Reference Exhibit Number Exhibit Description Form File No. Exhibit Filing Date Filed Here-with Furn-ished Here-with 2.1 Purchase and Sale Agreement dated July 1, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership, including the following Exhibits thereto: Exhibit I – Form of Registration Rights Agreement, Exhibit K – Form of Nomination Agreement, Exhibit L – Form of Certificate of Designation and Exhibit M – Form of Lock-Up Agreement 8-K 001-36057 2.1 7/8/22 2.2 First Amendment to Purchase and Sale Agreement by and among Stronghold Energy II Operating, LLC, Stronghold Energy II Royalties, LP, and Ring Energy, Inc., dated August 4, 2022 8-K 001-36057 2.1 8/9/22 2.3 Asset Purchase Agreement dated July 10, 2023 between Ring Energy, Inc. and Founders Oil & Gas IV, LLC. 8-K 001-36057 2.1 7/14/23 2.4 Purchase and Sale Agreement dated as of February 25, 2025 by and among Ring Energy, Inc., Lime Rock Resources IV-A, L.P., and Lime Rock Resources IV-C, L.P. 8-K 001-36057 2.1 2/28/25 3.1 Articles of Incorporation (as amended) 10-K 000-53920 3.1 4/1/13 3.2 Certificate of Amendment to the Articles of Incorporation, as amended, of Ring Energy, Inc. 8-K 001-36057 3.1 12/17/21 3.3 Certificate of Amendment to the Articles of Incorporation, as amended, of Ring Energy, Inc. 8-K 001-36057 3.1 5/26/23 3.4 Bylaws of Ring Energy, Inc. as amended April 13, 2021 8-K 001-36057 3.1 4/15/21 3.5 Certificate of Designation of the Series A Convertible Preferred Stock dated August 30, 2022 8-K 001-36057 3.1 9/6/22 3.6 Certificate of Withdrawal of Certificate of Designation filed with the Secretary of State of Nevada effective October 31, 2022 8-K 001-36057 3.1 10/31/22 4.1 Description of Ring Energy, Inc. equity securities registered under Section 12(b) of the Securities Exchange Act of 1934, as amended 10-K 001-36057 4.2 3/7/24 4.2 Securities Purchase Agreement, dated October 27, 2020 8-K 001-36057 4.1 10/29/20 10.1* Executive Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Stephen D. Brooks 8-K 001-36957 10.1 12/4/20 10.1(a)* Consulting Agreement, dated July 1, 2024 by and between Ring Energy, Inc. and Stephen D. Brooks. 8-K 001-36957 10.1 7/3/24 69 Table of Contents Incorporated by Reference Exhibit Number Exhibit Description Form File No. Exhibit Filing Date Filed Here-with Furn-ished Here-with 10.2* Executive Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Paul D. McKinney 8-K 001-36957 10.1 10/6/20 10.3* Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Alexander Dyes 8-K 001-36057 10.1 12/22/20 10.4* Employment and Severance Agreement, dated as of September 30, 2020, by and between the Company and Marinos C. Baghdati 8-K 001-36057 10.2 12/22/20 10.5* Ring Energy Inc. Long Term Incentive Plan, as Amended 8-K 000-53920 99.3 1/24/13 10.6* Form of Option Grant for Long-Term Incentive Plan 10-Q 000-53920 10.2 8/14/12 10.7* Executive Employment and Severance Agreement, dated as of October 26, 2020, by and between the Company and Travis T. Thomas 8-K 001-36057 10.1 3/26/21 10.8 Registration Rights Agreement dated August 31, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, and Stronghold Energy II Royalties, LP. 8-K 001-36057 10.1 9/6/22 10.9 Director Nomination Agreement dated August 31, 2022, by and among Ring Energy, Inc., Stronghold Energy II Operating, LLC, and Stronghold Energy II Royalties, LP. 8-K 001-36057 10.3 9/6/22 10.10 Second Amended and Restated Credit Agreement dated August 31, 2022, by and among Ring Energy, Inc., Truist Bank, and the Lenders from time to time party thereto 8-K 001-36057 10.4 9/6/22 10.11* Ring Energy, Inc. 2021 Omnibus Incentive Plan DEF 14A 001-36057 4/22/21 10.12* Amendment No. 1 to the Ring Energy, Inc. 2021 Omnibus Incentive Plan 8-K 001-36057 10.1 5/26/23 10.13* Form of Performance Stock Unit Agreement 8-K 001-36057 10.1 11/30/21 10.14* Form Restricted Stock Unit Agreement (employees) 8-K 001-36057 10.1 2/23/23 10.15* Form of Restricted Stock Unit Agreement (non-employee directors) 8-K 001-36057 10.2 2/23/23 10.16 Form of Warrant Amendment and Exercise Agreement. 8-K 001-36057 10.1 4/12/23 10.17 First Amendment to Second Amended and Restated Credit Agreement dated as of February 12, 2024, by and among Ring Energy, Inc., Truist Bank, as administrative agent, and the Lenders party thereto. 8-K 001-36057 10.1 2/16/24 10.18 Change in Control and Severance Benefit Plan 10-K 001-36057 10.25 3/7/24 70 Table of Contents Incorporated by Reference Exhibit Number Exhibit Description Form File No. Exhibit Filing Date Filed Here-with Furn-ished Here-with 10.19 Registration Rights Agreement dated March 31, 2025, by and among Ring Energy, Inc., Lime Rock Resources IV-A, L.P. and Lime Rock Resources IV-C, L.P. 8-K 001-36057 10.1 4/4/25 10.20 A mendment No. 2 to the Ring Energy, Inc. 2021 Omnibus Incentive Plan. 8-K 001-36057 10.1 5/22/25 10.21 Third Amended and Restated Credit Agreement dated June 18, 2025, by and among Ring Energy, Inc., Bank of America, N.A., and the Lenders from time to time party thereto. 8-K 001-36057 10.1 6/23/25 10.22* General Release Agreement dated October 2, 2025 by Travis T. Thomas . 8-K/A 001-36057 10.1 10/3/25 10.23* Offer Letter between Ring Energy, Inc. and Sundip S. Johl dated January 29, 2026. 8-K 001-36057 10.1 2/3/26 14.1 Code of Ethics 8-K 000-53920 14.1 1/24/13 19.1 Insider Trading Policy 10-K 001-36057 19.1 3/5/25 23.1 Consent of Cawley, Gillespie & Associates, Inc. X 23.2 Consent of Grant Thornton LLP X 24.1 Power of Attorney (included as part of the signature pages of this report) X 31.1 Rule 13a-14(a) Certification by Chief Executive Officer X 31.2 Rule 13a-14(a) Certification by Principal Financial Officer X 32.1 Section 1350 Certification of Chief Executive Officer X 32.2 Section 1350 Certification of Principal Financial Officer X 97.1 Ring Energy, Inc. Clawback Policy 10-K 001-36057 97.1 3/7/24 99.1 Reserve Report of Cawley, Gillespie & Associates, Inc. X 101.INS Inline XBRL Instance Document X 101.SCH Inline XBRL Taxonomy Extension Schema Document X 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document X 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document X 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document X 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document X 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). * Management contract 71 Table of Contents Item 16: Form 10-K Summary None. 72 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. Ring Energy, Inc. By: /s/ Paul D. McKinney Mr. Paul D. McKinney Chief Executive Officer Date: March 4, 2026 KNOW ALL PERSONS BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints Paul D. McKinney, his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission, hereby ratifying and confirming his or her signature as he or she may be signed by his or her said attorney to any and all amendments to said Annual Report on Form 10-K. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the dates indicated. /s/ Paul D. McKinney /s/ Thomas L. Mitchell Mr. Paul D. McKinney Mr. Thomas L. Mitchell Chief Executive Officer and Director Director (Principal Executive Officer) Date: March 4, 2026 Date: March 4, 2026 /s/ Rocky P. Kwon /s/ Anthony B. Petrelli Mr. Rocky P. Kwon Mr. Anthony B. Petrelli Vice President, Chief Accounting Officer Director (Principal Financial Officer and Principal Accounting Officer) Date: March 4, 2026 Date: March 4, 2026 /s/ Carla Tharp /s/ John A. Crum Mrs. Carla Tharp Mr. John A. Crum Director Director Date: March 4, 2026 Date: March 4, 2026 /s/ Richard E. Harris /s/ David S. Habachy Mr. Richard E. Harris Mr. David S. Habachy Director Director Date: March 4, 2026 Date: March 4, 2026 73 Table of Contents RING ENERGY, INC. INDEX TO FINANCIAL STATEMENTS Page Report of Grant Thornton LLP Independent Registered Public Accounting Firm (PCAOB ID Number 248 ) F- 2 Balance Sheets as of December 31, 2025 and 2024 F- 4 Statements of Operations for the years ended December 31, 2025, 2024, and 2023 F- 5 Statement of Stockholders’ Equity for the years ended December 31, 2025, 2024, and 2023 F- 6 Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023 F- 7 Notes to Financial Statements F- 9 Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) F- 48 F-1 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Stockholders Ring Energy, Inc. Opinion on the financial statements We have audited the accompanying balance sheets of Ring Energy, Inc. (a Nevada corporation) (the “Company”) as of December 31, 2025 and 2024, the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 4, 2026 expressed an unqualified opinion. Basis for opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the 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 financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical audit matter The critical audit matter communicated below is a matter arising from the current period audit of the 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 financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. The development of estimated proved crude oil and natural gas reserves used in the calculation of depletion, depreciation and amortization expense and impairment expense under the full cost method of accounting As described further in Note 1 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future development costs to calculate and record depletion, depreciation and amortization expense and impairment expense. To estimate the volume of proved crude oil and natural gas reserves, future development costs, and the related future net cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved crude oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved crude oil and natural gas reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion, depreciation and amortization expense and the assessment of potential impairment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter. F-2 Table of Contents The principal consideration for our determination that the estimation of proved crude oil and natural gas reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volumes, future development costs, and the related net cash flows of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense and impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. Our audit procedures related to the estimation of proved crude oil and natural gas reserves included the following, among others. • We tested the design and operating effectiveness of key controls relating to management’s estimation of proved crude oil and natural gas reserves for the purpose of estimating depletion, depreciation and amortization expense and impairment expense. • We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved crude oil and natural gas reserve volumes, and read the reserve report prepared by the Company’s reserve engineers. • Identified the inputs and assumptions significant to the proved reserve volumes and tested management’s process for determining the significant inputs and assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s inputs and assumptions by performing the following: ◦ Compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; ◦ Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs; ◦ Evaluated the method used to determine the estimated future development costs used in the reserve report and compared management’s estimates to amounts expended for recently drilled and completed wells; ◦ Tested, on a sample basis, the working and net revenue interests used in the reserve report by inspecting land, legal and division order records; ◦ Evaluated evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and ◦ Applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results. /s/ GRANT THORNTON LLP We have served as the Company’s auditor since 2021. Houston, Texas March 4, 2026 F-3 Table of Contents RING ENERGY, INC. BALANCE SHEETS As of December 31, 2025 2024 ASSETS Current Assets Cash and cash equivalents $ 902,913 $ 1,866,395 Accounts receivable 30,938,908 36,172,316 Joint interest billing receivables, net 1,623,991 1,083,164 Derivative assets 21,468,134 5,497,057 Inventory 5,312,715 4,047,819 Prepaid expenses and other assets 1,822,751 1,781,341 Total Current Assets 62,069,412 50,448,092 Properties and Equipment Oil and natural gas properties, full cost method 1,891,510,431 1,809,309,848 Financing lease asset subject to depreciation 3,633,586 4,634,556 Fixed assets subject to depreciation 3,504,788 3,389,907 Total Properties and Equipment 1,898,648,805 1,817,334,311 Accumulated depreciation, depletion and amortization ( 569,180,901 ) ( 475,212,325 ) Net Properties and Equipment 1,329,467,904 1,342,121,986 Operating lease asset 1,285,159 1,906,264 Derivative assets 9,739,430 5,473,375 Deferred financing costs 9,337,344 8,149,757 Total Assets $ 1,411,899,249 $ 1,408,099,474 LIABILITIES AND STOCKHOLDERS’ EQUITY Current Liabilities Accounts payable $ 97,522,809 $ 95,729,261 Income tax liability 356,436 328,985 Financing lease liability 730,564 906,119 Operating lease liability 586,614 648,204 Derivative liabilities 841,193 6,410,547 Notes payable 505,752 496,397 Asset retirement obligations 418,526 517,674 Total Current Liabilities 100,961,894 105,037,187 Non-current Liabilities Deferred income taxes 20,764,119 28,591,802 Revolving line of credit 420,000,000 385,000,000 Financing lease liability, less current portion 593,146 647,078 Operating lease liability, less current portion 819,223 1,405,837 Derivative liabilities 2,512,692 2,912,745 Asset retirement obligations 29,972,429 25,864,843 Total Liabilities 575,623,503 549,459,492 Commitments and contingencies - See Note 13 Stockholders' Equity Preferred stock - $ 0.001 par value; 50,000,000 shares authorized; no shares issued or outstanding — — Common stock - $ 0.001 par value; 450,000,000 shares authorized; 207,656,929 shares and 198,561,378 shares issued and outstanding, respectively 207,657 198,561 Additional paid-in capital 812,777,586 800,419,719 Retained earnings (Accumulated deficit) 23,290,503 58,021,702 Total Stockholders’ Equity 836,275,746 858,639,982 Total Liabilities and Stockholders' Equity $ 1,411,899,249 $ 1,408,099,474 The accompanying notes are an integral part of these financial statements. F-4 Table of Contents RING ENERGY, INC. STATEMENTS OF OPERATIONS For the years ended December 31, 2025 2024 2023 Oil, Natural Gas, and Natural Gas Liquids Revenues $ 307,178,072 $ 366,327,414 $ 361,056,001 Costs and Operating Expenses Lease operating expenses 79,353,806 78,310,949 70,158,227 Gathering, transportation and processing costs 585,087 506,333 457,573 Ad valorem taxes 7,906,586 8,069,064 6,757,841 Oil and natural gas production taxes 14,312,232 16,116,565 18,135,336 Depreciation, depletion and amortization 96,414,150 98,702,843 88,610,291 Ceiling test impairment 108,825,446 — — Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686 Operating lease expense 700,362 700,362 541,801 General and administrative expense 31,928,576 29,640,300 29,188,755 Total Costs and Operating Expenses 341,516,500 233,426,714 215,275,510 Income (Loss) from Operations ( 34,338,428 ) 132,900,700 145,780,491 Other Income (Expense) Interest income 290,879 491,946 257,155 Interest (expense) ( 40,430,929 ) ( 43,311,810 ) ( 43,926,732 ) Gain (loss) on derivative contracts 31,658,839 ( 2,365,917 ) 2,767,162 Gain (loss) on disposal of assets 446,400 89,693 ( 87,128 ) Other income 189,294 106,656 198,935 Net Other Income (Expense) ( 7,845,517 ) ( 44,989,432 ) ( 40,790,608 ) Income (Loss) Before Benefit from (Provision for) Income Taxes ( 42,183,945 ) 87,911,268 104,989,883 Benefit from (Provision for) Income Taxes 7,452,746 ( 20,440,954 ) ( 125,242 ) Net Income (Loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641 Basic Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.55 Diluted Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.54 The accompanying notes are an integral part of these financial statements. F-5 Table of Contents RING ENERGY, INC. STATEMENT OF STOCKHOLDERS’ EQUITY Common Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Total Stockholders' Equity Shares Amount Balance, December 31, 2022 175,530,212 $ 175,530 $ 775,241,114 $ ( 114,313,253 ) $ 661,103,391 Exercise of common warrants issued in offering 4,517,427 4,517 3,609,424 — 3,613,941 Induced exercise of common warrants issued in offering 14,512,166 14,512 8,673,143 — 8,687,655 Restricted stock vested 1,680,232 1,680 ( 1,680 ) — — Shares to cover tax withholdings for restricted stock vested ( 288,152 ) ( 287 ) 287 — — Payments to cover tax withholdings for restricted stock vested, net — — ( 520,153 ) — ( 520,153 ) Performance stock vested 1,170,024 1,170 ( 1,170 ) — — Shares to cover tax withholdings for performance stock vested ( 284,908 ) ( 285 ) 285 — — Share-based compensation — — 8,833,425 — 8,833,425 Net income — — — 104,864,641 104,864,641 Balance, December 31, 2023 196,837,001 $ 196,837 $ 795,834,675 $ ( 9,448,612 ) $ 786,582,900 Restricted stock vested 1,688,317 1,688 ( 1,688 ) — — Shares to cover tax withholdings for restricted stock vested ( 327,041 ) ( 327 ) 327 — — Payments to cover tax withholdings for restricted stock vested, net — — ( 919,249 ) — ( 919,249 ) Performance stock vested 571,324 571 ( 571 ) — — Shares to cover tax withholdings for performance stock vested ( 208,223 ) ( 208 ) 208 — — Share-based compensation — — 5,506,017 — 5,506,017 Net income — — — 67,470,314 67,470,314 Balance, December 31, 2024 198,561,378 $ 198,561 $ 800,419,719 $ 58,021,702 $ 858,639,982 Restricted stock vested 2,402,692 2,403 ( 2,403 ) — — Shares to cover tax withholdings for restricted stock vested ( 588,840 ) ( 589 ) 589 — — Payments to cover tax withholdings for restricted stock vested, net — ( 1,189,805 ) — ( 1,189,805 ) Common stock issuance for Lime Rock Acquisition 6,452,879 6,453 7,414,358 — 7,420,811 Performance stock vested 1,230,565 1,231 ( 1,231 ) — — Shares to cover tax withholdings for performance stock vested ( 401,745 ) ( 402 ) 402 — — Share-based compensation — — 6,135,957 — 6,135,957 Net loss — — — ( 34,731,199 ) ( 34,731,199 ) Balance, December 31, 2025 207,656,929 $ 207,657 $ 812,777,586 $ 23,290,503 $ 836,275,746 The accompanying notes are an integral part of these financial statements. F-6 Table of Contents RING ENERGY, INC. STATEMENTS OF CASH FLOWS For the years ended December 31, 2025 2024 2023 Cash Flows From Operating Activities Net income (loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 96,414,150 98,702,843 88,610,291 Ceiling test impairment 108,825,446 — — Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686 Amortization of deferred financing costs 4,459,520 4,969,174 4,920,714 Share-based compensation 6,135,957 5,506,017 8,833,425 Credit loss expense 19,029 160,847 134,007 (Gain) loss on disposal of assets ( 446,400 ) ( 89,693 ) — Deferred income tax expense (benefit) ( 7,858,446 ) 19,935,413 ( 425,275 ) Excess tax expense (benefit) related to share-based compensation 30,763 104,344 478,304 (Gain) loss on derivative contracts ( 31,658,839 ) 2,365,917 ( 2,767,162 ) Cash received (paid) for derivative settlements, net 5,452,300 ( 5,193,673 ) ( 9,084,920 ) Changes in operating assets and liabilities: Accounts receivable 4,452,926 3,594,504 1,154,085 Inventory ( 1,264,896 ) 2,089,116 3,113,782 Prepaid expenses and other assets ( 41,410 ) 93,509 226,688 Accounts payable 474,744 ( 5,076,738 ) ( 1,451,422 ) Settlement of asset retirement obligation ( 904,493 ) ( 1,588,480 ) ( 1,862,385 ) Net Cash Provided by Operating Activities 150,849,407 194,423,712 198,170,459 Cash Flows From Investing Activities Payments for the Stronghold Acquisition — — ( 18,511,170 ) Payments for the Founders Acquisition — — ( 62,227,145 ) Payments for the Lime Rock Acquisition ( 81,863,429 ) — — Payments to purchase oil and natural gas properties ( 2,528,932 ) ( 2,210,826 ) ( 2,162,585 ) Payments to develop oil and natural gas properties ( 95,207,027 ) ( 153,945,456 ) ( 152,559,314 ) Payments to acquire or improve fixed assets subject to depreciation ( 179,771 ) ( 185,524 ) ( 492,317 ) Proceeds from sale of fixed assets subject to depreciation 17,360 10,605 332,229 Proceeds from divestiture of oil and natural gas properties 100 121,232 1,554,558 Proceeds from sale of Delaware properties — — 7,600,699 Proceeds from sale of New Mexico properties — ( 144,398 ) 3,891,757 Proceeds from sale of CBP vertical wells — 5,500,000 — Insurance proceeds received for damage to oil and natural gas properties 260,446 — — Net Cash Used in Investing Activities ( 179,501,253 ) ( 150,854,367 ) ( 222,573,288 ) Cash Flows From Financing Activities Proceeds from revolving line of credit 231,822,997 130,000,000 225,000,000 Payments on revolving line of credit ( 196,822,997 ) ( 170,000,000 ) ( 215,000,000 ) Proceeds from issuance of common stock and warrants — — 12,301,596 Payments for taxes withheld on vested restricted shares, net ( 1,189,805 ) ( 919,249 ) ( 520,153 ) Proceeds from notes payable 1,648,539 1,560,281 1,637,513 Payments on notes payable ( 1,639,184 ) ( 1,597,618 ) ( 1,603,659 ) Payment of deferred financing costs ( 5,647,107 ) ( 88,450 ) ( 52,222 ) Reduction of financing lease liabilities ( 484,079 ) ( 954,298 ) ( 776,388 ) Net Cash Provided by (Used in) Financing Activities 27,688,364 ( 41,999,334 ) 20,986,687 Net Increase (Decrease) in Cash ( 963,482 ) 1,570,011 ( 3,416,142 ) Cash at Beginning of Period 1,866,395 296,384 3,712,526 Cash at End of Period $ 902,913 $ 1,866,395 $ 296,384 F-7 Table of Contents RING ENERGY, INC. STATEMENTS OF CASH FLOWS (CONTINUED) For the years ended December 31, 2025 2024 2023 Supplemental Cash Flow Information Cash paid for interest $ 32,363,614 $ 39,196,575 $ 38,009,164 Cash paid (refunded) for income taxes 347,487 72,213 72,213 Noncash Investing and Financing Activities Asset retirement obligation incurred during development $ 89,923 $ 695,553 $ 439,528 Asset retirement obligation acquired 2,780,280 — 2,090,777 Asset retirement obligation revision of estimate ( 78,480 ) 133,794 53,826 Asset retirement obligation sold ( 65,129 ) ( 3,219,651 ) ( 5,340,211 ) Operating lease assets obtained in exchange for new operating lease liability — — 1,713,677 Financing lease assets obtained in exchange for new financing lease liability, net (1) 707,964 738,240 894,996 Change in capitalized expenditures attributable to drilling projects financed through current liabilities 1,039,445 ( 3,896,948 ) ( 2,241,192 ) Supplemental Schedule for Lime Rock Acquisition Investing Activities - Cash Paid Cash paid to Lime Rock on closing $ 63,599,939 $ — $ — Escrow deposit released at closing 5,000,000 — — Direct transaction costs 2,576,648 — — Cash paid for fixed assets acquired ( 34,275 ) — — Purchase price adjustments paid to third parties 1,427,233 — — Cash received from Lime Rock for post-close adjustments ( 706,116 ) — — Payment of deferred cash payment 10,000,000 — — Payments for the Lime Rock Acquisition $ 81,863,429 $ — $ — Investing Activities - Noncash Assumption of suspense liability $ 459,096 $ — $ — Assumption of ad valorem tax liability 405,549 — — Assumption of asset retirement obligation 2,587,179 — — Deferred cash payment at fair value 9,415,066 — — Financing Activities - Noncash Common stock issued for acquisition 7,420,811 — — Supplemental Schedule for Founders Acquisition Investing Activities - Cash Paid Escrow deposit released at closing $ — $ — $ 7,500,000 Closing amount paid to Founders — — 42,502,799 Interest from escrow deposit — — 1,747 Direct transaction costs — — 1,361,843 Post-close adjustments — — ( 4,139,244 ) Payment of deferred cash payment — — 15,000,000 Payments for the Founders Acquisition $ — $ — $ 62,227,145 Investing Activities - Noncash Assumption of suspense liability $ — $ — $ 677,116 Assumption of asset retirement obligation — — 2,090,777 Assumption of ad valorem tax liability — — 234,051 Deferred cash payment at fair value — — 14,657,383 Supplemental Schedule for Stronghold Acquisition Investing Activities - Cash Paid Payment of deferred cash payment — — 15,000,000 Payment of post-close settlement — — 3,511,170 Payments for the Stronghold Acquisition $ — $ — $ 18,511,170 (1) Included within the financing lease assets obtained in exchange for new financing lease liability, net, is $ 144,216 and $ 45,436 of finance lease asset terminations for the years ended December 31, 2025 and 2024, respectively. The accompanying notes are an integral part of these financial statements. F-8 Table of Contents RING ENERGY, INC. NOTES TO FINANCIAL STATEMENTS Index to the Notes to the Financial Statements Note 1 — Organization, Basis of Presentation and Summary of Significant Accounting Policies Note 10 — Asset Retirement Obligation Note 2 — Revenue Recognition Note 11 — Stockholders' Equity Note 3 — Leases Note 12 — Employee Stock Options, Restricted Stock Award Plan, and 401(k) Note 4 — Earnings (Loss) Per Share Information Note 13 — Commitments and Contingencies Note 5 — Acquisitions & Divestitures Note 14 — Income Taxes Note 6 — Oil and Natural Gas Producing Activities Note 15 - Segment Reporting Note 7 — Derivative Financial Instruments Note 16 — Legal Matters Note 8 — Fair Value Measurements Note 17 — Subsequent Events Note 9 — Revolving Line of Credit Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) NOTE 1 — ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Nature of Operations – Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas. Liquidity and Capital Considerations – The Company strives to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include the Company’s net cash provided by operating activities, cash on hand, available borrowing capacity under its revolving credit facility, and proceeds from sales of non-strategic assets. While changes in oil and natural gas prices affect the Company’s liquidity, the Company has put in place hedges in seeking to protect a substantial portion of its cash flows from price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could still have a material adverse effect on the Company’s cash flows. The Company expects ongoing oil price volatility over an indeterminate term. Extended depressed oil prices have historically had and could have a material adverse impact on the Company’s oil revenue, which is mitigated to some extent by the Company’s hedge contracts. The Company believes that it has the ability to continue to fund its operations and service its debt by using cash flows from operations. Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. The Company's financial statements are based on a number of significant estimates, including estimates of oil and natural gas reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Actual results could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the Company's future results of operations. Fair Value Measurements – Fair value is 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 (exit price). The Financial Accounting Standards Board (“FASB”) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted F-9 Table of Contents quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. Fair Values of Financial Instruments – The carrying amounts reported for our revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts receivable and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs, and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy. Concentration of Credit Risk and Receivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and receivables. Cash and cash equivalents – The Company had cash in excess of federally insured limits of $ 652,913 and $ 1,616,395 as of December 31, 2025 and 2024, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. Accounts receivable – Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Refer to the " Major Purchasers " section below for detail on purchaser activity for the years ended December 31, 2025, 2024, and 2023. The following table reflects the Company's beginning and ending balances of its accounts receivables from purchasers of its oil and gas for the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Beginning balance of accounts receivable from purchasers of oil and gas $ 33,774,968 $ 37,879,779 $ 40,143,326 Ending balance of accounts receivable from purchasers of oil and gas 29,591,571 33,774,968 37,879,779 Joint interest billing receivables, net – The Company also has joint interest billing receivables. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself. Receivables from joint interest owners outstanding longer than the contractual payment terms are considered past due. The following table indicates the Company's provisions for credit loss expense associated with its joint interest billing receivables during the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Credit loss expense $ 19,029 $ 160,847 $ 134,007 The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of December 31, 2025 and 2024. F-10 Table of Contents 2025 2024 Joint interest billing receivables $ 1,824,753 $ 1,264,897 Allowance for credit losses ( 200,762 ) ( 181,733 ) Joint interest billing receivables, net $ 1,623,991 $ 1,083,164 The increase of $ 19,029 in the allowance for credit losses during the year ended December 31, 2025 was primarily for owner settlements considered uncollectible with no offsetting revenues held in suspense. For receivables, the Company's estimated credit loss allowance is estimated using historical loss information, current industry conditions and payment practices, as well as reasonable and supportable forecasts of future economic conditions. Credit risk is assessed based on days outstanding and other available information. Production imbalances – The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company recorded no imbalances as of December 31, 2025 or 2024. Cash and Cash Equivalents – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At December 31, 2025 and 2024, the Company had no such investments. Inventory – The full balance of the Company's inventory consists of materials and supplies for its operations, with no work in process or finished goods inventory balances. Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports the balance of its inventory at the lower of cost or net realizable value. Inventory balances are excluded from the Company's calculation of depletion. Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization. All of the Company’s capitalized costs, excluding inventory, are subject to amortization. The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs. All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and the depletion per barrel-of-oil-equivalent rate, for the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Depletion $ 95,079,057 $ 97,238,673 $ 87,442,546 Depletion rate, per barrel-of-oil-equivalent (Boe) $ 12.86 $ 13.52 $ 13.22 F-11 Table of Contents In addition, capitalized costs less accumulated depletion and related deferred income taxes are not allowed to exceed an amount (the full cost ceiling) equal to the sum of: 1) the present value of estimated future net revenues discounted at ten percent computed in compliance with SEC guidelines; 2) plus the cost of properties not being amortized; 3) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized; 4) less income tax effects related to differences between the book and tax basis of the properties. Due to the lower oil prices impacting the present value of estimated future net revenues, during the year ended December 31, 2025, the Company recorded impairments on oil and natural gas properties as a result of the ceiling test of $ 108.8 million. No impairments on oil and natural gas properties as a result of the ceiling test were recorded for the years ended December 31, 2024 or 2023. Land, Buildings and Structures, Equipment, Software, Leasehold Improvements, Automobiles, and UAV – Land, buildings and structures, equipment, software, leasehold improvements, automobiles, and unmanned aerial vehicles ("UAV") are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings and structures, equipment, software, leasehold improvements, automobiles, and UAV and placing them in service. Upon sale or abandonment, the cost of the fixed asset(s) and related accumulated depreciation are removed from the accounts and any gain or loss is recognized. Depreciation of buildings and structures, equipment, software, leasehold improvements, automobiles, and UAV is calculated using the straight-line method based upon the following estimated useful lives: Leasehold improvements 3 ‑ 5 years Office equipment and software 3 ‑ 7 years Equipment 5 ‑ 10 years Automobiles 4 years Buildings and structures 7 years UAV 3 years The following table provides information on the Company's depreciation expense for the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Depreciation expense $ 409,474 $ 405,772 $ 364,024 During the years ended December 31, 2025 2024, and 2023, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of owned vehicles, as follows: For the years ended December 31, 2025 2024 2023 Sale of owned vehicles $ ( 6,974 ) $ ( 14,239 ) $ ( 132,109 ) Sale of leased vehicles 453,374 103,932 44,981 Gain (loss) on disposal of assets $ 446,400 $ 89,693 $ ( 87,128 ) F-12 Table of Contents Accounts Payable The following table summarizes the Company's components of its current accounts payable balance presented in its Balance Sheets at December 31, 2025 and 2024: 2025 2024 Trade accounts payable $ 40,196,719 $ 39,289,431 Revenues payable 37,156,219 35,766,989 Accrued expenses 20,169,871 20,672,841 Accounts payable $ 97,522,809 $ 95,729,261 Trade accounts payable – The following table summarizes the Company's current trade accounts payable at December 31, 2025 and 2024: 2025 2024 Accounts payable related to vendors $ 33,012,524 $ 37,147,926 Other 7,184,195 2,141,505 Trade accounts payable $ 40,196,719 $ 39,289,431 Revenues payable – The following table summarizes the Company's current revenues and royalties payable at December 31, 2025 and 2024: 2025 2024 Revenue held in suspense $ 32,107,446 $ 28,166,335 Revenues and royalties payable 5,048,773 7,600,654 Revenues payable $ 37,156,219 $ 35,766,989 Accrued expenses – The following table summarizes the Company's current accrued expenses at December 31, 2025 and 2024: 2025 2024 Accrued capital expenditures $ 4,395,906 $ 3,645,377 Accrued lease operating expenses 5,149,712 5,313,315 Accrued interest 5,853,412 2,830,440 Accrued general and administrative expense 4,685,253 4,897,904 Other 85,588 3,985,805 Accrued expenses $ 20,169,871 $ 20,672,841 F-13 Table of Contents Notes Payable – At the end of May 2025, the Company renewed its control of well, general liability, pollution, umbrella, property, worker's compensation, auto, and D&O (directors and officers) insurance policies, funding the premiums with a promissory note with a face value after down payments of $ 1,648,539 . The APR for this note was 7.75 %. In November 2025, the Company renewed its cybersecurity insurance policy, paying the premium without financing through a note. At the end of May 2024, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $ 1,501,507 . In November 2024, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a face value after down payments of $ 58,773 . The APR for both notes was 7.98 %. At the end of May 2023, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, and funded the premiums with a promissory note with a total face value after down payments of $ 1,565,071 . In November 2023, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a total face value after down payments of $ 72,442 . The annual percentage rate (APR) for both notes was 7.08 %. As of December 31, 2025 and 2024, the notes payable balances included within current liabilities on the Balance Sheets were $ 505,752 and $ 496,397 , respectively. The following table reflects the weighted average notes payable balances and the weighted average interest rate on the weighted average notes payable outstanding during the period as of and for the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Weighted average notes payable balance $ 688,086 $ 651,789 $ 687,456 Weighted average interest rate on weighted average notes payable 8.59 % 8.63 % 7.23 % The following table shows interest paid related to notes payable for the years ended December 31, 2025, 2024, and 2023. This interest is included within "Interest (expense)" in the Statements of Operations. For the years ended December 31, 2025 2024 2023 Interest paid for notes payable $ 59,097 $ 56,261 $ 49,734 Revenue Recognition –The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "NOTE 2 — REVENUE RECOGNITION" for additional information. Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes. On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was enacted, which, among other items, allows for 100% bonus depreciation on a permanent basis for property acquired after January 19, 2025. Further, the OBBBA basis for Code F-14 Table of Contents Section 163(j) net interest expense deduction is based on EBITDA (earnings before interest, taxes, depreciation and amortization) rather than EBIT (earnings before interest and taxes) for taxable years beginning after December 31, 2024, and any disallowed interest expense can be carried forward indefinitely. We have incorporated these changes into our income tax provision for the year ended December 31, 2025. Accounting for Uncertainty in Income Taxes – In accordance with GAAP, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as a “major” tax jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2022 and after remain subject to examination. The Company’s federal income tax returns for the years ended December 31, 2007 and after remain subject to examination to the extent of the net operating loss (NOL) carryforwards. The Company’s franchise tax returns in Texas remain subject to examination for 2021 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the Statements of Operations. Leases – Upon adoption of ASU 2016-02, the Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less (i.e. short-term leases) and to not separate lease and non-lease components for all asset classes. The Company also elected to adopt the package of practical expedients that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases and the practical expedient regarding land easements that exist prior to adoption. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. Earnings (Loss) Per Share – Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the applicable period. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares. Major Purchasers – During the year ended December 31, 2025, sales to three purchasers represented 67 %, 13 %, and 9 %, respectively, of total oil, natural gas, and natural gas liquids sales. As of December 31, 2025, sales outstanding from these three purchasers represented 66 %, 10 %, and 6 %, respectively, of accounts receivable from purchasers. During the year ended December 31, 2024, sales to three purchasers represented 61 %, 14 %, and 13 %, respectively, of total oil, natural gas and natural gas liquids sales. As of December 31, 2024, sales outstanding from these three purchasers represented 64 %, 11 %, and 11 %, respectively, of accounts receivable from purchasers. During the year ended December 31, 2023, sales to three purchasers represented 66 %, 12 %, and 10 %, respectively, of total oil, natural gas, and natural gas liquids sales. As of December 31, 2023, sales outstanding from these three purchasers represented 65 %, 11 %, and 8 %, respectively, of accounts receivable from purchasers. Share-Based Employee Compensation – The Company has outstanding stock option grants, restricted stock unit awards, and performance stock unit awards to directors, officers and employees, which are described more fully below in "NOTE 12 — EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN, AND 401(K)". The Company recognizes the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and recognizes the related compensation expense over the period during which an employee is required to provide service in exchange for the award, which is generally the vesting period. Share-Based Compensation to Non-Employees – The Company accounts for share-based compensation issued to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of (i) the date at which a commitment for performance by the recipient to earn the equity instruments is reached or (ii) the date at which the recipient’s performance is complete. Share-Based Compensation – The following table summarizes the Company's share-based compensation, included with General and administrative expense within our Statements of Operations, incurred for the years ended December 31, 2025, 2024, and 2023. F-15 Table of Contents For the years ended December 31, 2025 2024 2023 Share-based compensation $ 6,135,957 $ 5,506,017 $ 8,833,425 Derivative Instruments and Hedging Activities – The Company periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. As the Company has not designated its derivative instruments as hedges for accounting purposes, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of Other Income (Expense) in the Statements of Operations. When applicable, the Company records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Refer to "NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS" for additional information. The Company uses the indirect method of reporting operating cash flows within the Statements of Cash Flows. Accordingly, the non-cash, unrealized gains and losses from derivative contracts are reflected as an adjustment to arrive at Net cash provided by operating activities. The total Gain (loss) on derivative contracts less the Cash received (paid) for derivative settlements, net represents the unrealized (mark to market) gain or loss on derivative contracts. Recently Adopted Accounting Pronouncements – In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR ("London Inter-Bank Offered Rate") or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. In December 2022, the FASB issued ASU 2022-06, " Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848" ("ASU 2022-06"), wh ich defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. The Company adopted ASU 2020-04 with an effective date of January 1, 2024. Beginning August 31, 2022, under the Company's Second Amended and Restated Credit Agreement, the Company's interest rates were transitioned from the LIBOR to the SOFR reference rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate. As such, the adoption and implementation of this ASU did not have a material impact on the Company’s financial statements. In October 2021, the FASB issued ASU 2021-08, " Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers” ("ASU 2021-08"). This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update became effective for public business entities beginning after December 15, 2022. The Company adopted ASU 2021-08 effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements, as its revenue is recognized when control transfers to the purchaser at the point of delivery, and no contract liabilities or assets are recognized in accordance with Accounting Standards Codification ("ASC") 606. In July 2023, the FASB issued ASU 2023-03, " Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock ." The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards. As the ASU did not provide any new ASC guidance, and there was no F-16 Table of Contents transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's financial statements. In November 2023, the FASB issued ASU 2023-07 " Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ." This update requires that a public entity with multiple reportable segments disclose significant segment expenses that are regularly provided to the chief operating decision maker ("CODM"), as well as other segment items that are included in the calculation of segment profit or loss. A public entity will also be required to disclose all annual disclosures about a reportable segment's profit or loss currently required by Topic 280 in interim periods. Although a public entity is permitted to disclose multiple measures of a segment's profit or loss, at least one of the reported segment profit or loss measures should be consistent with the measurement principles used in measuring the corresponding amounts of the public entity's consolidated financial statements. Further, a public entity must disclose the title and position of the CODM as well as how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Finally, the update requires that a public entity that has a single reportable segment provide all the disclosures required by the amendments in this update and all existing segment disclosures in Topic 280. The amendments in this update became effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 effective January 1, 2024. In December 2023, the FASB issued ASU 2023-09 " Income Taxes (Topic 740): Improvements to Income Tax Disclosures. " The amendments from this update provide for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. Specifically, public business entities are required to disclose a tabular reconciliation, using both percentages and reporting currency amounts, showing detail from eight specific categories: (a) state and local income tax net of federal (national) income tax effect, (b) foreign tax effects, (c) effect of changes in tax laws or rates enacted in the current period, (d) effect of cross-border tax laws, (e) tax credits, (f) changes in valuation allowances, (g) nontaxable or nondeductible items, and (h) changes in unrecognized tax benefits. In addition, public business entities are required to separately disclose any reconciling item, disaggregated by nature and/or jurisdiction, in which the effect of the reconciling item is equal to or greater than five percent of the amount computed by multiplying the income (or loss) from continuing operations before income taxes by the applicable statutory income tax rate. Also, for the state and local category, a public business entity is required to provide a qualitative description of the states and local jurisdictions that make up the majority (greater than 50 percent) of the category. Further, the amount of income taxes paid (net of refunds received) are required to be disaggregated by (i) federal (national), state, and foreign taxes, and (ii) by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than five percent of total income taxes paid (net of refunds received). Finally, the amendments from this update require that all entities disclose (i) income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign and (ii) income tax expense (or benefit) from continuing operations disaggregated by federal, state, and foreign. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. As such, the Company adopted ASU 2023-09 effective January 1, 2025. The Company has included the applicable enhanced disclosures prospectively in its annual financial statements for the year ended December 31, 2025. In March 2024, the FASB issued ASU 2024-02 " Codification Improvements – Amendments to Remove References to the Concepts Statements " ("ASU 2024-02"), which contains amendments to the Codification to remove references to various FASB Concepts Statements. In most instances, the references are extraneous and not required to understand or apply the guidance. Generally, ASU 2024-02 is not intended to result in significant accounting changes for most entities. ASU 2024-02 is effective for the Company for fiscal years beginning after December 15, 2024. As such, the Company adopted ASU 2024-02 effective January 1, 2025. The adoption did not have a material impact on the Company's financial statements. Recent Accounting Pronouncements – In October 2023, the FASB issued ASU 2023-06, " Disclosure Improvements: Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative ." This update modifies the disclosure or presentation requirements of a variety of Topics in the Codification, which should be applied prospectively. For instance, within ASC 230-10 Statement of Cash Flows – Overall, the amendment requires an accounting policy disclosure in annual periods of where cash flows associated with their derivative instruments and their related gains and losses are presented in the statement of cash flows. Additionally, within ASC 260-10 Earnings Per Share – Overall, the amendment requires disclosure of the methods used in the diluted earnings-per-share computation for each dilutive security and clarifies that certain disclosures should be made during interim periods. The Company is currently assessing the impact of this update on its financial statements and related notes. If by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity. F-17 Table of Contents In November 2024, the FASB issued ASU 2024-03, " Income Statement - Reporting Comprehensive Income - Expenses Disaggregation Disclosures (Subtopic 220-40) - Disaggregation of Income Statement Expenses" ("ASU 2024-03"). The purpose of this update is to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expense captions (such as cost of sales, SG&A, and research and development). As clarified in ASU 2025-01, "Income Statement – Reporting Comprehensive Income – Expenses Disaggregation Disclosures (Subtopic 220-40) – Clarifying the Effective Date," the amendments in this update are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures. In July 2025, the FASB issued ASU 2025-05, " Financial Instruments - Credit Losses (Topic 326) - Measurement of Credit Losses for Accounts Receivable and Contract Assets ," that provides for a practical expedient for estimating expected credit losses which assumes that current conditions as of the balance sheet date do not change for the remaining life of the asset. The amendments will be effective prospectively for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures. In December 2025, the FASB issued ASU 2025-11, " Interim Reporting (Topic 270) - Narrow-Scope Improvements ," which provides clarity on the current interim disclosure requirements. The update also includes the addition of a disclosure principle which requires entities to disclose events since the last annual reporting period that have a material impact on the entity. The application of the update is effective for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted, and either prospective or retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its interim financial disclosures. F-18 Table of Contents NOTE 2 — REVENUE RECOGNITION The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and NGLs. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content, and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. Once consideration is received from the purchaser, the Company records any variances between the estimates and actual amounts, which has historically not been significant. Oil sales . Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales . Under the majority of the Company’s natural gas sales processing contracts, the Company delivers unprocessed natural gas to midstream processing entities at the wellhead, and the midstream processing entities obtain control of the natural gas and NGLs at the wellhead. The midstream processing entities gather and process the natural gas and NGLs and remit proceeds to the Company for the resulting sale of natural gas and NGLs. Under these processing agreements, the Company recognizes revenue when control transfers to the purchasers at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. As such, the Company accounts for any fees and deductions as a reduction of the transaction price. The Company has only one minor contract with a natural gas processing entity in place where the point of control does not pass at the wellhead. Under this agreement, the point of control of the gas dictates that the associated fees are recorded as an expense. Disaggregation of revenue. The following table presents revenues disaggregated by product for the years ended December 31, 2025, 2024, and 2023. For the years ended December 31, 2025 2024 2023 Oil, Natural Gas, and Natural Gas Liquids Revenues Oil $ 307,553,614 $ 363,971,394 $ 349,044,863 Natural gas (1) ( 9,297,614 ) ( 9,265,335 ) 334,175 Natural gas liquids 8,922,072 11,621,355 11,676,963 Total oil, natural gas, and natural gas liquids revenues $ 307,178,072 $ 366,327,414 $ 361,056,001 (1) In 2024 and 2025, the Company experienced a net negative total gas revenue, due to the significant reduction in gross realized sales prices per Mcf, coupled with the growth in the plant fees per Mcf. F-19 Table of Contents NOTE 3 — LEASES The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The current Midland office is under a five-year lease, effective October 1, 2022 and ending September 30, 2027. The Woodlands office is currently under a 71-month (five years and 11-month) lease, effective May 9, 2023. The future payments for these office spaces are reflected in the future lease payments schedule below. The Company has month to month leases for office equipment and compressors used in its operations on which the Company has elected to apply ASU 2016-02 (i.e. to not capitalize). The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases is reflected in the short-term lease costs within Lease operating expenses, shown below. The Company has financing leases for vehicles. These leases have an initial term of 36 months at the end of which the Company owns the vehicles. These vehicles are generally sold at the end of their term and the proceeds are settled in cash or applied to a new vehicle. Future lease payments associated with these operating and financing leases as of December 31, 2025 are as follows: 2026 2027 2028 2029 2030 Thereafter Total Operating lease payments $ 636,649 $ 460,497 $ 250,606 $ 149,628 $ — $ — $ 1,497,380 Financing lease payments 803,745 465,880 159,374 — — — 1,428,999 The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company's leases as of the dates indicated. As of December 31, 2025 2024 Operating leases Weighted average remaining lease term (in years) 2.71 3.45 Weighted average discount rate 4.50 % 4.50 % Finance leases Weighted average remaining lease term (in years) 1.99 1.85 Weighted average discount rate 7.50 % 7.31 % F-20 Table of Contents The following table represents a reconciliation between the undiscounted future cash flows in the table above and the operating and financing lease liabilities disclosed in the Balance Sheets: As of December 31, 2025 2024 Operating lease liability, current portion $ 586,614 $ 648,204 Operating lease liability, non-current portion 819,223 1,405,837 Operating lease liability, total $ 1,405,837 $ 2,054,041 Total undiscounted future cash flows (sum of future operating lease payments) $ 1,497,380 $ 2,224,840 Imputed interest 91,543 170,799 Undiscounted future cash flows less imputed interest $ 1,405,837 $ 2,054,041 Financing lease liability, current portion $ 730,564 $ 906,119 Financing lease liability, non-current portion 593,146 647,078 Financing lease liability, total $ 1,323,710 $ 1,553,197 Total undiscounted future cash flows (sum of future financing lease payments) $ 1,428,999 $ 1,667,763 Imputed interest 105,289 114,566 Undiscounted future cash flows less imputed interest $ 1,323,710 $ 1,553,197 The following table provides supplemental information regarding lease costs in the Statements of Operations for the years ended December 31, 2025, 2024, and 2023. 2025 2024 2023 Operating lease costs $ 700,362 $ 700,362 $ 541,801 Short-term lease costs (1) $ 4,714,675 $ 4,083,088 $ 5,096,723 Financing lease costs: Amortization of financing lease assets (2) $ 925,619 $ 1,058,398 $ 803,721 Interest on financing lease liabilities (3) $ 107,754 $ 121,293 $ 101,269 (1) Amount included in Lease operating expenses (2) Amount included in Depreciation, depletion and amortization (3) Amount included in Interest (expense) During the years ended December 31, 2025, 2024, and 2023, the Company recorded a gain (loss) on disposal of assets, which was impacted by the sale of leased vehicles, as follows: For the years ended December 31, 2025 2024 2023 Sale of owned vehicles $ ( 6,974 ) $ ( 14,239 ) $ ( 132,109 ) Sale of leased vehicles 453,374 103,932 44,981 Gain (loss) on disposal of assets $ 446,400 $ 89,693 $ ( 87,128 ) F-21 Table of Contents NOTE 4 — EARNINGS (LOSS) PER SHARE INFORMATION The following table presents the calculation of the Company's basic and diluted earnings (loss) per share for the years ended December 31, 2025, 2024 and 2023. For all dilutive securities, the treasury stock method of calculating the incremental shares is applied. For the years ended December 31, 2025 2024 2023 Net Income (Loss) $ ( 34,731,199 ) $ 67,470,314 $ 104,864,641 Basic Weighted-Average Shares Outstanding 204,984,223 197,937,683 190,589,143 Effect of dilutive securities: Stock options — — — Restricted stock units — 1,695,791 1,292,582 Performance stock units — 603,867 438,818 Common warrants — 40,039 3,044,307 Diluted Weighted-Average Shares Outstanding 204,984,223 200,277,380 195,364,850 Basic Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.55 Diluted Earnings (Loss) per Share $ ( 0.17 ) $ 0.34 $ 0.54 The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the years ended December 31, 2025, 2024 and 2023, as their effect would have been anti-dilutive. 2025 2024 2023 Anti-dilutive securities: Stock options to purchase common stock 62,433 66,511 264,966 Unvested restricted stock units 5,211,248 32,231 56,153 Unvested performance stock units 2,822,081 1,260,595 1,445,804 NOTE 5 — ACQUISITIONS & DIVESTITURES Stronghold Acquisition On July 1, 2022, Ring, as buyer, and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), as seller, entered into a purchase and sale agreement (the “Stronghold Purchase Agreement”). Pursuant to the Stronghold Purchase Agreement, Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres located in the Central Basin Platform of the Texas Permian Basin. On August 31, 2022, Ring completed the Stronghold Acquisition. The fair value of consideration paid to Stronghold was approximately $ 394.0 million, of which $ 165.9 million, net of customary purchase price adjustments, was paid in cash at closing, $ 15.0 million was paid in cash on the sixth-month anniversary of the closing date. Shortly after closing, approximately $ 4.5 million was paid for inventory and vehicles and approximately $ 1.8 million was paid for August oil derivative settlements for certain novated hedges. The cash portion of the consideration was funded primarily from borrowings under a new fully committed revolving credit facility (the “Credit Facility”) underwritten by Truist Securities, Citizens Bank, N.A., KeyBanc Capital Markets Inc., and Mizuho Bank, Ltd. The borrowing base of the $ 1.0 billion Credit Facility was increased from $ 350 million to $ 600 million at the closing of the Stronghold Acquisition. The remaining consideration consisted of 21,339,986 shares of common stock and 153,176 shares of newly created Series A Convertible Preferred Stock, par value $ 0.001 (“Preferred Stock”) which was converted into 42,548,892 shares of common stock on October 27, 2022. In addition, Ring assumed $ 24.8 million of derivative liabilities, $ 1.7 million of items in suspense and $ 14.5 million in asset retirement obligations. F-22 Table of Contents Delaware Basin Divestiture On May 11, 2023, the Company completed the divestiture of its Delaware Basin assets to an unaffiliated party for $ 8.3 million. The sale had an effective date of March 1, 2023. The final cash consideration was approximately $ 7.6 million. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $ 2.3 million. Founders Acquisition On July 10, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, entered into an Asset Purchase Agreement (the “Founders Purchase Agreement”). Pursuant to the closing of the Founders Purchase Agreement, on August 15, 2023 the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders located in the Central Basin Platform of the Texas Permian Basin in Ector County, Texas, for a purchase price (the “Purchase Price”) of (i) a cash deposit of $ 7.5 million paid on July 11, 2023 into a third-party escrow account as a deposit pursuant to the Founders Purchase Agreement, (ii) approximately $ 42.5 million in cash paid on the closing date, net of approximately $ 10 million of preliminary and customary purchase price adjustments with an effective date of April 1, 2023, and (iii) a deferred cash payment of $ 11.9 million paid on December 18, 2023, net of customary purchase price adjustments. The Founders Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on Ring’s books as of the date of the closing of the Founders Acquisition. Additionally, costs directly related to the Founders Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Founder’s oil and gas properties. The inputs and assumptions related to the oil and gas properties are categorized as level 3 in the fair value hierarchy. The following table represents the final allocation of the total cost of the Founders Acquisition to the assets acquired and liabilities assumed as of the Founders Acquisition date: Consideration: Cash consideration Escrow deposit released at closing $ 7,500,000 Closing amount paid to Founders 42,502,799 Interest from escrow deposit 1,747 Fair value of deferred payment liability 14,657,383 Post-close adjustments ( 4,139,244 ) Total cash consideration $ 60,522,685 Direct transaction costs 1,361,843 Total consideration $ 61,884,528 Fair value of assets acquired: Oil and natural gas properties $ 64,886,472 Amount attributable to assets acquired $ 64,886,472 Fair value of liabilities assumed: Suspense liability $ 677,116 Asset retirement obligations 2,090,777 Ad valorem tax liability 234,051 Amount attributable to liabilities assumed $ 3,001,944 Net assets acquired $ 61,884,528 Approximately $ 18.0 million of revenues and $ 5.0 million of direct operating expenses attributed to the Founders Acquisition are included in the Company’s Statements of Operations for the period from August 16, 2023 through December 31, 2023. F-23 Table of Contents New Mexico Divestiture On September 27, 2023, the Company completed the divestiture of its operated New Mexico assets to an unaffiliated party for $ 4.5 million, resulting in cash consideration of approximately $ 3.6 million. The sale had an effective date of June 1, 2023. As part of the divestiture, the buyer assumed an asset retirement obligation balance of approximately $ 2.4 million. Gaines County Texas Sale On December 29, 2023, the Company completed the sale of certain oil and gas properties in Gaines County, Texas to an unaffiliated party for $ 1.5 million, which resulted in cash proceeds of $ 1.4 million, net of $ 0.1 million in sales fees. The sale had an effective date of December 1, 2023. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $ 0.5 million. CBP Vertical Well Sale On September 30, 2024, the Company completed the sale of certain oil and gas properties, including vertical wells and associated facilities, within Andrews County, Texas and Gaines County, Texas to an unaffiliated party for a sales price of $ 5.5 million, with cash consideration being the same. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $ 2.7 million. Yoakum County Purchase On December 24, 2024, the Company completed the purchase of assorted leases and additional well interests in Yoakum County, Texas from an unaffiliated party for approximately $ 1.4 million. The purchase had an effective date of December 1, 2024 with a required down payment of $ 175,000 due at closing and the remainder of $ 1,175,000 due in January 2025. Lime Rock Acquisition On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”) and Lime Rock Resources IV-C, L.P. ("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”), which provided that the Company would acquire (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of the Texas Permian Basin in Andrews County, Texas (the "Lime Rock Assets"). On March 31, 2025, the Company and Lime Rock consummated the transactions contemplated in the Lime Rock Acquisition whereby the Company acquired the Lime Rock Assets for aggregate consideration consisting of: (i) approximately $ 69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $ 10.0 million paid on December 31, 2025, and (iii) 6,452,879 shares of common stock. The Lime Rock Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation to the underlying assets acquired, on a relative fair value basis, was recorded as of the date of the closing of the Lime Rock Acquisition. Additionally, costs directly related to the Lime Rock Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Lime Rock's oil and gas properties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the fair value hierarchy. F-24 Table of Contents The following table represents the final allocation of the total cost of the Lime Rock Acquisition to the assets acquired and liabilities assumed as of the closing date of the Lime Rock Acquisition: Consideration: Common stock consideration Shares of common stock issued 6,452,879 Common stock price as of March 31, 2025 $ 1.15 Total common stock consideration $ 7,420,811 Cash consideration Escrow deposit released at closing $ 5,000,000 Closing amount paid to Lime Rock 63,599,939 Fair value of deferred payment liability 9,415,066 Post-close adjustments 721,116 Total cash consideration $ 78,736,121 Direct transaction costs 2,576,648 Total consideration $ 88,733,580 Fair value of assets acquired: Oil and natural gas properties $ 92,111,309 Fixed assets 34,275 Joint interest billing receivable 39,820 Amount attributable to assets acquired $ 92,185,404 Fair value of liabilities assumed: Suspense liability $ 459,096 Asset retirement obligations 2,587,179 Ad valorem tax liability 405,549 Amount attributable to liabilities assumed $ 3,451,824 Net assets acquired $ 88,733,580 F-25 Table of Contents NOTE 6 — OIL AND NATURAL GAS PRODUCING ACTIVITIES Set forth below is certain information regarding the aggregate capitalized costs of oil and natural gas properties and costs incurred by the Company for its oil and natural gas property acquisitions, development and exploration activities: Capitalized Costs As of December 31, 2025 2024 2023 Oil and natural gas properties, full cost method Proved properties $ 1,891,510,431 $ 1,809,309,848 $ 1,663,548,249 Unproved properties — — — Total oil and natural gas properties, full cost method $ 1,891,510,431 $ 1,809,309,848 $ 1,663,548,249 Accumulated depletion of oil and natural gas properties ( 564,169,311 ) ( 469,786,336 ) ( 373,280,583 ) Net oil and natural gas properties capitalized $ 1,327,341,120 $ 1,339,523,512 $ 1,290,267,666 Costs Incurred in Oil and Gas Producing Activities For the years ended December 31, 2025 2024 2023 Payments to acquire oil and natural gas properties $ 84,392,361 $ 2,210,826 $ 82,900,900 Payments to explore oil and natural gas properties — — — Payments to develop oil and natural gas properties 95,207,027 153,945,456 152,559,314 Total costs incurred $ 179,599,388 $ 156,156,282 $ 235,460,214 NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It utilizes derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements. From time to time, the Company enters into derivative contracts to protect the Company’s cash flow from price fluctuation and maintain its capital programs. The Company has historically used costless collars, deferred premium puts, or swaps for this purpose. Oil derivative contracts are based on WTI crude oil prices and natural gas contacts are based on the Henry Hub. A “costless collar” is the combination of two options, a put option (floor) and call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. Similar to costless collars, there is no cost to enter into the swap contracts. A deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract. The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in the Company's Balance Sheets. The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Balance Sheets. The Company has not designated its derivative instruments as hedges for accounting purposes, and, as a result, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of "Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Statements of Operations. F-26 Table of Contents The following presents the impact of the Company’s contracts on its Balance Sheets for the periods indicated. As of December 31, 2025 2024 Commodity derivative instruments, marked to market: Derivative assets, current $ 21,468,134 $ 5,497,057 Derivative assets, noncurrent $ 9,739,430 $ 5,473,375 Derivative liabilities, current $ 841,193 $ 6,410,547 Derivative liabilities, noncurrent $ 2,512,692 $ 2,912,745 The components of “Gain (loss) on derivative contracts” from the Statements of Operations are as follows for the respective periods: For the years ended December 31, 2025 2024 2023 Oil derivatives: Realized gain (loss) on oil derivatives $ 3,834,312 $ ( 10,264,202 ) $ ( 11,364,484 ) Unrealized gain (loss) on oil derivatives 23,367,255 6,859,929 9,462,374 Gain (loss) on oil derivatives $ 27,201,567 $ ( 3,404,273 ) $ ( 1,902,110 ) Natural gas derivatives: Realized gain (loss) on natural gas derivatives $ 1,617,988 $ 5,070,529 $ 2,279,564 Unrealized gain (loss) on natural gas derivatives 2,839,284 ( 4,032,173 ) 2,389,708 Gain (loss) on natural gas derivatives $ 4,457,272 $ 1,038,356 $ 4,669,272 Gain (loss) on derivative contracts $ 31,658,839 $ ( 2,365,917 ) $ 2,767,162 The components of “Cash received (paid) for derivative settlements, net” within the Statements of Cash Flows are as follows for the respective periods: For the years ended December 31, 2025 2024 2023 Cash flows from operating activities Cash received (paid) for oil derivatives $ 3,834,312 $ ( 10,264,202 ) $ ( 11,364,484 ) Cash received (paid) for natural gas derivatives 1,617,988 5,070,529 2,279,564 Cash received (paid) for derivative settlements, net $ 5,452,300 $ ( 5,193,673 ) $ ( 9,084,920 ) F-27 Table of Contents The following tables reflect the details of current derivative contracts as of December 31, 2025 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts). Oil Hedges (WTI) Q1 2026 Q2 2026 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 Swaps: Hedged volume (Bbl) 608,350 577,101 171,400 529,000 509,500 492,000 432,000 412,963 Weighted average swap price $ 67.95 $ 66.50 $ 62.26 $ 65.34 $ 62.82 $ 60.45 $ 61.80 $ 57.59 Two-way collars: Hedged volume (Bbl) — — 379,685 — — — — — Weighted average put price $ — $ — $ 60.00 $ — $ — $ — $ — $ — Weighted average call price $ — $ — $ 72.50 $ — $ — $ — $ — $ — Gas Hedges (Henry Hub) Q1 2026 Q2 2026 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 NYMEX Swaps: Hedged volume (MMBtu) 448,854 1,165,628 600,016 1,072,305 439,678 423,035 1,079,906 1,046,151 Weighted average swap price $ 4.19 $ 3.82 $ 4.19 $ 3.99 $ 4.02 $ 4.02 $ 3.86 $ 4.02 Two-way collars: Hedged volume (MMBtu) 456,850 139,000 648,728 128,000 717,000 694,000 — — Weighted average put price $ 3.50 $ 3.50 $ 3.10 $ 3.50 $ 3.99 $ 3.00 $ — $ — Weighted average call price $ 5.11 $ 5.42 $ 4.24 $ 5.42 $ 5.21 $ 4.32 $ — $ — Gas Hedges (Henry Hub) Q1 2028 Q2 2028 Q3 2028 Q4 2028 Q1 2029 Q2 2029 Q3 2029 Q4 2029 NYMEX Swaps: Hedged volume (MMBtu) 1,012,567 984,322 956,865 931,539 908,117 886,933 866,585 846,134 Weighted average swap price $ 3.77 $ 3.77 $ 3.77 $ 3.77 $ 3.67 $ 3.67 $ 3.67 $ 3.67 F-28 Table of Contents Gas Hedges (basis differential) Q1 2026 Q2 2026 Q3 2026 Q4 2026 Q1 2027 Q2 2027 Q3 2027 Q4 2027 El Paso Permian Basin basis swaps: Hedged volume (MMBtu) — — — — 960,307 636,710 615,547 596,306 Weighted average spread price (1) $ — $ — $ — $ — $ 0.72 $ 0.67 $ 0.67 $ 0.67 Waha basis swaps: Hedged volume (MMBtu) — — — — 196,372 480,325 464,360 449,846 Weighted average spread price (1) $ — $ — $ — $ — $ 0.78 $ 0.78 $ 0.78 $ 0.78 Gas Hedges (basis differential) Q1 2028 Q2 2028 Q3 2028 Q4 2028 Q1 2029 Q2 2029 Q3 2029 Q4 2029 El Paso Permian Basin basis swaps: Hedged volume (MMBtu) 577,163 561,064 545,413 530,977 517,628 505,552 493,953 482,296 Weighted average spread price (1) $ 0.60 $ 0.60 $ 0.60 $ 0.60 $ 0.57 $ 0.57 $ 0.57 $ 0.57 Waha basis swaps: Hedged volume (MMBtu) 435,403 423,259 411,453 400,562 390,490 381,381 372,632 363,837 Weighted average spread price (1) $ 0.68 $ 0.68 $ 0.68 $ 0.68 $ 0.63 $ 0.63 $ 0.63 $ 0.63 (1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude. (1) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above. F-29 Table of Contents NOTE 8 — FAIR VALUE MEASUREMENTS Fair value is 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 (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary. F-30 Table of Contents The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS"). Fair Value Measurement Classification Quoted prices in Active Markets for Identical Assets or (Liabilities) (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total As of December 31, 2024 Commodity Derivatives - Assets $ — $ 10,970,432 $ — $ 10,970,432 Commodity Derivatives - Liabilities — ( 9,323,292 ) — ( 9,323,292 ) Total $ — $ 1,647,140 $ — $ 1,647,140 As of December 31, 2025 Commodity Derivatives - Assets $ — $ 31,207,564 $ — $ 31,207,564 Commodity Derivatives - Liabilities — ( 3,353,885 ) — ( 3,353,885 ) Total $ — $ 27,853,679 $ — $ 27,853,679 The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. F-31 Table of Contents NOTE 9 — REVOLVING LINE OF CREDIT On June 18, 2025, the Company, as borrower, Bank of America, N.A. as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into that certain Third Amended and Restated Credit Agreement (the "Credit Agreement"), with a maximum borrowing base of $ 1 billion secured by substantially all of the assets of the Company and a maturity date of June 2029. The Credit Agreement has a borrowing base of $ 585 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions. The Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, income tax expense, depreciation, depletion and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80 %; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75 %. The reference rate in the Credit Agreement is the Secured Overnight Financing Rate ("SOFR"). The interest rate on each SOFR Loan will (i) be the adjusted term SOFR for the applicable interest period plus (ii) a margin between 2.75 % and 3.75 % (depending on the then-current level of borrowing base usage) plus (iii) a 0.10 % SOFR adjustment. The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Agreement) plus 0.5 % per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00 % per annum and (iv) 1.00 % per annum, plus (b) a margin between 1.75 % and 2.75 % per annum (depending on the then-current level of borrowing base usage). The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Agreement) of 1.0 to 1.0. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50 % of the projected production from its proved, developed, and producing oil and gas. However, on any hedge testing date, (a) if the borrowing base utilization is less than 25 % and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0 % from such hedge testing date to the next succeeding hedge testing date and (b) if the borrowing base utilization percentage is equal to or greater than 25 %, but less than 50 % and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25 % from such hedge testing date to the next succeeding hedge testing date. As of December 31, 2025, $ 420 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Credit Agreement. Under the Credit Agreement, the applicable percentage for the unused commitment fee is 0.5 % per annum for all levels of borrowing base utilization. As of December 31, 2025, the Company's unused line of credit was $ 165.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $ 420 million and standby letters of credit of $ 35,000 in total ($ 10,000 with a federal agency and $ 25,000 with an insurance company for New Mexico state surety bonds) from the $ 585 million borrowing base. F-32 Table of Contents NOTE 10 — ASSET RETIREMENT OBLIGATION The Company records the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense, and any revisions made to the costs or timing estimates. The asset retirement obligation is incurred using an annual credit-adjusted risk-free discount rate at the applicable dates. A reconciliation of the asset retirement obligation for the years ended December 31, 2025, 2024 and 2023 is as follows: Balance, December 31, 2022 $ 30,226,306 Liabilities acquired 2,090,777 Liabilities incurred 439,528 Liabilities sold ( 5,340,211 ) Liabilities settled ( 647,828 ) Revision of estimate (1) 53,826 Accretion expense 1,425,686 Balance, December 31, 2023 $ 28,248,084 Liabilities incurred 695,553 Liabilities sold ( 3,219,651 ) Liabilities settled ( 855,561 ) Revision of estimate (1) 133,794 Accretion expense 1,380,298 Balance, December 31, 2024 $ 26,382,517 Liabilities acquired 2,780,280 Liabilities incurred 89,923 Liabilities sold ( 65,129 ) Liabilities settled ( 208,411 ) Revision of estimate (1) ( 78,480 ) Accretion expense 1,490,255 Balance, December 31, 2025 $ 30,390,955 (1) Several factors are considered in the annual review process, including current estimates for removal cost and estimated remaining useful life of the assets. The revisions recorded during the year ended December 31, 2025 included updated interests for our working interest partners. The revisions recorded during the years ended December 31, 2024 and 2023 were related to shorter estimated useful lives, with regards to planned dates to plug and abandon such assets. The following table presents the Company's current and non-current asset retirement obligation balances as of the dates specified. December 31, 2025 December 31, 2024 Asset retirement obligations, current $ 418,526 $ 517,674 Asset retirement obligations, non-current 29,972,429 25,864,843 Asset retirement obligations $ 30,390,955 $ 26,382,517 F-33 Table of Contents NOTE 11 — STOCKHOLDERS' EQUITY The Company was authorized to issue 225,000,000 shares of common stock, with a par value of $ 0.001 per share, and 50,000,000 shares of preferred stock with a par value per share of $ 0.001 per share. On May 25, 2023, at the Company's annual meeting of stockholders, the Company's stockholders approved an amendment (the "Charter Amendment") to the Articles of Incorporation of the Company to increase the authorized shares of common stock from 225,000,000 to 450,000,000 . Issuance of equity instruments in public and private offerings – In October 2020, the Company closed on an underwritten public offering of (i) 9,575,800 shares of common stock, (ii) 13,428,500 Pre-Funded Warrants and (iii) 23,004,300 warrants to purchase common stock (the “Common Warrants”) at a combined purchase price of $ 0.70 . This includes a partial exercise of the over-allotment. The Common Warrants have a term of five years ending in October 2025 and an exercise price of $ 0.80 per share. Gross proceeds totaled $ 16,089,582 . Concurrently with the underwritten public offering, the Company closed on a registered direct offering of (i) 3,500,000 shares of common stock, (ii) 3,300,000 Pre-Funded Warrants and (iii) 6,800,000 Common Warrants at a combined purchase price of $ 0.70 per share of common stock and Pre-Funded Warrants. The Common Warrants have a term of five years ending in October 2025 and an exercise price of $ 0.80 per share. Gross proceeds totaled $ 4,756,700 . Total gross proceeds from the 2020 underwritten public offering and the registered direct offering aggregated $ 20,846,282 . Total net proceeds for the Common Warrants exercised in 2020 aggregated $ 19,379,832 . Common stock issued pursuant to warrant exercise - In December 2020, the Company issued 3,300,000 shares of common stock pursuant to the exercise of Pre-Funded Warrants issued in the October 2020 registered direct offering. Gross and net proceeds were $ 3,300 . In January 2021, the remaining 13,428,500 Pre-Funded Warrants were exercised. During the year ended December 31, 2021, 442,600 of the Common Warrants were exercised. Accordingly, the number of Common Warrants outstanding as of December 31, 2021 was 29,361,700 . During the year ended December 31, 2022, a total of 10,253,907 Common Warrants were exercised, leaving 19,107,793 Common Warrants outstanding as of December 31, 2022. During February and March 2023, a total of 4,517,427 Common Warrants were exercised, at the exercise price of $ 0.80 per share. On April 11 and 12, 2023, the Company and certain holders of the common warrants (the “Participating Holders”) entered into a form of Warrant Amendment and Exercise Agreement (the “Exercise Agreement”) pursuant to which the Company agreed to reduce the exercise price of an aggregate of 14,512,166 common warrants held by such Participating Holders from $ 0.80 to $ 0.62 per share (the “Reduced Exercise Price”) in consideration for the immediate exercise of the common warrants held by such Participating Holders in full at the Reduced Exercise Price in cash. The Company received aggregate gross proceeds of $ 8,997,543 from the exercise of the common warrants by the Participating Holders pursuant to the Exercise Agreement, which was recognized as an equity issuance cost in accordance with ASC 815-40-35-17(a). In the Statement of Stockholders' Equity, the net impact to Stockholders' Equity is $ 8,687,655 , which is net of $ 309,888 in advisory fees. As of December 31, 2023, a total of 78,200 Common Warrants remained outstanding. No Common Warrants were exercised during 2024, so a total of 78,200 Common Warrants remained outstanding as of December 31, 2024. In October 2025, the remaining 78,200 Common Warrants expired, and as such, no Common Warrants remained outstanding as of December 31, 2025. F-34 Table of Contents NOTE 12 — EMPLOYEE STOCK OPTIONS, RESTRICTED STOCK AWARD PLAN, AND 401(K) Share-based compensation expense charged against income during the years ended December 31, 2025, 2024, and 2023 was as follows. These amounts are included in General and administrative expense in the Statements of Operations. For the years ended December 31, 2025 2024 2023 Share-based compensation expense from: Employee stock options $ — $ — $ — Restricted stock unit grants 4,214,928 3,544,748 4,537,026 Performance stock unit awards 1,921,029 1,961,269 4,296,399 Total share-based compensation $ 6,135,957 $ 5,506,017 $ 8,833,425 During the year ended December 31, 2025, one former executive officer separated from the Company. As part of the executive officer's separation agreement, the vesting of the officer’s outstanding performance stock units and restricted stock units were accelerated. The impact to share-based compensation expense resulting from this modification was $ 133,671 . During the year ended December 31, 2024, two former executive officers separated from the Company, with both officers forfeiting their performance stock units. One officer entered into a consulting agreement with the Company which modified his restricted stock unit agreements to continue to vest through March 31, 2025. The other officer forfeited his restricted stock units. The total forfeitures related to these executive officers separating from the Company resulted in a reduction to share-based compensation expense of $ 1,448,076 . In 2011, the Board of Directors (the "Board") of the Company approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the shareholders. As of December 31, 2025, there were no shares eligible for grant, either as stock options or as restricted stock, under the 2011 Plan. In 2021, the Board and Company stockholders approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (the “2021 Plan”). The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing. At the 2023 Annual Meeting of Stockholders, the stockholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million. At the 2025 Annual Meeting of Stockholders, the stockholders approved a second amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 11.5 million. As of December 31, 2025, there were 11,785,291 shares available for grant under the 2021 Plan. F-35 Table of Contents Employee Stock Options – No stock options were granted in the years ended December 31, 2025, 2024, or 2023. All outstanding stock option awards vest at the rate of 20 % each year over five years beginning one year from the date granted and expire ten years from the grant date. A summary of the status of the stock options as of December 31, 2025, 2024, and 2023 and changes during the years ended December 31, 2025, 2024, and 2023 is as follows: 2025 2024 2023 Options Weighted- Average Exercise Price Options Weighted- Average Exercise Price Options Weighted- Average Exercise Price Outstanding at beginning of year 65,500 $ 10.70 70,500 $ 10.33 265,500 $ 4.21 Granted — — — — — — Forfeited — — — — — — Expired ( 14,500 ) 12.51 ( 5,000 ) 5.50 ( 195,000 ) 2.00 Exercised — — — — — — Outstanding at end of year 51,000 $ 10.18 65,500 $ 10.70 70,500 $ 10.33 Exercisable at end of year 51,000 $ 10.18 65,500 $ 10.70 70,500 $ 10.33 As of December 31, 2025, the Company had $ 0 of unrecognized compensation cost related to stock options. The aggregate intrinsic value of options vested and expected to vest as of December 31, 2025 was $ 0 . The aggregate intrinsic value of options exercisable at December 31, 2025 was $ 0 . The year-end intrinsic values are based on a December 31, 2025 closing stock price of $ 0.87 . No stock options were exercised during 2025, 2024 or 2023. The following table summarizes information related to the Company’s stock options outstanding as of December 31, 2025: Options Outstanding Exercise price Number Outstanding Weighted- Average Remaining Contractual Life (in years) Number Exercisable 6.42 15,000 0.10 15,000 11.75 36,000 0.67 36,000 $ 10.18 51,000 0.77 51,000 F-36 Table of Contents Restricted Stock Unit Grants – Following is a table reflecting the restricted stock unit grants during 2025, 2024 and 2023: Grant date Restricted stock units granted February 16, 2023 2,270,842 February 13, 2024 2,647,970 April 5, 2024 60,000 July 31, 2024 76,600 December 9, 2024 83,000 February 12, 2025 3,691,373 April 29, 2025 76,177 Restricted stock unit grants issued prior to 2020 vest at the rate of 20 % each year over five years beginning one year from the date granted. Restricted stock unit grants issued during 2020 and in following years vest at a rate of 33 % each year over three years beginning one year from the date granted for all employees. Restricted stock unit awards granted to members of the Board generally vest on the first anniversary of the grant date. The Company accrues for estimated forfeitures in share-based compensation by an annual factor of 3 %. For forfeited awards, in the period of occurrence, the reduction in expense is booked as an incremental reduction to share-based compensation. For non-forfeited awards, in the final period of expense, the incremental remaining expense is recognized. A summary of the status of restricted stock unit grants and changes during the years ended December 31, 2025, 2024 and 2023 is as follows: 2025 2024 2023 Restricted Stock Units Weighted- Average Grant Date Fair Value Restricted Stock Units Weighted- Average Grant Date Fair Value Restricted Stock Units Weighted- Average Grant Date Fair Value Outstanding at beginning of year 3,817,128 $ 1.70 3,148,226 $ 2.40 2,623,790 $ 2.29 Granted 3,767,550 1.30 2,867,570 1.34 2,270,842 2.22 Forfeited or rescinded ( 269,876 ) 1.37 ( 510,351 ) 1.61 ( 66,174 ) 2.22 Vested ( 2,402,692 ) 1.73 ( 1,688,317 ) 2.43 ( 1,680,232 ) 1.99 Outstanding at end of year 4,912,110 $ 1.40 3,817,128 $ 1.70 3,148,226 $ 2.40 As of December 31, 2025, the Company had $ 2,462,658 of unrecognized compensation cost related to restricted stock unit grants that will be recognized over a weighted average period of 1.77 years. During 2025, 2024, and 2023, 2,402,692 , 1,688,317 , and 1,680,232 restricted stock units vested, respectively. At the dates of vesting those restricted stock units had an aggregate intrinsic value of $ 3,047,762 , $ 2,439,773 , and $ 3,203,568 , respectively. F-37 Table of Contents Performance Stock Units - In accordance with the 2021 Plan, upon Board approval, the Company entered into performance stock unit (“PSU”) agreements (the “PSU Agreement”) with certain employees. The PSUs are performance-based restricted stock units subject to the terms of the 2021 Plan and the PSU Agreement. On November 22, 2021, the Company granted a total of 860,216 PSUs to the Company’s five executive officers (the “2021 PSU Awards”). The performance period for the 2021 PSU Awards began on January 1, 2021, and ended on December 31, 2023. Based on the achievement of the performance goals for the 2021 PSU Awards, a total of 1,170,024 PSUs vested on December 31, 2023. On February 9, 2022, the Company granted a total of 860,216 PSUs to the Company's five executive officers (the "2022 PSU Awards"). The performance period for the 2022 PSU Awards began on January 1, 2022, and ended on December 31, 2024. In July 2024, two of the executive officers separated from the Company, forfeiting 215,054 of these PSUs. Based on the achievement of the performance goals for the 2022 PSU Awards, a total of 571,324 PSUs vested on December 31, 2024. On February 16, 2023, the Company granted a total of 1,162,162 PSUs to the Company's five executive officers (the "2023 PSU Awards"). The performance period for the 2023 PSU Awards began on January 1, 2023, and ended on December 31, 2025. In July 2024, two of the aforementioned executive officers separated from the Company, forfeiting 270,270 of these PSUs. In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 135,135 of these PSUs. Based on the achievement of the performance goals for the 2023 PSU Awards, a total of 680,665 PSUs vested on December 31, 2025. On April 30, 2024, the Company granted a total of 1,378,378 PSUs to the Company's five executive officers (the "2024 PSU Awards"). The performance period for the 2024 PSU Awards began on January 1, 2024, and will end on December 31, 2026. In July 2024, two of the aforementioned executive officers separated from the Company, forfeiting 378,378 of these PSUs. In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 189,189 of these PSUs. On April 29, 2025, the Company granted a total of 1,624,756 PSUs to the Company's six executive officers (the "2025 PSU Awards"). The performance period for the 2025 PSU Awards began on January 1, 2025, and will end on December 31, 2027. In September 2025, one of the aforementioned executive officers separated from the Company, and accelerated the vesting of 225,576 of these PSUs. A summary of the status of the PSU awards and changes during the years ended December 31, 2025, 2024 and 2023 are as follows: 2025 2024 2023 Performance Stock Units Weighted- Average Grant Date Fair Value Performance Stock Units Weighted- Average Grant Date Fair Value Performance Stock Units Weighted- Average Grant Date Fair Value Outstanding at beginning of year 1,891,892 $ 2.47 2,022,378 $ 3.11 1,720,432 $ 3.76 Granted 1,624,756 0.93 1,378,378 2.27 1,162,162 2.71 Incremental performance stock units vested 188,962 — 248,742 — 309,808 — Forfeited, cancelled or rescinded ( 265,054 ) 3.20 ( 1,186,282 ) 2.38 — — Vested ( 1,230,565 ) 2.13 ( 571,324 ) 2.79 ( 1,170,024 ) 3.66 Outstanding at end of year 2,209,991 $ 1.42 1,891,892 $ 2.47 2,022,378 $ 3.11 The Company accrues for estimated forfeitures in share-based compensation by an annual factor of 3 %. For forfeited awards, in the period of occurrence, the reduction in expense is booked as an incremental reduction to share-based compensation. For non-forfeited awards, in the final period of expense, the incremental remaining expense is recognized. F-38 Table of Contents As of December 31, 2025, the Company had $ 1,599,139 of unrecognized compensation cost related to the PSU Awards that will be recognized over a weighted average period of 1.53 years. During 2025, 1,230,565 PSUs vested. At the dates of vesting those PSUs had an aggregate intrinsic value of $ 1,175,073 . 401(k) Plan - In 2019, the Company initiated a sponsored 401(k) plan that is a defined contribution plan for the benefit of all eligible employees. The plan allows eligible employees, after a three-month waiting period, to make pre-tax or after-tax contributions, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6 % of any employee’s compensation. Employees are 100 % vested in the employer contribution upon receipt. The following table presents the matching contributions expense recognized for the Company’s 401(k) plan for the years ended December 31, 2025, 2024, and 2023: 2025 2024 2023 Employer safe harbor match $ 509,967 $ 455,641 $ 346,268 NOTE 13 — COMMITMENTS AND CONTINGENCIES Surety Bonds – As of December 31, 2025 and 2024, the Company had $ 2,275,000 in total surety bonds. A Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 or more wells in the State of Texas in the amount of $ 250,000 and another RRC required blanket plugging extension bond in the amount of $ 2,000,000 . Both RRC bonds have zero collateral requirements A surety bond in the amount of $ 25,000 to operate wells in the State of New Mexico was also in place as of December 31, 2025 and 2024; however, that bond will likely be released as the Company no longer operates wells in New Mexico. Total expenses related to the RRC surety bonds were $ 38,000 and $ 29,585 for the years ended December 31, 2025 and 2024, respectively. The New Mexico bond is supported by a $ 25,000 standby letter of credit collateralized by the Credit Facility with the bank. Standby Letters of Credit – As of December 31, 2025 and 2024, the Company had total standby letters of credit outstanding of $ 35,000 , consisting of a $ 10,000 standby letter of credit in favor of a federal agency and a $ 25,000 standby letter of credit issued to support bonding requirements related to the Company's former operations in the State of New Mexico. The Company no longer conducts operations in New Mexico and expects the standby letter of credit related to the New Mexico bonding requirements to be released, subject to regulatory approval. No amounts had been drawn under either standby letter of credit as of December 31, 2025 and 2024, and no liability has been recorded in the accompanying Balance Sheets related to these arrangements. F-39 Table of Contents NOTE 14 — INCOME TAXES For the years ended December 31, 2025, 2024, and 2023, components of our provision (benefit) for income taxes are as follows. Provision for (Benefit from) Income Taxes: 2025 2024 2023 Federal deferred tax $ ( 7,654,389 ) $ 19,096,010 $ ( 901,522 ) State current tax 374,982 401,197 72,213 State deferred tax ( 173,339 ) 943,747 954,551 Provision for (Benefit from) Income Taxes $ ( 7,452,746 ) $ 20,440,954 $ 125,242 The Company’s overall effective tax rates are calculated as Benefit from (Provision for) Income Taxes divided by Income (Loss) Before Benefit from (Provision for) Income Taxes. The effective tax rates for the years ended December 31, 2025, 2024, and 2023 were as follows. For the years ended December 31, 2025 2024 2023 Effective tax rate (1) 17.7 % 23.3 % 0.1 % (1) The effective tax rates for the years ended December 31, 2025 and 2024 differ from the U.S. federal statutory rate of 21% primarily due to share-based and executive compensation and state income taxes. The effective tax rate for the year ended December 31, 2023 was impacted by the release of valuation allowance on the Company's federal net deferred tax asset. A tax benefit of $ 24.2 million was recorded in the year ended December 31, 2023. The following is a reconciliation of the difference between the effective income tax rate and the U.S. federal statutory rate, for the year ended December 31, 2025. Rate Reconciliation: 2025 Amount Percent Pre-tax book income (loss) $ ( 42,183,945 ) Tax provision (benefit) computed at the U.S. federal statutory rate ( 8,858,628 ) 21.0 % State and local income tax, net of federal income tax effect (1) 174,193 ( 0.4 ) Nontaxable or nondeductible items: Share-based compensation and executive compensation disallowance 1,209,928 ( 2.9 ) Meals and entertainment 20,147 0.0 Other 1,614 0.0 Provision for (Benefit from) Income Taxes $ ( 7,452,746 ) 17.7 % (1) State taxes in Texas made up the majority (greater than 50%) of the tax effect in this category. F-40 Table of Contents As previously disclosed for the years ended December 31, 2024, and 2023, prior to the adoption of ASU 2023-09, the following is a reconciliation of the difference between the effective income tax rate and the U.S. federal statutory rate. Rate Reconciliation: 2024 2023 Pre-tax book income (loss) (2) $ 87,911,268 $ 104,917,670 Tax at federal statutory rate 18,461,366 22,032,711 Excess tax benefit from stock option exercises and restricted stock vesting 104,344 478,304 Adjust prior estimates to tax return 69,654 ( 474,617 ) States taxes, net of federal benefit 1,008,096 1,122,782 Valuation allowance — ( 24,182,975 ) Non-deductible expenses and other 797,494 1,149,037 Provision for (Benefit from) Income Taxes $ 20,440,954 $ 125,242 (2) Amount in the year ended December 31, 2023 represented pre-tax book income, net of income taxes paid. The Company's deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. The net deferred taxes consisted of the following as of December 31, 2025 and 2024. 2025 2024 Deferred Tax Assets Net operating loss (NOL) carryforward $ 72,880,353 $ 68,516,720 Share-based compensation 910,213 1,097,273 Asset retirement obligation 6,627,813 5,755,174 §163(j) business interest expense carryforward 19,675,692 18,838,600 Other 1,488,392 1,672,268 Gross Deferred Tax Assets $ 101,582,463 $ 95,880,035 Less: valuation allowance — — Net Deferred Tax Assets $ 101,582,463 $ 95,880,035 Deferred Tax Liabilities Property and equipment $ ( 115,663,637 ) $ ( 123,318,803 ) Fair value of derivative instruments ( 6,107,910 ) ( 392,761 ) Other ( 575,035 ) ( 760,273 ) Net Deferred Tax Liabilities $ ( 122,346,582 ) $ ( 124,471,837 ) Net Deferred Tax Liability $ ( 20,764,119 ) $ ( 28,591,802 ) The following table summarizes income taxes paid (net of refunds received) for the year ended December 31, 2025. All jurisdictions in which income taxes paid (net of refunds received) were equal to or greater than five percent of total income taxes paid (net of refunds received) are included below (if the noted jurisdiction did not meet the five percent threshold for a particular year, the amount for that year is not included below). Income taxes paid (net of refunds received) 2025 Federal income taxes $ — State and local income taxes: Texas $ 337,787 Other 9,700 Total state and local income taxes, net of refunds $ 347,487 Total income taxes paid, net of refunds received $ 347,487 F-41 Table of Contents As of December 31, 2025, the Company had net operating loss carryforwards for federal income tax reporting purposes of approximately $ 96.9 million which, if unused, will begin to expire in 2033 and fully expire in 2037 and an additional $ 248.2 million that can be carried forward indefinitely. Section 382 of the Internal Revenue Code of 1986, as amended, limits the availability of certain tax attributes, including net operating losses and disallowed interest carryforwards, to offset future taxable income of the Company. In evaluating its need for a valuation allowance against its deferred tax assets, the Company has estimated the amount of tax attributes related to the pre-ownership change period to be available under Section 382 in periods in which it expects deferred tax liabilities to be realized based on currently available information. Based on its current analysis, the Company does not anticipate any material tax attributes to expire unused as result of the Section 382 ownership change; however, the ultimate timing in the amount of tax attributes available in future periods may be different than the Company's current estimate and will be determined in each year as new information becomes available. Changes in expectation in the timing of the availability of the Company's tax attributes could result in adjustments to the valuation allowance in future years as it updates its analysis based on new information. As of December 31, 2025, we carried a valuation allowance against our federal and state deferred tax assets of $ 0 . We have considered both the positive and negative evidence in determining whether it was more likely than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax assets considered realizable could, however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence is no longer present and additional weight is given to subjective positive evidence, including projections for growth. As of June 30, 2023, the Company was no longer in a cumulative loss position. As a result, future forecasted pre-tax book income was considered as positive evidence in assessing the valuation allowance. Based on the change in judgment on the realizability of the related federal deferred tax assets in future years, the Company released $ 24.2 million of valuation allowance as a benefit during the year ended December 31, 2023. This, coupled with the income tax provision for the year ended December 31, 2025 resulted in an ending federal net deferred tax liability of $ 16,977,823 . Additionally, the Company reported a net state deferred tax liability at December 31, 2025 of $ 3,786,296 attributable to certain state deferred tax liabilities mainly associated with property and equipment. F-42 Table of Contents NOTE 15 — SEGMENT REPORTING In accordance with ASU 2023-07 " Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ," the Company has performed an assessment of its reporting to comply with the new requirements for the fiscal year beginning January 1, 2024 and for interim periods beginning January 1, 2025. The Company's operations consist of the exploration, production, and sale of oil, natural gas, and NGLs, primarily within the Permian Basin of Texas, and is regulated by the RRC. The Company operates different areas within the Permian Basin, including the Northwest Shelf and Central Basin Platform. The Company's operations and financials are managed by one cohesive group of individuals, identified as the chief operating decision maker ("CODM"), consisting of the Chairman of the Board and Chief Executive Officer; Executive Vice President and Chief Operations Officer; Executive Vice President and Chief Exploration Officer; Senior Vice President of Operations; and Vice President and Interim Chief Financial Officer. The CODM group reviews the Company's operating results, including condensed financial statements on a monthly basis for evaluating performance and determining resource allocation. The significant expense categories provided to the CODM include lease operating expenses; gathering, transportation and processing costs; ad valorem taxes; and oil and natural gas production taxes. Each of these costs are deducted from oil, natural gas, and natural gas liquids revenues by operating segment to arrive at operating segment profit, used to assess performance. The Company assessed whether its operating segments exhibited similar economic characteristics and whether its operating segments had a similar nature of products, services, production processes, purchaser types/classes, product distribution, and regulatory environment. Each operating segment has similar products (oil, natural gas, and NGLs), similar production processes, similar types of purchasers (midstream companies, or companies with midstream components), similar methods of product delivery, and is governed by the same regulations. After a thorough analysis of each of these factors with regards to the Company's operating segments, it has been determined that it is appropriate to aggregate its operating segments into a single reportable segment, Exploration and Production, which includes all of its revenues, lease operating expenses, gathering, transportation and processing costs, ad valorem taxes, and oil and natural gas production taxes. Refer to the table below. For the years ended December 31, 2025 2024 2023 Exploration and Production Oil, natural gas, and natural gas liquids revenues (1) $ 307,178,072 $ 366,327,414 $ 361,056,001 Lease operating expenses (2) ( 79,353,806 ) ( 78,310,949 ) ( 70,158,227 ) Gathering, transportation and processing costs ( 585,087 ) ( 506,333 ) ( 457,573 ) Ad valorem taxes ( 7,906,586 ) ( 8,069,064 ) ( 6,757,841 ) Oil and natural gas production taxes ( 14,312,232 ) ( 16,116,565 ) ( 18,135,336 ) Exploration and Production segment profit $ 205,020,361 $ 263,324,503 $ 265,547,024 (1) All of the Company's revenues are within the Permian Basin within the United States. (2) The CODM also reviews the following cost categories within lease operating expenses. Refer to the following table. For the years ended December 31, 2025 2024 2023 Lease operating expenses: Workovers $ 12,025,118 $ 15,150,944 $ 14,919,560 Other lease operating expenses $ 67,328,688 $ 63,160,005 $ 55,238,667 Total lease operating expenses $ 79,353,806 $ 78,310,949 $ 70,158,227 F-43 Table of Contents The following tables include a reconciliation of the total reportable segments' measures of profit or loss to the Company's total income (loss) before income taxes. Additionally included is a reconciliation between the reportable segments' assets to the Company's total assets. For the year ended December 31, 2025 Exploration and Production Corporate Total Company Oil, Natural Gas, and Natural Gas Liquids Revenues $ 307,178,072 $ — $ 307,178,072 Lease operating expenses ( 79,353,806 ) — ( 79,353,806 ) Gathering, transportation and processing costs ( 585,087 ) — ( 585,087 ) Ad valorem taxes ( 7,906,586 ) — ( 7,906,586 ) Oil and natural gas production taxes ( 14,312,232 ) — ( 14,312,232 ) Depreciation, depletion and amortization (3) — ( 96,414,150 ) ( 96,414,150 ) Ceiling test impairment (3) — ( 108,825,446 ) ( 108,825,446 ) Asset retirement obligation accretion — ( 1,490,255 ) ( 1,490,255 ) Operating lease expense — ( 700,362 ) ( 700,362 ) General and administrative expense — ( 31,928,576 ) ( 31,928,576 ) Interest income — 290,879 290,879 Interest (expense) — ( 40,430,929 ) ( 40,430,929 ) Gain (loss) on derivative contracts — 31,658,839 31,658,839 Gain (loss) on disposal of assets — 446,400 446,400 Other income — 189,294 189,294 Income (Loss) Before Benefit from (Provision for) Income Taxes $ 205,020,361 $ ( 247,204,306 ) $ ( 42,183,945 ) Total Assets (3) $ 1,365,252,029 $ 46,647,220 $ 1,411,899,249 Capital expenditures $ 98,211,527 $ — $ 98,211,527 (3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included this expense within the Corporate column of the reconciliation table. F-44 Table of Contents For the year ended December 31, 2024 Exploration and Production Corporate Total Company Oil, Natural Gas, and Natural Gas Liquids Revenues $ 366,327,414 $ — $ 366,327,414 Lease operating expenses ( 78,310,949 ) — ( 78,310,949 ) Gathering, transportation and processing costs ( 506,333 ) — ( 506,333 ) Ad valorem taxes ( 8,069,064 ) — ( 8,069,064 ) Oil and natural gas production taxes ( 16,116,565 ) — ( 16,116,565 ) Depreciation, depletion and amortization (3) — ( 98,702,843 ) ( 98,702,843 ) Ceiling test impairment (3) — — — Asset retirement obligation accretion — ( 1,380,298 ) ( 1,380,298 ) Operating lease expense — ( 700,362 ) ( 700,362 ) General and administrative expense — ( 29,640,300 ) ( 29,640,300 ) Interest income — 491,946 491,946 Interest (expense) — ( 43,311,810 ) ( 43,311,810 ) Gain (loss) on derivative contracts — ( 2,365,917 ) ( 2,365,917 ) Gain (loss) on disposal of assets — 89,693 89,693 Other income — 106,656 106,656 Income (Loss) Before Benefit from (Provision for) Income Taxes $ 263,324,503 $ ( 175,413,235 ) $ 87,911,268 Total Assets (3) $ 1,381,583,504 $ 26,515,970 $ 1,408,099,474 Capital expenditures $ 151,946,171 $ — $ 151,946,171 (3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included this expense within the Corporate column of the reconciliation table. F-45 Table of Contents For the year ended December 31, 2023 Exploration and Production Corporate Total Company Oil, Natural Gas, and Natural Gas Liquids Revenues $ 361,056,001 $ — $ 361,056,001 Lease operating expenses ( 70,158,227 ) — ( 70,158,227 ) Gathering, transportation and processing costs ( 457,573 ) — ( 457,573 ) Ad valorem taxes ( 6,757,841 ) — ( 6,757,841 ) Oil and natural gas production taxes ( 18,135,336 ) — ( 18,135,336 ) Depreciation, depletion and amortization (3) — ( 88,610,291 ) ( 88,610,291 ) Ceiling test impairment (3) — — — Asset retirement obligation accretion — ( 1,425,686 ) ( 1,425,686 ) Operating lease expense — ( 541,801 ) ( 541,801 ) General and administrative expense — ( 29,188,755 ) ( 29,188,755 ) Interest income — 257,155 257,155 Interest (expense) — ( 43,926,732 ) ( 43,926,732 ) Gain (loss) on derivative contracts — 2,767,162 2,767,162 Gain (loss) on disposal of assets — ( 87,128 ) ( 87,128 ) Other income — 198,935 198,935 Income (Loss) Before Benefit from (Provision for) Income Taxes $ 265,547,024 $ ( 160,557,141 ) $ 104,989,883 Total Assets (3) $ 1,338,584,701 $ 37,911,691 $ 1,376,496,392 Capital expenditures $ 151,969,735 $ — $ 151,969,735 (3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization or ceiling test impairment as a significant Exploration and Production segment expense, the Company has included this expense within the Corporate column of the reconciliation table. The following table discloses the purchasers from which 10% or more of revenues were derived in the years noted. For the years ended December 31, 2025 2024 2023 Purchasers with 10% or more percentage of total revenue (4) Phillips 66 Company ("Phillips") 67 % 61 % 66 % Concord Energy LLC 13 % 14 % * LPC Crude III, LLC * 13 % * NGL Crude Partners ("NGL Crude") * 10 % 10 % Enterprise Crude Oil LLC ("Enterprise") * * 12 % (4) All the Company's purchasers are within the Exploration and Production operating segment. * Represents less than 10% F-46 Table of Contents NOTE 16 — LEGAL MATTERS The Company is a defendant in a lawsuit in Harris County District Court, Houston, Texas, styled EPUS Permian Assets, LLC, v. Ring Energy, Inc., that was filed in July 2021. The plaintiff, EPUS Permian Assets, LLC, claims breach of contract, money had and received by fraudulent inducement, unjust enrichment and constructive trust. The plaintiff is requesting its forfeited deposit of $ 5,500,000 in connection with a proposed property sale by the Company plus related damages, and attorneys’ fees and costs. The action relates to a proposed property sale by the Company to the plaintiff, which was extended by the Company on several occasions with the plaintiff ultimately failing to perform on the agreement and the Company keeping the deposit. The Company believes that the claims by the plaintiff are entirely without merit and is conducting a vigorous defense and counterclaim. The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have concluded discovery in the matter and are currently set for trial in the second quarter of 2026. NOTE 17 — SUBSEQUENT EVENTS In accordance with ASC Topic 855, Subsequent Events, the Company has evaluated all events subsequent to the balance sheet date of December 31, 2025, through the date these condensed financial statements were issued, March 4, 2026. The Company did not have any material subsequent events to report. F-47 Table of Contents RING ENERGY, INC. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (Unaudited) Results of Operations from Oil and Natural Gas Producing Activities – The Company’s results of operations from oil and natural gas producing activities exclude interest expense, gain from change in fair value of derivatives, and other financing expense. For the years ended December 31, 2025 2024 2023 Oil, natural gas, and natural gas liquids sales $ 307,178,072 $ 366,327,414 $ 361,056,001 Lease operating expenses (79,353,806) (78,310,949) (70,158,227) Gathering, transportation and processing costs (585,087) (506,333) (457,573) Ad valorem taxes (7,906,586) (8,069,064) (6,757,841) Production taxes (14,312,232) (16,116,565) (18,135,336) Depreciation, depletion, and amortization (96,414,150) (98,702,843) (88,610,291) Ceiling test impairment (108,825,446) — — General and administrative (exclusive of corporate overhead) (4,162,391) (3,360,370) (2,839,401) Income tax benefit (expense) 774,233 (37,493,250) (208,917) Results of Oil and Natural Gas Producing Operations $ (3,607,393) $ 123,768,040 $ 173,888,415 Costs Incurred in Oil and Gas Producing Activities For the years ended December 31, 2025 2024 2023 Payments to acquire oil and natural gas properties $ 84,392,361 $ 2,210,826 $ 82,900,900 Payments to explore oil and natural gas properties — — — Payments to develop oil and natural gas properties 95,207,027 153,945,456 152,559,314 Total costs incurred $ 179,599,388 $ 156,156,282 $ 235,460,214 Capitalized Costs As of December 31, 2025 2024 2023 Oil and natural gas properties, full cost method Proved properties $ 1,891,510,431 $ 1,809,309,848 $ 1,663,548,249 Unproved properties — — — Total oil and natural gas properties, full cost method $ 1,891,510,431 $ 1,809,309,848 $ 1,663,548,249 Accumulated depletion of oil and natural gas properties (564,169,311) (469,786,336) (373,280,583) Net oil and natural gas properties capitalized $ 1,327,341,120 $ 1,339,523,512 $ 1,290,267,666 F-48 Table of Contents Reserve Quantities Information – The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted future net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States of America. The proved reserves estimates shown herein for the years ended December 31, 2025, 2024 and 2023 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. The reserve information in these financial statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced. The oil prices as of December 31, 2025, 2024 and 2023 are based on the respective 12-month unweighted average of the first of the month prices of the WTI posted prices which equates to $61.82 per barrel, $71.96 per barrel and $74.70 per barrel, respectively. The natural gas prices as of December 31, 2025, 2024 and 2023 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $3.387 per MMBtu, $2.130 per MMBtu and $2.637 per MMBtu, respectively. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines. Proved reserves are estimated reserves of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and methods. F-49 Table of Contents For the year ended December 31, 2025 Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1) Proved Developed and Undeveloped Reserves Beginning of year 80,904,071 149,817,162 28,303,085 134,176,684 Purchase of minerals in place 9,915,483 10,067,543 2,373,336 13,966,743 Extensions, discoveries and improved recovery 7,281,553 10,624,783 2,133,786 11,186,136 Sales of minerals in place — — — — Production (4,841,164) (6,980,958) (1,387,818) (7,392,476) Revisions of previous quantity estimates (2) (2,939,895) 12,652,046 2,171,955 1,340,734 End of year 90,320,048 176,180,576 33,594,344 153,277,821 Proved Developed at beginning of year 56,106,714 102,538,111 19,426,387 92,622,787 Proved Undeveloped at beginning of year 24,797,357 47,279,051 8,876,698 41,553,897 Proved Developed at end of year 60,108,129 121,424,006 23,453,484 103,798,946 Proved Undeveloped at end of year 30,211,919 54,756,570 10,140,860 49,478,875 (1) Six Mcf is deemed the equivalent of one Boe. (2) Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Notable changes in proved reserves for the year ended December 31, 2025 included the following: • Extensions. In 2025, extensions of 11.2 MMBoe were primarily the result of 41 newly added PUDs in addition to an active leasing program. Also impacting extensions were three successfully drilled wells in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place. In 2025, the Company completed the acquisition of Lime Rock oil and gas leases and related property within Andrews County, as well as a few other minor acquisitions, that resulted in 14.0 MMBoe of additional reserves. • Sales of minerals in place. In 2025, the Company did not sell any reserves. • Revision of previous quantity estimates. In 2025, the positive revisions of prior reserves of 1.3 MMBoe consisted of a positive 7.2 MMBoe related to changes in performance and other economic factors, offset by a negative 5.9 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials). F-50 Table of Contents For the year ended December 31, 2024 Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1) Proved Developed and Undeveloped Reserves Beginning of year 82,141,277 146,396,322 23,218,564 129,759,229 Purchase of minerals in place — — — — Extensions, discoveries and improved recovery 11,495,236 10,630,769 2,738,451 16,005,482 Sales of minerals in place (1,140,568) (56,020) (16,361) (1,166,266) Production (4,861,628) (6,423,674) (1,258,814) (7,191,054) Revisions of previous quantity estimates (2) (6,730,246) (730,235) 3,621,245 (3,230,707) End of year 80,904,071 149,817,162 28,303,085 134,176,684 Proved Developed at beginning of year 56,029,039 99,896,022 15,449,907 88,128,284 Proved Undeveloped at beginning of year 26,112,238 46,500,300 7,768,657 41,630,945 Proved Developed at end of year 56,106,714 102,538,111 19,426,387 92,622,787 Proved Undeveloped at end of year 24,797,357 47,279,051 8,876,698 41,553,897 (1) Six Mcf is deemed the equivalent of one Boe. (2) Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Notable changes in proved reserves for the year ended December 31, 2024 included the following: • Extensions. In 2024, extensions of 16.0 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place. In 2024, the Company did not purchase any additional reserves. • Sales of minerals in place. In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties. • Revision of previous quantity estimates. In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors. F-51 Table of Contents For the year ended December 31, 2023 Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1) Proved Developed and Undeveloped Reserves Beginning of year 88,704,743 157,870,449 23,105,658 138,122,143 Purchase of minerals in place 6,543,640 3,372,965 1,089,382 8,195,183 Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768 Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700) Production (4,579,942) (6,339,158) (976,852) (6,613,320) Revisions of previous quantity estimates (2) (6,728,088) (9,946,459) (621,014) (9,006,845) End of year 82,141,277 146,396,322 23,218,564 129,759,229 Proved Developed at beginning of year 57,012,137 106,399,050 15,332,804 90,078,116 Proved Undeveloped at beginning of year 31,692,606 51,471,399 7,772,854 48,044,027 Proved Developed at end of year 56,029,039 99,896,022 15,449,907 88,128,284 Proved Undeveloped at end of year 26,112,238 46,500,300 7,768,657 41,630,945 (1) Six Mcf is deemed the equivalent of one Boe. (2) Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Notable changes in proved reserves for the year ended December 31, 2023 included the following: • Extensions. In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place. In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves. • Sales of minerals in place. In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%). • Revision of previous quantity estimates. In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors. F-52 Table of Contents Standardized Measure of Discounted Future Net Cash Flows – The standardized measure of discounted future net cash flows is computed by applying the price according to the SEC guidelines for oil and natural gas to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2025 2024 2023 Future cash inflows $ 5,976,599,552 $ 6,165,487,616 $ 6,622,410,752 Future production costs (2,473,482,048) (2,432,555,200) (2,413,303,488) Future development costs (1) (573,423,296) (536,825,664) (562,063,424) Future income taxes (402,808,797) (465,768,645) (548,664,988) Future net cash flows 2,526,885,411 2,730,338,107 3,098,378,852 10% annual discount for estimated timing of cash flows (1,403,392,079) (1,497,401,764) (1,699,193,661) Standardized Measure of Discounted Future Net Cash Flows $ 1,123,493,332 $ 1,232,936,343 $ 1,399,185,191 (1) Future development costs include not only development costs but also future asset retirement costs. The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2025: Changes in Standardized Measure of Discounted Future Net Cash Flows 2025 2024 2023 Beginning of the year $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518 Purchase of minerals in place 174,287,315 — 141,738,066 Extensions, discoveries and improved recovery 98,831,276 226,741,618 57,607,609 Development costs incurred during the year 28,098,777 71,665,321 70,697,664 Sales of oil and gas produced, net of production costs (205,605,448) (263,830,836) (266,004,598) Sales of minerals in place — (10,230,951) (59,600,128) Accretion of discount 146,282,714 164,703,142 277,365,650 Net changes in price and production costs (372,012,158) (285,618,955) (1,181,594,019) Net change in estimated future development costs 28,456,200 6,732,428 37,865,811 Revisions of previous quantity estimates 17,046,040 (50,292,499) (187,443,783) Changes in estimated timing of cash flows (60,003,723) (44,073,556) (17,257,348) Net change in income taxes 35,175,996 17,955,440 253,696,749 End of the Year $ 1,123,493,332 $ 1,232,936,343 $ 1,399,185,191 F-53