MURPHY OIL CORP 10-K

Item 9A. CONTROLS AND PROCEDURES Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors. Based on their evaluation, with the participation of the Company’s management, as of December 31, 2025, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2025. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025 and their report is included on page 67 of this Form 10-K report. There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 55 Table of Contents PART II Item 9B. OTHER INFORMATION During the three months ended December 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K. Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS Not applicable. 56 Table of Contents PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Certain information regarding executive officers of the Company is included on page 29 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the captions “Election of Directors” and “The Board and Committees.” Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance tab at ir.murphyoilcorp.com. Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Corporate Secretary at 9805 Katy Freeway, Suite G-200, Houston, TX 77024. Any future amendments to or waivers of the Code of Ethical Conduct for Executive Management will be posted on the Company’s Website. Murphy Oil has also adopted an insider trading policy governing the purchase, sale, and/or other dispositions of our securities by our directors, officers, employees and contractors and consultants who have access to material nonpublic information, as well as the Company itself, that we believe is reasonably designed to promote compliance with insider trading laws, rules and regulations, and the exchange listing standards applicable to us. A copy of our insider trading policy, including any amendments thereto, is filed as Exhibit 19.1 to this Form 10-K. Item 11. EXECUTIVE COMPENSATION Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the captions “Compensation Discussion and Analysis” and “How We Are Compensated” and in various compensation schedules. As required by U.S. federal securities laws, the Company implemented its incentive-based compensation recoupment (clawback) policy providing for the recovery of erroneously awarded incentive-based compensation received by current or former executive officers. We have filed our written recoupment policy as Exhibit 97.1 to this Form 10-K report and as of December 31, 2025, there have been no accounting restatements requiring compensation recoupment. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the caption “Our Stockholders” and in the “Equity Compensation Plan Information”. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the caption “Election of Directors”. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Our independent registered public accounting firm is KPMG LLP, Houston, TX, Auditor Firm ID: 185. Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the caption “Audit Committee Report”. 57 Table of Contents PART IV Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) 1. Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below. Page No. Report of Management – Consolidated Financial Statements 64 Report of Management – Internal Control Over Financial Reporting 64 Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (KPMG LLP , Houston, TX, Auditor Firm ID: 185 ) 65 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting (KPMG LLP, Houston, TX, Auditor Firm ID: 185) 67 Consolidated Balance Sheets 68 Consolidated Statements of Operations 69 Consolidated Statements of Comprehensive Income (Loss) 70 Consolidated Statements of Cash Flows 71 Consolidated Statements of Stockholders’ Equity 72 Notes to Consolidated Financial Statements 73 Note A – Significant Accounting Policies 73 Note B – New Accounting Principles and Recent Accounting Pronouncements 76 Note C – Revenue from Contracts with Customers 77 Note D – Property, Plant and Equipment 79 Note E – Inventories 81 Note F – Financing Arrangements and Debt 82 Note G – Asset Retirement Obligations 83 Note H – Income Taxes 84 Note I – Incentive Plans 87 Note J – Employee and Retiree Benefit Plans 90 Note K – Financial Instruments and Risk Management 96 Note L – Net Income (Loss) Per Common Share 98 Note M – Other Financial Information 98 Note N – Accumulated Other Comprehensive Loss 99 Note O – Assets and Liabilities Measured at Fair Value 99 Note P – Commitments 101 Note Q – Environmental and Other Contingencies 101 Note R – Common Stock Issued and Outstanding 103 Note S – Business Segments 103 Note T – Leases 108 Note U – Subsequent Event 110 Supplemental Oil and Gas Information (unaudited) 111 Supplemental Quarterly Information (unaudited) 127 58 Table of Contents PART IV 2. Financial Statement Schedules – All financial statement schedules are omitted because either they are not applicable, or the required information is included in the consolidated financial statements or notes thereto. 3. Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed as indicated by double asterisks (**), or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable. Exhibit No. Incorporated by Reference to the Indicated Filing by Murphy Oil Corporation 2.1 Purchase and sale agreement dated as of April 19, 2019 between LLOG Bluewater Holdings, LLC and LLOG Exploration Offshore, LLC, as seller, and Murphy Exploration & Production Company – USA, as purchaser. Exhibit 2.1 to Form 8-K filed June 5, 2019 2.2 First Amendment to Purchase and Sale Agreement dated as of May 31, 2019 among Murphy Exploration & Production Company - USA, LLOG Exploration Offshore, L.L.C. and LLOG Bluewater Holdings, L.L.C. Exhibit 2.2 to Form 8-K filed June 5, 2019 2.3 Contribution Agreement dated as of October 10, 2018 among Murphy Exploration & Production Company – USA, Petrobras America Inc. and MP Gulf of Mexico, LLC Exhibit 2.1 to Form 10-K filed February 27, 2019 3.1 Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005 Exhibit 3.1 to Form 10-K filed February 28, 2011 3.2 By-Laws of Murphy Oil Corporation, as amended effective August 5, 2020 Exhibit 3.2 to Form 10-Q filed August 6, 2020 4.1 Supplemental Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee, relating to 7.05% Notes due 2029 Exhibit 4.2 to Form 10-K filed March 16, 2005 4.2 Indenture dated as of May 18, 2012 between Murphy Oil Corporation and U.S. Bank National Association, as trustee Exhibit 4.1 to Form 8-K filed May 18, 2012 4.3 Second Supplemental Indenture dated as of November 30, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 5.125% Notes due 2042 Exhibit 4.1 to Form 8-K filed November 30, 2012 4.4 Fifth Supplemental Indenture dated as of November 27, 2019, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, and Wells Fargo Bank, National Association, as series trustee, relating to 5.875% Notes due 2027 Exhibit 4.2 to Form 8-K filed November 27, 2019 4.5 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 Exhibit 4.9 to Form 10-K filed February 27, 2020 4.6 Sixth Supplemental Indenture dated as of March 5, 2021, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, and Wells Fargo Bank, National Association as series trustee, relating to 6.375% Notes due 2028 Exhibit 4.2 to Form 8-K filed March 5, 2021 4.7 Seventh Supplemental Indenture dat ed as of October 3, 2024,between Murphy Oil Corporation and Regions Bank, as trustee, relating to 6.000% Notes due 2032 Exhibit 4.2 to Form 8-K filed October 3, 2024 4.8 Eighth Supplemental Indenture, dated as of January 23, 2026, between Murphy Oil Corporation and Regions Bank, as trustee (including the Form of 6.500% Notes due 2034) Exhibit 4.2 to Form 8-K filed January 23, 2026 10.1 Murphy Oil Corporation Annual Incentive Plan Exhibit 10.3 to Form 10-K filed February 25, 2022 10.2 Murphy Oil Corporation 2020 Long-Term Incentive Plan Exhibit A to definitive proxy statement filed March 30, 2020 59 Table of Contents PART IV 10.3 Form of employee performance-based restricted stock unit – stock settled grant agreement (2020 LTI Plan) Exhibit 10.21 to Form 10-K filed February 26, 2021 10.4 Form of employee time-based restricted stock unit – stock settled 3-year grant agreement (2020 LTI Plan) Exhibit 10.22 to Form 10-K filed February 26, 2021 10.5 Form of employee time-based restricted stock unit – stock settled 5-year grant agreement (2020 LTI Plan) Exhibit 10.23 to Form 10-K filed February 26, 2021 10.6 Form of employee time-based restricted stock unit – cash settled 3-year grant agreement (2020 LTI Plan) Exhibit 10.24 to Form 10-K filed February 26, 2021 10.7 Form of employee time-based restricted stock unit – cash settled 5-year grant agreement (2020 LTI Plan) Exhibit 10.25 to Form 10-K filed February 26, 2021 10.8 Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 23, 2018 10.9 First Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.1 to Form 8-K filed April 25, 2018 10.10 Second Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.24 to Form 10-K filed February 27, 2020 10.11 Form of non-employee director restricted stock unit award – stock settled grant agreement (2018 NED Plan) Exhibit 10.20 to Form 10-K filed February 27, 2019 10.12 Form of non-employee director restricted stock unit award – stock settled grant agreement (2018 NED Plan) Exhibit 10.26 to Form 10-K filed February 27, 2020 10.13 Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 26, 2021 10.14 Form of non-employee director restricted stock unit award – stock settled grant agreement (2021 NED Plan) Exhibit 10.27 to Form 10-Q filed August 5, 2021 10.15 Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors Exhibit 10.6 to Form 10-K filed February 26, 2016 10.16 Trademark License Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc. Exhibit 10.4 to Form 8-K filed September 5, 2013 10.17 Form of employee performance-based restricted stock unit (2020 LTI Plan) Exhibit 10.23 to Form 10-Q filed May 7, 2025 10.18 Form of employee time-based restricted stock unit – A (2020 LTI Plan) Exhibit 10.24 to Form 10-Q filed May 7, 2025 10.19 Form of employee time-based restricted stock unit – B (2020 LTI Plan) Exhibit 10.25 to Form 10-Q filed May 7, 2025 10.20 Form of employee time-based restricted stock unit – C (2020 LTI Plan) Exhibit 10.33 to Form 10-K filed February 23, 2024 10.21 Form of employee time-based restricted stock unit – D (2020 LTI Plan) Exhibit 10.34 to Form 10-K filed February 23, 2024 10.22 Form of non-employee director elective restricted stock unit (2021 NED Plan) Exhibit 10.35 to Form 10-Q filed May 2, 2024 10.23 Severance Protection Agreement dated as of August 7, 2013 between Murphy Oil Corporation and Roger W. Jenkins Exhibit 10.1 to Form 8-K filed August 9, 2013 10.24 Amendment to Severance Protection Agreement dated as of August 7, 2013, between Murphy Oil Corporation and Roger W. Jenkins Exhibit 10.1 to Form 10-Q filed May 2, 2019 10.25 Credit Agreement, dated as of October 7, 2024, among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank N.A., as administrative agent, and the lenders party thereto Exhibit 10.1 to Form 8-K filed October 7, 2024 10.26 Form of Severance Protection Agreement Exhibit 10.32 to Form 10-K filed February 27, 2025 60 Table of Contents PART IV 10.27 First Amendment to the New Credit Agreement dated as of February 6, 2025 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party hereto Exhibit 10.33 to Form 10-K filed February 27, 2025 10.28 Murphy Oil Corporation 2025 Long-Term Incentive Plan Exhibit A to definitive proxy statement filed on March 28, 2025 10.29 Form of employee performance-based restricted stock unit (2025 LTI Plan) Exhibit 10.35 to Form 10-Q filed November 5, 2025 10.30 Form of employee time-based restricted stock unit – A (2025 LTI Plan) Exhibit 10.36 to Form 10-Q filed November 5, 2025 10.31 Second Amendment to the Credit Agreement dated as of January 2, 2026 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd. as borrowers, Murphy Exploration & Production Company and Murphy Exploration & Production Company – USA, as guarantors, JP Morgan Chase Bank, N.A. as administrative agent, and each of the lenders party thereto Exhibit 10.1 to Form 8-K filed January 6, 2026 *10.32 Form of e mplo yee performance-based re s tr icted stock u nit — B (2025 LTI Plan) *10.33 Form of employee time-based restricted stock unit — B (2025 LTI Plan) *10.34 Form of employee tim e-based restricted stock unit — C (2025 LTI Plan) *10.35 Form of employee tim e-based restricted stock unit — D (2025 LTI Plan) 19.1 Murphy Oil Corporation Insider Trading Policy Exhibit 19.1 to Form 10-K filed February 27, 2025 *21.1 Subsidiaries of Murphy Oil Corporation *23.1 Consent of Independent Registered Public Accounting Firm *23.2 Consent of Ryder Scott Company, L.P. *23.3 Consent of McDaniel & Associates Consultants Ltd. *23.4 Consent of Netherland, Sewell & Associates, Inc. *23.5 C onsent of GLJ Petro leum Consultants Ltd. *31.1 Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 *31.2 Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 **32.1 Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 97.1 Murphy Oil Corporation Compensation Recoupment Policy Exhibit 10.29 to Form 10-K filed February 23, 2024 *99.1 Ryder Scott independent reserves audit report for MP GOM JV *99.2 R yder Scott independ ent reserves au dit report for U .S. Onshore *99.3 McDaniel independent reserves audit report for Canada Onshore *99.4 Netherland, Sewell & Associates, Inc. independent reserves audit report U.S. Gulf of America *99.5 GLJ independent reserves au dit for Canada Offshore 101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document 101.SCH Inline XBRL Taxonomy Extension Schema Document 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) 61 Table of Contents PART IV Item 16. FORM 10-K SUMMARY None. 62 Table of Contents PART IV 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. MURPHY OIL CORPORATION By /s/ ERIC M. HAMBLY Date: February 25, 2026 Eric M. Hambly, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 25, 2026 by the following persons on behalf of the registrant and in the capacities indicated. /s/ CLAIBORNE P. DEMING /s/ JEFFREY W. NOLAN Claiborne P. Deming, Chairman and Director Jeffrey W. Nolan, Director /s/ ERIC M. HAMBLY /s/ ROBERT N. RYAN, JR. Eric M. Hambly, President and Chief Executive Officer and Director (Principal Executive Officer) Robert N. Ryan, Jr., Director /s/ LAWRENCE R. DICKERSON /s/ LAURA A. SUGG Lawrence R. Dickerson, Director Laura A. Sugg, Director /s/ MICHELLE A. EARLEY /s/ ROBERT B. TUDOR, III Michelle A. Earley, Director Robert B. Tudor, III, Director /s/ ELISABETH W. KELLER /s/ THOMAS J. MIRELES Elisabeth W. Keller, Director Thomas J. Mireles, Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ R. MADISON MURPHY /s/ PAUL D. VAUGHAN R. Madison Murphy, Director Paul D. Vaughan Vice President and Controller (Principal Accounting Officer) 63 Table of Contents REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The financial statements were prepared in conformity with U.S. generally accepted accounting principles (GAAP) appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality. An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and provides an objective, independent opinion about the Company’s consolidated financial statements. The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders. KPMG LLP’s opinion covering the Company’s consolidated financial statements can be found on page 65 . The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters. REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. GAAP. All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements. Management has conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the results of this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2025. KPMG LLP has performed an audit of the Company’s internal control over financial reporting, and their opinion thereon can be found on page 67 . 64 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors Murphy Oil Corporation: Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated 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 years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles. 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 Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated 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 consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Estimated oil and gas reserves used in the depletion of producing oil and gas properties As discussed in Note A to the consolidated financial statements, the Company calculates depletion expense related to producing oil and gas properties using the units-of-production method. Under this method, costs to acquire interests in oil and gas properties and costs for the drilling and completion efforts for exploratory wells that find proved reserves and for development wells are capitalized. Capitalized costs of producing oil and gas properties, along with equipment and facilities that support production, are amortized to expense by the units-of-production method. The Company’s internal petroleum reserve engineers estimate proved oil and gas reserves and the Company engages third-party petroleum reserve specialists to perform an 65 Table of Contents independent assessment. For the year ended December 31, 2025, the Company recorded depreciation, depletion, and amortization expense of $977.8 million. We identified the assessment of the estimated oil and gas reserves used in the depletion of producing oil and gas properties as a critical audit matter. Complex auditor judgment was required in evaluating the Company’s estimate of total proved oil and gas reserves, which is an input to the depletion expense calculation. Estimating proved oil and gas reserves requires the expertise of professional petroleum reserve engineers based on their estimates of forecasted production, forecasted operating costs, future development costs, and oil and gas prices. The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion calculation process, including controls related to the estimation of proved oil and gas reserves. We evaluated (1) the professional qualifications of the internal petroleum reserve engineers, third-party petroleum reserve specialists, and external engineering firm, (2) the knowledge, skills, ability of the Company’s internal petroleum reserve engineers and third-party petroleum reserve specialists, and (3) the relationship of the third-party petroleum reserve specialists and external engineering firm to the Company. We analyzed and assessed the calculation of depletion expense for compliance with industry and regulatory standards. We compared the forecasted production assumptions used by the Company to historical production rates. We compared the forecasted operating costs to historical results. We also evaluated the forecasted nature and timing of future development costs by obtaining an understanding of the development projects. We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices. In addition, we read and considered the report of the Company’s third-party petroleum reserve specialists in connection with our evaluation of the Company’s proved oil and gas reserve estimates. /s/ KPMG LLP We have served as the Company’s auditor since 1952. Houston, Texas February 25, 2026 66 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and the Board of Directors Murphy Oil Corporation: Opinion on Internal Control Over Financial Reporting We have audited Murphy Oil Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2026 expressed an unqualified opinion on those consolidated 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 Report of Management - 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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/ KPMG LLP Houston, Texas February 25, 2026 67 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31 (Thousands of dollars except share amounts) 2025 2024 ASSETS Current assets Cash and cash equivalents $ 377,196 $ 423,569 Accounts receivable, net 346,759 272,530 Inventories Note E 57,284 54,858 Prepaid expenses 35,473 34,322 Total current assets 816,712 785,279 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ 15,068,149 in 2025 and $ 13,811,539 in 2024 Note D 8,136,346 8,054,653 Operating lease assets Note T 805,464 777,536 Deferred charges and other assets 74,104 50,011 Total assets $ 9,832,626 $ 9,667,479 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease Note F $ 2,514 $ 871 Accounts payable 572,183 472,165 Income taxes payable 18,209 19,003 Other taxes payable 28,295 31,685 Operating lease liabilities Note T 278,834 253,208 Other accrued liabilities 120,755 117,802 Current asset retirement obligations Note G 41,959 48,080 Total current liabilities 1,062,749 942,814 Long-term debt, including finance lease obligation Note F 1,382,566 1,274,502 Asset retirement obligations Note G 970,908 960,804 Deferred credits and other liabilities 263,596 274,345 Non-current operating lease liabilities Note T 537,773 537,381 Deferred income taxes Note H 378,337 335,790 Total liabilities $ 4,595,929 $ 4,325,636 Equity Cumulative Preferred Stock, par $ 100 , authorized 400,000 shares, none issued $ — $ — Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at December 31, 2025 and 195,100,628 shares at December 31, 2024 195,101 195,101 Capital in excess of par value 859,633 848,950 Retained earnings 6,691,318 6,773,289 Accumulated other comprehensive loss Note N ( 554,227 ) ( 628,072 ) Treasury stock ( 2,073,445 ) ( 1,995,018 ) Murphy Shareholders' Equity 5,118,380 5,194,250 Noncontrolling interest 118,317 147,593 Total equity 5,236,697 5,341,843 Total liabilities and equity $ 9,832,626 $ 9,667,479 The accompanying notes are an integral part of these consolidated financial statements. 68 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31 (Thousands of dollars except per share amounts) 2025 2024 2023 Revenues and other income Revenue from production $ 2,689,845 $ 3,014,856 $ 3,376,639 Sales of purchased natural gas — 3,742 72,215 Total revenue from sales to customers 2,689,845 3,018,598 3,448,854 Gain (loss) on derivative instruments 5,927 ( 1,707 ) — Gain on sale of assets and other operating income 23,051 11,583 11,293 Total revenues and other income 2,718,823 3,028,474 3,460,147 Costs and expenses Lease operating expenses 765,240 936,960 784,391 Severance and ad valorem taxes 39,238 39,162 42,787 Transportation, gathering and processing 199,693 210,827 232,985 Costs of purchased natural gas — 3,147 51,682 Exploration expenses, including undeveloped lease amortization 111,670 133,538 234,776 Selling and general expenses 137,332 110,085 117,306 Depreciation, depletion and amortization 977,753 865,753 861,602 Accretion of asset retirement obligations 57,730 52,511 46,059 Impairment of assets 115,002 62,909 — Other operating expense 13,928 10,989 46,530 Total costs and expenses 2,417,586 2,425,881 2,418,118 Operating income from continuing operations 301,237 602,593 1,042,029 Other income (loss) Other income (loss) ( 22,299 ) 70,902 ( 8,587 ) Interest expense, net ( 96,072 ) ( 105,926 ) ( 112,373 ) Total other loss ( 118,371 ) ( 35,024 ) ( 120,960 ) Income from continuing operations before income taxes 182,866 567,569 921,069 Income tax expense 44,552 78,272 195,921 Income from continuing operations 138,314 489,297 725,148 Income (loss) from discontinued operations, net of income taxes 485 ( 2,812 ) ( 1,467 ) Net income including noncontrolling interest 138,799 486,485 723,681 Less: Net income attributable to noncontrolling interest 34,565 79,314 62,122 NET INCOME ATTRIBUTABLE TO MURPHY $ 104,234 $ 407,171 $ 661,559 NET INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ 0.73 $ 2.73 $ 4.27 Discontinued operations — ( 0.02 ) ( 0.01 ) Net income $ 0.73 $ 2.71 $ 4.26 NET INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 0.72 $ 2.72 $ 4.23 Discontinued operations — ( 0.02 ) ( 0.01 ) Net income $ 0.72 $ 2.70 $ 4.22 Cash dividends per common share $ 1.300 $ 1.200 $ 1.100 Average common shares outstanding (thousands) Basic 143,124 150,011 155,234 Diluted 144,025 151,027 156,646 The accompanying notes are an integral part of these consolidated financial statements. 69 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Years Ended December 31 (Thousands of dollars) 2025 2024 2023 Net income including noncontrolling interest $ 138,799 $ 486,485 $ 723,681 Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation 73,993 ( 134,692 ) 36,598 Retirement and postretirement benefit plans ( 148 ) 27,737 ( 23,029 ) Other comprehensive income (loss) 73,845 ( 106,955 ) 13,569 Comprehensive income including noncontrolling interest 212,644 379,530 737,250 Less: Comprehensive income attributable to noncontrolling interest 34,565 79,314 62,122 COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ 178,079 $ 300,216 $ 675,128 The accompanying notes are an integral part of these consolidated financial statements. 70 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31 (Thousands of dollars) 2025 2024 2023 Operating Activities Net income including noncontrolling interest $ 138,799 $ 486,485 $ 723,681 Adjustments to reconcile net income to net cash provided by continuing operations activities Depreciation, depletion and amortization 977,753 865,753 861,602 Unsuccessful exploration well costs and previously suspended exploration costs 30,095 73,201 169,795 Deferred income tax expense 34,673 72,434 179,823 Impairment of assets 115,002 62,909 — Accretion of asset retirement obligations 57,730 52,511 46,059 Long-term non-cash compensation 45,128 45,057 61,953 Amortization of undeveloped leases 11,634 9,587 10,925 (Income) loss from discontinued operations ( 485 ) 2,812 1,467 Unrealized (gain) loss on derivative instruments ( 1,706 ) 1,707 — Contingent consideration payment — — ( 139,574 ) Unrealized loss on contingent consideration — — 7,113 Other operating activities, net ( 86,763 ) ( 18,349 ) ( 74,728 ) Net decrease (increase) in non-cash working capital ( 74,052 ) 74,883 ( 99,361 ) Net cash provided by continuing operations activities 1,247,808 1,728,990 1,748,755 Investing Activities Property additions and dry hole costs 1 ( 1,020,611 ) ( 900,108 ) ( 1,066,015 ) Acquisition of oil and natural gas properties 1 ( 29,034 ) ( 8,056 ) ( 35,578 ) Proceeds from sales of property, plant and equipment 20,719 — 102,913 Net cash required by investing activities ( 1,028,926 ) ( 908,164 ) ( 998,680 ) Financing Activities Retirement of debt — ( 650,112 ) ( 498,175 ) Early redemption of debt cost — ( 15,700 ) — Debt issuance — 600,000 — Debt issuance cost — ( 10,145 ) — Borrowings on revolving credit facility 550,000 350,000 600,000 Repayment of revolving credit facility ( 450,000 ) ( 350,000 ) ( 600,000 ) Issue costs of revolving credit facility ( 418 ) ( 14,718 ) ( 20 ) Repurchase of common stock ( 102,620 ) ( 301,350 ) ( 150,022 ) Cash dividends paid ( 186,205 ) ( 179,961 ) ( 170,978 ) Distributions to noncontrolling interest ( 63,841 ) ( 118,580 ) ( 29,382 ) Withholding tax on stock-based incentive awards ( 9,743 ) ( 25,310 ) ( 14,276 ) Finance lease obligation payments ( 1,238 ) ( 665 ) ( 622 ) Contingent consideration payment — — ( 60,243 ) Net cash required by financing activities ( 264,065 ) ( 716,541 ) ( 923,718 ) Effect of exchange rate changes on cash and cash equivalents ( 1,190 ) 2,210 ( 1,246 ) Net increase (decrease) in cash and cash equivalents ( 46,373 ) 106,495 ( 174,889 ) Cash and cash equivalents at beginning of period 423,569 317,074 491,963 Cash and cash equivalents at end of period $ 377,196 $ 423,569 $ 317,074 1 Prior period amounts have been reclassified to conform to current period presentation. The accompanying notes are an integral part of these consolidated financial statements. 71 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Years Ended December 31 (Thousands of dollars except number of shares) 2025 2024 2023 Common Stock Balance at beginning and end of year - par $ 1.00 , authorized 450,000,000 shares at December 31, 2025, 2024 and 2023, issued 195,100,628 shares at December 31, 2025, 2024 and 2023 $ 195,101 $ 195,101 $ 195,101 Capital in Excess of Par Value Balance at beginning of year 848,950 880,297 893,578 Restricted stock transactions and other ( 32,165 ) ( 70,539 ) ( 42,667 ) Share-based compensation 42,848 39,192 29,386 Balance at end of year 859,633 848,950 880,297 Retained Earnings Balance at beginning of year 6,773,289 6,546,079 6,055,498 Net income attributable to Murphy 104,234 407,171 661,559 Cash dividends paid ( 186,205 ) ( 179,961 ) ( 170,978 ) Balance at end of year 6,691,318 6,773,289 6,546,079 Accumulated Other Comprehensive Loss Balance at beginning of year ( 628,072 ) ( 521,117 ) ( 534,686 ) Foreign currency translation gain (loss), net of income taxes 73,993 ( 134,692 ) 36,598 Retirement and postretirement benefit plans, net of income taxes ( 148 ) 27,737 ( 23,029 ) Balance at end of year ( 554,227 ) ( 628,072 ) ( 521,117 ) Treasury Stock Balance at beginning of year ( 1,995,018 ) ( 1,737,566 ) ( 1,614,717 ) Repurchase of common stock ( 100,849 ) ( 302,681 ) ( 151,241 ) Awarded restricted stock, net of forfeitures 22,422 45,229 28,392 Balance at end of year – 52,315,476 shares of common stock in 2025, 49,255,504 shares of common stock in 2024 and 42,351,986 shares of common stock in 2023 ( 2,073,445 ) ( 1,995,018 ) ( 1,737,566 ) Murphy Shareholders’ Equity 5,118,380 5,194,250 5,362,794 Noncontrolling Interest Balance at beginning of year 147,593 186,859 154,119 Net income attributable to noncontrolling interest 34,565 79,314 62,122 Distributions to noncontrolling interest owners ( 63,841 ) ( 118,580 ) ( 29,382 ) Balance at end of year 118,317 147,593 186,859 Total Equity $ 5,236,697 $ 5,341,843 $ 5,549,653 The accompanying notes are an integral part of these consolidated financial statements. 72 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS These notes are an integral part of the consolidated financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 73 - 110 of the Form 10-K report. Note A – Significant Accounting Policies NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the U.S. and Canada and conducts oil and natural gas exploration activities worldwide. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries and are presented in conformity with GAAP. Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20 % to 50 % are accounted for by the equity method. Murphy reports 100 % of the sales volume, revenues, costs, assets and liabilities including the 20 % noncontrolling interest in MP GOM in accordance with accounting for noncontrolling interest as prescribed by Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-10-45, “Consolidations”. Other investments are generally carried at cost. Intercompany accounts and transactions are eliminated. USE OF ESTIMATES – Preparing the financial statements of the Company in accordance with GAAP requires management to make a number of estimates and assumptions that affect the reporting of amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates. REVENUE RECOGNITION – Revenues from sales of oil and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties, in which Murphy shares in the undivided interest with other producers, are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The Company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2025 and 2024, the liabilities for natural gas balancing were immaterial. Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues. CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents. MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. ACCOUNTS RECEIVABLE – At December 31, 2025 and 2024, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas and operating costs related to joint venture partners working interest share. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers, joint venture partners and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years. 73 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Continued) INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations. Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and including costs incurred to bring the inventory to its existing condition), or market. Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment. See Note E . PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on undeveloped property, the leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in “Property, plant and equipment” when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Oil and natural gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is assessed when there is an indication that the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its fair value. See Note D for further discussion of impairment charges. The Company records a liability for ARO equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled, or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and natural gas production facilities, plugging and abandoning wells and restoring sites are charged against the related liability. Any difference between costs incurred upon settlement of an ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings. See Note G for further discussion. Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production. Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information. CAPITALIZED INTEREST – Interest associated with borrowings from third parties is capitalized on significant oil and natural gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in “Property, plant and equipment” in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs. LEASES – At inception, contracts are assessed for the presence of a lease according to the criteria of ASC 842, “Leases”. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheets as “Operating lease assets” with the corresponding lease liabilities presented in “Operating lease liabilities” and “Non-current operating lease liabilities”. Finance lease assets are presented on the Consolidated Balance Sheets within 74 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Continued) “Property, plant and equipment”, with the corresponding liabilities presented in “Current maturities of long-term debt, finance lease” and “Long-term debt, including finance lease obligation”. Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates. Operating leases are expensed according to their nature and recognized in “Lease operating expenses”, “Selling and general expenses”, “Transportation, gathering and processing”, “Exploration expenses”, “Other operating expenses” or capitalized in the consolidated financial statements. Finance leases are depreciated with the relevant expenses recognized in “Depreciation, depletion and amortization” and “Interest expense, net” on the Consolidated Statements of Operations. ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists, and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded. If no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities arising from differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence, including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense. FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings as part of interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in “Accumulated Other Comprehensive Loss” in the Consolidated Statements of Stockholders’ Equity. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or it may decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. Certain physical delivery sale and purchase contracts are entered into in the normal course of business and qualify for, and are designated under, the normal purchase and normal sale scope exception provided by ASC 815, “Derivatives and Hedging”. Accordingly, these contracts are not accounted for as derivative instruments or recorded at fair value in the Consolidated Balance Sheets. Revenues and expenses associated with these contracts are recognized in net income (loss) when the underlying physical transactions occur. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its risk management objectives and strategy. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis, whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in 75 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Continued) “Accumulated other comprehensive loss” in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in “Accumulated other comprehensive loss” is recognized immediately in earnings. All commodity price derivatives for the periods provided are not designated as cash flow or fair value hedges and therefore changes in fair value are recognized in earnings. FAIR VALUE MEASUREMENTS – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. See Note O . STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units (PSUs) with market based conditions, and expense is recognized over the three-year vesting period. The fair value of PSUs with performance-based conditions and time-based restricted stock units (RSUs) is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years . The Company estimates the number of stock options and PSUs that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense, when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (SARs) and cash-settled restricted time-based stock units (CRSUs) as liability awards. Expense associated with these awards is recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SARs and the period-end price of the Company’s common stock for time-based CRSUs. When SARs are exercised and when CRSUs settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note I . PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statements of Operations are recorded net of tax in “Accumulated other comprehensive loss”. The remaining amounts in “Accumulated other comprehensive loss” include net actuarial losses and prior service (cost) credit. See Note J . NET INCOME (LOSS) PER COMMON SHARE – Basic net income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs, as the inclusion would have the effect of reducing the diluted loss per share. See Note L . Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Income Tax Disclosures. In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. The Company adopted this standard in the fourth quarter of 76 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note B - New Accounting Principles and Recent Accounting Pronouncements (Continued) 2025. The adoption did not affect the calculation of income tax expense. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note H . Recent Accounting Pronouncements Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impacts on our results of operations, cash flows and financial condition. The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption. Note C – Revenue from Contracts with Customers Nature of Goods and Services The Company explores for and produces oil and natural gas in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil, natural gas and NGLs. For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by GAAP. U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials. Canada - In Canada, contracts include long-term floating commodity index-priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments. Disaggregation of Revenue The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies. 77 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note C - Revenue from Contracts with Customers (Continued) The Company’s revenues and other income for each of the three years presented were as follows. Years Ended December 31, (Thousands of dollars) 2025 2024 2023 Net crude oil and condensate revenue United States - Onshore $ 617,358 $ 586,584 $ 676,139 United States - Offshore 1 1,355,527 1,777,723 2,072,353 Canada - Onshore 61,715 70,855 78,088 Canada - Offshore 187,030 193,961 78,650 Other 5,713 6,537 11,022 Total crude oil and condensate revenue 2,227,343 2,635,660 2,916,252 Net natural gas liquids revenue United States - Onshore 41,518 32,853 33,178 United States - Offshore 1 33,029 38,858 47,434 Canada - Onshore 5,626 7,454 8,914 Total natural gas liquids revenue 80,173 79,165 89,526 Net natural gas revenue United States - Onshore 35,524 17,443 21,346 United States - Offshore 1 70,968 50,329 71,332 Canada - Onshore 275,837 232,259 278,183 Total natural gas revenue 382,329 300,031 370,861 Revenue from production 2,689,845 3,014,856 3,376,639 Sales of purchased natural gas 2 Canada - Onshore — 3,742 72,215 Total sales of purchased natural gas — 3,742 72,215 Total revenue from sales to customers 2,689,845 3,018,598 3,448,854 Gain (loss) on derivative instruments 5,927 ( 1,707 ) — Gain on sale of assets and other operating income 23,051 11,583 11,293 Total revenues and other income $ 2,718,823 $ 3,028,474 $ 3,460,147 1 Includes revenue attributable to the noncontrolling interest in MP GOM. 2 Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and has risks and rewards of ownership. Sales of natural gas are reported when the contractual performance obligations are satisfied. This occurs at the time the product is delivered to a third party purchaser at the contractually determinable price. Contract Balances and Asset Recognition As of December 31, 2025 and 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 165.3 million and $ 178.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods. The Company has not entered into any revenue contracts that have financing components as of December 31, 2025, 2024 or 2023. The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer. 78 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note C - Revenue from Contracts with Customers (Continued) Performance Obligations The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity. For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods. The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy. As of December 31, 2025, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract. Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGLs Q2 2030 Deliveries from dedicated acreage in Eagle Ford Shale As produced Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCF/D Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCF/D Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCF/D Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCF/D Canada Natural Gas Q4 2027 Contracts to sell natural gas at CAD fixed pricing 9 MMCF/D Canada NGLs Q4 2026 Contracts to sell NGLs at CAD index pricing As produced The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes. Note D – Property, Plant and Equipment The Company’s property, plant and equipment assets for the respective periods are presented as follows: December 31, 2025 December 31, 2024 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 23,042,373 $ 8,099,291 2 $ 21,716,358 $ 8,021,620 2 Corporate and other 162,122 37,055 149,834 33,033 Property, plant and equipment $ 23,204,495 $ 8,136,346 $ 21,866,192 $ 8,054,653 ¹ Includes unproved mineral rights as follows: $ 229,759 $ 99,729 $ 283,015 $ 151,341 2 Includes $ 12,050 in 2025 and $ 13,335 in 2024 related to administrative assets and support equipment. Exploratory Wells Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well, and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. At December 31, 2025, 2024 and 2023, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 191.8 million, $ 72.1 million and $ 49.1 million, respectively. The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented. 79 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D – Property, Plant and Equipment (Continued) ( Thousands of dollars ) 2025 2024 2023 Beginning balance at January 1 $ 72,055 $ 49,118 $ 171,860 Additions pending the determination of proved reserves 119,766 49,408 48 Reclassifications to proved properties based on the determination of proved reserves — — ( 82,185 ) Capitalized exploration well costs charged to expense — ( 26,471 ) ( 40,605 ) Ending balance at December 31 $ 191,821 $ 72,055 $ 49,118 Capital additions of $ 119.8 million, for the year ended December 31, 2025, were mainly for the Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well, in Vietnam, encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations. Capital additions also included Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and Bubale-1X (Block CI-709) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire. Subsequent to year end, Murphy announced the successful discoveries of the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells, which encountered 50 feet and 30 feet of net pay, respectively. The Company also announced the results of two exploration wells in Côte d’Ivoire at the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and at the Caracal-1X (Block CI-102) exploration well, which will be plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. A portion of the Civette-1X dry hole charge was recorded in 2025. The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026. Capital additions of $ 49.4 million, for the year ended December 31, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam. Reclassifications to proved properties of $ 82.2 million, for the year ended December 31, 2023, were primarily related to Lac Da Vang-4X (Golden Camel), Block 15-1/05 exploration well in Vietnam. Capitalized well costs charged to dry hole expense were $ 26.5 million and $ 40.6 million for the years ended 2024 and 2023, respectively. In 2024, costs related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well. In 2023, costs related to the Cholula-1EXP well offshore Mexico and the Oso #1 (Atwater Valley 138) and Chinook #7 (Walker Ridge 425) exploration wells in the Gulf of America. The preceding table excludes well costs of $ 30.1 million, $ 46.7 million, and $ 129.2 million incurred and expensed directly to dry hole during the years ended 2025, 2024 and 2023, respectively. In 2025, these costs primarily included $ 30.0 million for the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire. In 2024, these costs primarily included $ 27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 13.4 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America. In 2023, the amount primarily included $ 82.0 million for the Chinook #7 (Walker Ridge 425) and $ 47.2 million for the non-operated Oso #1 (Atwater Valley 138) exploration wells in the Gulf of America. The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well. 2025 2024 2023 ( Thousands of dollars ) Amount No. of Wells Amount No. of Wells Amount No. of Wells Aging of capitalized well costs Zero to one year $ 28,384 2 $ 49,790 5 $ — 0 One to two years 140,959 6 — — — 0 Two to three years — — — — 2,698 1 Three years or more 22,478 3 22,265 3 46,420 3 $ 191,821 11 $ 72,055 8 $ 49,118 4 80 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D – Property, Plant and Equipment (Continued) Of the $ 163.4 million of exploratory well costs capitalized more than one year at December 31, 2025, $ 91.5 million was in Vietnam, $ 64.6 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. Property Additions On July 1, 2025, the Company purchased additional working interests in the Eagle Ford Shale, in acreages primarily operated by Murphy, for $ 23.0 million. During the first quarter of 2025, Murphy purchased the Pioneer FPSO from BW Offshore (UK) Limited for a gross purchase price of $ 125.0 million. The FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a new five-year contract. Dispositions In the fourth quarter of 2025, Murphy received a $ 12.5 million payment for achieving the first milestone related to the contingent sale of Brunei CA-2 in 2022, which resulted in a $ 4.0 million gain on sale of assets . In addition, the revaluation of the final milestone (anticipated in 2031) resulted in a $ 6.0 million gain on sale of assets. In September 2025, Murphy executed a purchase and sale agreement, which closed in October 2025, for the sale of leases in the Ralph and Saylee area of Tilden West for an adjusted sales price of $ 8.2 million. No gain or loss was recorded for this sale. Impairments In 2025, the Company recognized a pretax impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) related to the partial write-down of the Dalmatian field, in the Gulf of America, due to reserve reductions, as certain projects in the field were less competitive for capital allocation. In 2024, the Company recorded a pretax impairment charge of $ 62.9 million. In the first quarter of 2024, the Company recorded an impairment charge of $ 34.5 million related to the Calliope field, and in the fourth quarter of 2024, the Company recorded an impairment charge of $ 28.4 million related to the Nearly Headless Nick field. Both of the impairments were the result of operational issues that led to reserve reductions. There were no impairments recognized in 2023. Note E – Inventories Inventories consisted of the following for the respective periods presented. December 31, ( Thousands of dollars ) 2025 2024 Unsold crude oil $ 17,560 $ 18,745 Materials and supplies 39,724 36,113 Inventories $ 57,284 $ 54,858 81 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note F – Financing Arrangements and Debt Long-term debt for the respective periods presented consisted of the following. December 31, (Thousands of dollars) 2025 2024 Notes payable 5.875 % notes, due December 2027 $ 78,899 $ 78,899 6.375 % notes, due July 2028 148,590 148,590 7.050 % notes, due May 2029 117,582 117,582 6.000 % notes, due October 2032 600,000 600,000 5.875 % notes, due December 2042 ¹ 339,761 339,761 Total notes payable 1,284,832 1,284,832 Unamortized debt issuance cost and discount on notes payable ( 12,406 ) ( 14,336 ) Total notes payable, net of unamortized discount 1,272,426 1,270,496 Finance lease obligations, due through November 2034 12,654 4,877 Total debt including current maturities 1,285,080 1,275,373 Senior Unsecured Revolving Credit Facility 100,000 — Current maturities ( 2,514 ) ( 871 ) Total long-term debt $ 1,382,566 $ 1,274,502 1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s. The amounts of long-term principal repayable over each of the next five years and thereafter are as follows: nil in 2026, $ 78.9 million in 2027, $ 148.6 million in 2028, $ 217.6 million in 2029, nil in 2030 and $ 939.8 million thereafter. The Company also has a shelf registration statement on file with the SEC that permits the offer and sale of debt and/or equity securities through October 15, 2027. Revolving Credit Facility As of December 31, 2025, the Company had a $ 1.35 billion senior unsecured guaranteed RCF, with a maturity date of October 7, 2029. At December 31, 2025, the Company had $ 100.0 million outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduced the borrowing capacity of the RCF. At December 31, 2025, the interest rate in effect on borrowings under the facility was 6.04 %. At December 31, 2025, the Company was in compliance with all covenants related to the RCF. On the date the Company achieved certain credit ratings (Investment Grade Ratings Date), certain covenants would have been modified as set forth in the RCF. In addition, prior to Investment Grade Ratings Date, the Company would have been required to comply with a maximum consolidated leverage ratio of 3.25 x and a minimum consolidated interest coverage ratio of 2.50 x. From and after the Investment Grade Ratings Date, the Company will be required to comply with a maximum ratio of consolidated total debt to consolidated total capitalization of 60 %. Borrowings under the RCF bore interest at rates based on either the “Alternate Base Rate”, the “Adjusted Term Secured Overnight Financing Rate (SOFR) Rate”, or the “Adjusted Daily Simple SOFR Rate”, respectively, plus the “Applicable Rate”. The “Alternate Base Rate” of interest was the highest of (a) the Wall Street Journal prime rate in effect on such day, (b) the New York Federal Reserve Bank Rate in effect on such day plus ½ of 1% and (c) the Adjusted Term SOFR Rate for a one month interest period as published two U.S. Government Securities Business Days prior to such day (or if such day is not a U.S. Government Securities Business Day, the immediately preceding U.S. Government Securities Business Day) plus 1 %. The “Adjusted Term SOFR Rate” of interest was equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10 %. The “Adjusted Daily Simple SOFR Rate” of interest was equal to (a) the Daily Simple SOFR, plus (b) 0.10 %. The “Applicable Rate” of interest meant, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services. 82 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note F - Financing Arrangements and Debt (Continued) Subsequent Event - Revolving Credit Facility On January 2, 2026, the Company entered into an amended credit agreement governing a $ 2.00 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. The Amended RCF, which is effective January 2026, extends the borrowing term and increases the borrowing capacity of the previous RCF. All terms of the Amended RCF are substantially similar to the existing credit agreement, with an exception for the following: The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero . The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero . The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $ 12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF. Debt Offering On October 3, 2024, the Company closed the public offering of $ 600.0 million aggregate principal amount of senior notes that bear interest at a rate of 6.000 % per annum and mature on October 1, 2032. The Company incurred transaction costs of $ 10.1 million on the issuance of these notes. The Company pays interest semi-annually on April 1 and October 1 of each year. The proceeds of the $ 600.0 million notes were used to fund the repurchase and repayment of debt during the fourth quarter of 2024 to achieve a debt-neutral transaction. Subsequent Event - Debt Offering On January 23, 2026, the Company closed a public offering of $ 500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.500 % per annum and mature on February 15, 2034. The Company has incurred transaction costs of $ 8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $ 500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes. Debt Extinguishment In December 2024, the Company redeemed $ 79.0 million of the 2027 Notes. The total cost of the debt extinguishment of $ 1.2 million, consisting of cash costs of $ 0.8 million and non-cash costs of $ 0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. In October 2024, the Company tendered an aggregate $ 521.1 million of its notes, comprised of: $ 258.8 million of the 2027 Notes, $ 200.2 million of the 2028 Notes and $ 62.1 million of the 2029 Notes. The total cost of the debt extinguishment of $ 18.2 million, consisting of cash costs of $ 14.9 million and non-cash costs of $ 3.3 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. In May 2024, the Company paid a total of $ 50.5 million to complete the open market repurchases of $ 26.5 million aggregate principal of its 2027 Notes and $ 23.5 million aggregate principal of its 2028 Notes. The total cost of debt extinguishment of $ 0.9 million, consisting of cash costs of $ 0.5 million and non-cash costs of $ 0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024. Subsequent Event - Debt Extinguishment On January 23, 2026, the Company redeemed the remaining $ 78.9 million principal amount outstanding of its 2027 Notes and $ 148.6 million of its 2028 Notes, for an aggregate $ 227.5 million. The total cost of the debt extinguishment of $ 3.5 million consisted of cash costs of $ 2.5 million and non-cash costs of $ 1.0 million. Note G – Asset Retirement Obligations The ARO liabilities recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment. A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the respective periods presented is shown in the following table. 83 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note G - Asset Retirement Obligations (Continued) (Thousands of dollars) 2025 2024 Balance at beginning of year $ 1,008,884 $ 914,763 Accretion 57,730 52,511 Liabilities incurred 20,744 25,619 Revisions of previous estimates ( 12,094 ) 29,279 Liabilities settled ( 70,829 ) ( 1,898 ) Changes due to translation of foreign currencies 8,432 ( 11,390 ) Balance at end of period 1,012,867 1,008,884 Current portion of liability ( 41,959 ) ( 48,080 ) Non-current portion of liability $ 970,908 $ 960,804 The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors. Note H – Income Taxes The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows. ( Thousands of dollars ) 2025 2024 2023 Income (loss) from continuing operations before income taxes United States $ 195,245 $ 468,202 $ 901,761 Foreign ( 12,379 ) 99,367 19,308 Total $ 182,866 $ 567,569 $ 921,069 Income tax expense Current tax expense U.S. State and Local $ 468 $ 1,153 $ 2,916 Foreign 9,411 4,685 13,182 Total current tax expense 9,879 5,838 16,098 Deferred tax expense U.S. Federal 37,825 55,377 170,115 U.S. State and Local ( 1,214 ) ( 5,641 ) 3,706 Foreign ( 1,938 ) 22,698 6,002 Total deferred tax expense 34,673 72,434 179,823 Total income tax expense U.S. Federal 37,825 55,377 170,115 U.S. State and Local ( 746 ) ( 4,488 ) 6,622 Foreign 7,473 27,383 19,184 Total income tax expense $ 44,552 $ 78,272 $ 195,921 84 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note H – Income Taxes (Continued) The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense for each of the three years presented. ( Thousands of dollars ) 2025 2024 2023 Amount Percent Amount Percent Amount Percent Income tax expense based on the U.S. statutory tax rate $ 38,402 21.0 % $ 119,190 21.0 % $ 193,424 21.0 % Domestic Federal Tax Credits Research and development tax credits 2,521 1.4 ( 6,841 ) ( 1.2 ) ( 8,805 ) ( 1.0 ) Nontaxable or Nondeductible Items Tax effect on income attributable to NCI ( 7,259 ) ( 4.0 ) ( 16,656 ) ( 2.9 ) ( 13,046 ) ( 1.4 ) U.S. tax benefit on certain foreign upstream investments — — ( 33,677 ) ( 5.9 ) — — Other ( 397 ) ( 0.2 ) 2,398 0.4 ( 293 ) — Share-based payment awards 5,595 3.1 2,340 0.4 2,636 0.3 State and Local Income Taxes, Net of Federal Income Tax Effect 1 ( 589 ) ( 0.3 ) ( 3,546 ) ( 0.6 ) 4,725 0.5 Foreign Tax Effects Canada Statutory tax rate differential 2,629 1.4 5,428 1.0 3,732 0.4 Research and development tax credits ( 3,875 ) ( 2.1 ) ( 3,547 ) ( 0.6 ) ( 3,982 ) ( 0.4 ) Other Foreign jurisdictions Statutory tax rate differential 4,960 2.7 9,127 1.6 2,844 0.3 Changes in valuation allowances Côte d’Ivoire 13,140 7.2 — — — — Other Foreign Jurisdictions ( 2,922 ) ( 1.6 ) 2,636 0.5 10,853 1.2 Other ( 5,825 ) ( 3.2 ) ( 532 ) ( 0.2 ) 1,377 0.1 Worldwide Changes in Unrecognized Tax Benefits ( 1,828 ) ( 1.0 ) 1,952 0.3 2,456 0.3 Effective Tax Rate $ 44,552 24.4 % $ 78,272 13.8 % $ 195,921 21.3 % 1 State taxes primarily include Texas and Louisiana. 85 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note H – Income Taxes (Continued) The following table displays cash taxes paid, net of refunds, for each of the three years presented. ( Thousands of dollars ) 2025 2024 2023 U.S. State and Local Alabama $ ( 1,868 ) $ — $ 4,838 Texas 1,500 2,300 1,079 Other 50 — 51 Total U.S. State and Local ( 318 ) 2,300 5,968 Foreign Canada 2,929 6,480 3,553 Canada - Alberta 2,809 3,269 1,756 Brunei 681 599 1,079 Total Foreign 6,419 10,348 6,388 Total $ 6,101 $ 12,648 $ 12,356 An analysis of the Company’s deferred tax assets and deferred tax liabilities for the respective periods presented showing the tax effects of significant temporary differences follows. ( Thousands of dollars ) 2025 2024 Deferred tax assets Property and leasehold costs $ 235,509 $ 225,379 Liabilities for dismantlements 40,242 36,719 Postretirement and other employee benefits 66,418 66,293 U. S. net operating loss 224,956 289,594 Investment in partnership 20,307 9,096 Other deferred tax assets 1 97,660 100,352 Total gross deferred tax assets 685,092 727,433 Less: Valuation allowance ( 157,807 ) ( 149,498 ) Net deferred tax assets 527,285 577,935 Deferred tax liabilities Deferred tax on undistributed foreign earnings ( 5,000 ) ( 5,000 ) Accumulated depreciation, depletion and amortization ( 812,727 ) ( 811,178 ) Other deferred tax liabilities 1 ( 87,895 ) ( 97,547 ) Total gross deferred tax liabilities ( 905,622 ) ( 913,725 ) Net deferred tax (liabilities) assets $ ( 378,337 ) $ ( 335,790 ) 1 Other deferred tax assets and other deferred tax liabilities are primarily comprised of the deferred tax benefit and obligation associated with operating lease liabilities and the associated right of use assets, respectively. In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions that in the judgment of management at the present time are more likely than not to be unrealized. The valuation allowance increased $ 8.3 million in 2025, related all to non-U.S. items. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense, assuming no offsetting change in the deferred tax asset. The Company has a U.S. net operating loss carryforward of $ 1.1 billion at year-end 2025 with a corresponding deferred tax asset of $ 225.0 million. The Company believes the U.S. net operating loss being carried forward will more likely than not be utilized in future periods prior to expirations in 2037. 86 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note H – Income Taxes (Continued) Other Information Currently, the Company considers $ 100.0 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $ 5.0 million liability. At December 31, 2025, $ 1.6 billion of past foreign earnings are considered permanently reinvested. The Company closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to our business and the future operation of the Company. Uncertain Income Tax Positions The financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon ultimate settlement. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in “Other taxes payable” and “Deferred credits and other liabilities” in the Consolidated Balance Sheets for current and long-term portions, respectively. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table. ( Thousands of dollars ) 2025 2024 2023 Balance at January 1 $ 9,979 $ 6,384 $ 3,928 Additions for tax positions related to current year — 1,643 — Additions for tax positions related to prior year — 1,952 2,456 Reductions for tax positions related to prior year ( 882 ) — — Settlements with taxing authorities ( 946 ) — — Balance at December 31 $ 8,151 $ 9,979 $ 6,384 All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded liabilities of $ 0.3 million as of December 31, 2025, 2024 and 2023, respectively, for interest and penalties associated with uncertain tax positions. There were no interest or penalties associated with uncertain tax positions included in income tax expense for any period presented. In 2026, the Company currently does not expect to add to the provision for uncertain tax positions. Although existing liabilities could be reduced by settlement with taxing authorities or due to statute of limitations closing, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statements of Operations during 2026. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of December 31, 2025, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2016; Canada – 2021; and Malaysia – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. Note I – Incentive Plans Murphy utilizes cash-based and/or share-based incentive awards to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations, using a grant date fair value-based measurement method, over the periods that the awards vest. For cash-settled equity awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award. 87 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan). All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan. Additional information on the 2025 Long-Term Plan can be found in the Company’s Definitive Proxy Statement (Definitive 14A) dated March 28, 2025. The Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2020 Long-Term Plan, and the 2025 Long-Term Plan. The AIP authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock to employees. These grants may be in the form of stock options (nonqualified or incentive), Stock Appreciation Rights (SARs), restricted stock, RSUs, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term. Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under this Plan. Based on awards made to date, 3.872 million shares are available for grant under the 2025 Long-Term Plan at December 31, 2025. The Company also has a stock plan that permits the issuance of RSUs, stock options, or a combination thereof, to non-employee directors (NEDs). The Company currently has outstanding incentive awards issued to directors under the 2021 Stock Plan for NEDs (2021 NED Plan) and the 2018 Stock Plan for NEDs. All awards on or after May 12, 2021, were made under the 2021 NED Plan. The Company generally expects to issue treasury shares to satisfy the vesting of restricted stock and RSUs. Amounts recognized in the financial statements with respect to share-based plans for each of the three years presented are shown in the following table. ( Thousands of dollars ) 2025 2024 2023 Compensation charged against income before income tax benefit $ 50,107 $ 40,831 $ 58,760 Related income tax benefit recognized in income 6,438 5,513 9,330 As of December 31, 2025, there were $ 46.5 million in compensation costs, to be expensed over approximately the next two years , related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable withholding obligations, upon each RSU vest. Equity-Settled Awards PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023, 2024 and February 2025 under the 2020 Long-Term Plan, and in August 2025 under the 2025 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PSUs will not vest, but the recognized compensation cost associated with the stock award would not be reversed. The performance conditions for the PSUs are weighted 80 % on the Company’s total shareholder return (TSR) relative to an industry peer group and 20 % on the return on average capital employed (ROACE), measured over the applicable performance period. ROACE is calculated by dividing the Company’s EBITDA by the average of the opening and closing Capital Employed (the sum of total equity and short-term and long-term debt). During the performance period, PSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid, nor do voting rights exist on awards of PSUs prior to their settlement. The fair value of the PSUs based on the Company’s TSR was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year performance measurement period. The risk-free interest 88 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) rate is based on the yield curve of three-year U.S. Treasury bonds, and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 2025, 2024 and 2023 are presented in the following table. 2025 2024 2023 Fair value per share at grant date $ 19.65 - $ 22.11 $ 41.95 $ 60.46 Assumptions Expected volatility 40.00 % 50.00 % 81.00 % Risk-free interest rate 4.25 % 4.14 % 3.90 % Stock beta 0.980 1.062 1.034 Expected life 3.0 years 3.0 years 3.0 years The fair value of the PSUs based on ROACE was estimated based on the average high/low price of the Company’s stock on the grant date. Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2025 2024 2023 Outstanding at beginning of year 1,392,421 1,818,188 2,148,467 Granted 657,730 536,900 409,160 Vested and issued ( 481,670 ) ( 938,599 ) ( 408,135 ) Forfeited ( 104,966 ) ( 24,068 ) ( 331,304 ) Outstanding at end of year 1,463,515 1,392,421 1,818,188 TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s non-employee directors under the 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan and 2025 Long-Term Plan. The fair value of the time-based RSUs awarded for each of the last three years is presented in the following table. Type of Plan Valuation Methodology 2025 2024 2023 Non-Employee Directors 1 Closing Stock Price at Grant Date $ 22.50 - $ 31.25 $ 30.26 - $ 45.70 $ 43.27 Long-Term Incentive Plan 2 Average High/Low Stock Price at Grant Date $ 23.09 - $ 25.98 $ 37.78 - $ 45.98 $ 42.20 1 Under the 2021 NED Plan, RSUs granted in 2025 are scheduled to vest in February 2026. 2 The RSUs granted under the 2020 Long-Term Plan and the 2025 Long-Term Plan generally vest on the third anniversary of the date of grant. Changes in RSUs outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2025 2024 2023 Outstanding at beginning of year 1,558,600 1,219,584 1,227,792 Granted 559,284 741,228 556,100 Vested and issued ( 360,281 ) ( 330,444 ) ( 517,047 ) Forfeited ( 95,951 ) ( 71,768 ) ( 47,261 ) Outstanding at end of year 1,661,652 1,558,600 1,219,584 STOCK OPTIONS – In 2017, the Company ceased the inclusion of stock options and SARs as a part of the long-term incentive compensation mix. As of December 31, 2024, there were no outstanding SARs or stock options. During 2023, 11,000 stock options were exercised, and 2,000 stock options were forfeited, both at an exercise price of $ 28.51 per share, leaving zero options outstanding as of December 31, 2023. 89 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) Cash-Settled Awards The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of CRSUs. CRSUs generally settle on the third anniversary of the date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with common shares. Total pretax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $ 7.5 million in 2025, $ 1.7 million in 2024 and $ 29.4 million in 2023. The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $ 37.8 million, $ 37.1 million and $ 30.9 million was recorded in 2025, 2024 and 2023, respectively, for these plans. Note J – Employee and Retiree Benefit Plans PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory. Upon the disposal of Murphy’s former U.K. refining and marketing assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy. GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its Consolidated Balance Sheets and to recognize changes in that funded status between periods through “Accumulated other comprehensive loss”. The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status for the respective periods presented. 90 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2025 2024 2025 2024 Change in benefit obligation Obligation at January 1 $ 655,324 $ 699,151 $ 54,994 $ 63,808 Service cost 7,094 7,042 382 436 Interest cost 33,798 33,554 3,261 2,923 Participant contributions — — 2,762 2,730 Actuarial (gain) loss 1 1,175 ( 35,417 ) 17,681 825 Medicare Part D subsidy — — 383 358 Exchange rate changes 8,010 ( 3,263 ) 9 ( 14 ) Benefits paid ( 45,907 ) ( 45,743 ) ( 16,073 ) ( 16,072 ) Obligation at December 31 659,494 655,324 63,399 54,994 Change in plan assets Fair value of plan assets at January 1 492,120 477,809 — — Actual return on plan assets 48,285 27,317 — — Employer contributions 25,067 35,477 12,928 12,984 Participant contributions — — 2,762 2,730 Medicare Part D subsidy — — 383 358 Exchange rate changes 7,514 ( 2,740 ) — — Benefits paid ( 45,907 ) ( 45,743 ) ( 16,073 ) ( 16,072 ) Fair value of plan assets at December 31 527,079 492,120 — — Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 14,925 1,819 — — Other accrued liabilities ( 10,354 ) ( 10,617 ) ( 4,663 ) ( 4,237 ) Deferred credits and other liabilities ( 136,986 ) ( 154,406 ) ( 58,736 ) ( 50,757 ) Fund Status and net plan liability recognized at December 31 $ ( 132,415 ) $ ( 163,204 ) $ ( 63,399 ) $ ( 54,994 ) 1 Actuarial losses in 2025 for other post retirement benefits primarily relate to trend rate increases for incurred claims. Actuarial gains for pension benefits in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation. At December 31, 2025, amounts included in “Accumulated other comprehensive loss” in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table. ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits Net actuarial gain (loss) $ ( 148,280 ) $ 18,862 Prior service (credit) cost ( 16,320 ) 2,873 $ ( 164,600 ) $ 21,735 91 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets. Projected Benefit Obligations Accumulated Benefit Obligations Fair Value of Plan Assets ( Thousands of dollars ) 2025 2024 2025 2024 2025 2024 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ — $ 497,947 $ — $ 489,225 $ — $ 477,983 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 147,339 145,058 145,545 143,859 — — Unfunded other postretirement plans 63,399 54,994 63,399 54,994 — — The table that follows provides the components of net periodic benefit expense for each of the three years presented. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2025 2024 2023 2025 2024 2023 Service cost $ 7,094 $ 7,042 $ 6,542 $ 382 $ 436 $ 495 Interest cost 33,798 33,554 34,140 3,261 2,923 3,241 Expected return on plan assets ( 35,511 ) ( 33,427 ) ( 32,839 ) — — — Amortization of prior service cost (credit) 1,967 2,316 620 ( 532 ) ( 532 ) ( 532 ) Recognized actuarial (gain) loss 7,262 9,438 9,776 ( 3,182 ) ( 3,586 ) ( 3,512 ) Net periodic benefit cost (credit) 14,610 18,923 18,239 ( 71 ) ( 759 ) ( 308 ) Other pension costs 276 251 219 — — — Total net periodic benefit cost (credit) $ 14,886 $ 19,174 $ 18,458 $ ( 71 ) $ ( 759 ) $ ( 308 ) The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2025 2024 2025 2024 Benefit obligation at December 31 $ 109,883 $ 115,428 $ 90 $ 106 Fair value of plan assets at December 31 110,280 103,445 — — Net plan liabilities recognized 397 ( 11,983 ) ( 90 ) ( 106 ) Net periodic benefit (credit) expense 2,131 1,480 ( 35 ) ( 44 ) 92 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2025 and 2024 and net periodic benefit expense for 2025 and 2024. Benefit Obligations Net Periodic Benefit Expense Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, December 31, Year Year 2025 2024 2025 2024 2025 2024 2025 2024 Discount rate on obligation, interest cost and service cost 5.41 % 5.58 % 5.48 % 5.65 % 5.54 % 5.17 % 5.66 % 5.15 % Rate of compensation increase 3.50 % 3.38 % — — 3.50 % 3.50 % — — Cash balance interest credit rate 3.70 % 3.20 % — — — — — — Expected return on plan assets — — — — 7.29 % 7.19 % — — The discount rates used for determining the plan obligations and expense are based on high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate, which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company. The plan’s cash balance interest accumulation rate is the greater of the annual yield on 10-year treasury constant maturities or 1.89 %. Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company, are shown in the following table. ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits 2026 $ 49,819 $ 4,663 2027 51,276 4,710 2028 51,786 4,872 2029 51,646 4,772 2030 53,230 4,752 2031-2035 260,581 23,671 For purposes of measuring postretirement benefit obligations at December 31, 2025, the future annual rates of increase in the cost of health care were assumed to be 7.9 % for 2026 decreasing each year to an ultimate rate of 4.0 % in 2050 and thereafter. During 2025, the Company made contributions of $ 24.3 million to its domestic defined benefit pension plans and $ 12.9 million to its domestic postretirement benefits plan. During 2026, the Company currently expects to make contributions of $ 23.8 million to its domestic defined benefit pension plans, $ 0.8 million to its foreign defined benefit pension plans and $ 4.7 million to its domestic postretirement benefits plan. PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement that establishes investment standards related to its funded domestic qualified retirement plan. Our investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include equities, fixed income and other investments, including hedge funds, real estate and cash equivalent securities. Investment managers are prohibited from investing in equity or fixed income securities issued by the Company. The majority of plan assets are highly liquid, providing flexibility for benefit payment requirements. The current target allocations for plan assets are 40 - 75 % equity securities, 20 - 60 % fixed 93 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) income securities, 0 - 15 % alternatives and 0 - 20 % cash and equivalents. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels. The weighted average asset allocation for the Company’s funded pension benefit plans at the respective balance sheet dates are shown in the following table. December 31, 2025 2024 Equity securities 45.2 % 57.3 % Fixed income securities 42.7 % 36.2 % Alternatives 7.4 % 3.7 % Cash equivalents 4.7 % 2.8 % 100.0 % 100.0 % The Company’s weighted average expected return on plan assets was 7.3 % in 2025 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 7.3 % expected return was comprised of the weighted average expected future equity securities return of 7.6 % and a fixed income securities return of 5.0 %. An average expected investment expense of 0.5 % is included in this calculation. Over the last 10 years, the return on funded retirement plan assets has averaged 4.1 %. At December 31, 2025, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2025 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 83,956 $ 73,999 $ — $ 9,957 U.S. small/midcap 56,699 56,699 — — Other alternative strategies 21,032 — — 21,032 International equity 27,772 27,772 — — Emerging market equity 13,518 13,518 — — Fixed income securities: U.S. fixed income 186,995 119,205 67,790 — International commingled trust fund 7,047 — 7,047 — Cash and equivalents 19,779 19,779 — — Total Domestic Plans 416,798 310,972 74,837 30,989 Foreign Plans Equity securities funds 13,946 — 13,946 — Fixed income securities funds 30,986 — 30,986 — Diversified pooled fund 42,124 — 42,124 — Other 18,454 — 532 17,922 Cash and equivalents 4,771 — 4,771 — Total Foreign Plans 110,281 — 92,359 17,922 Total $ 527,079 $ 310,972 $ 167,196 $ 48,911 94 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) At December 31, 2024, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows. Fair Value Measurements Using ( Thousands of dollars ) Fair Value at December 31, 2024 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Domestic Plans Equity securities: U.S. core equity $ 87,124 $ 87,124 $ — $ — U.S. small/midcap 51,978 51,978 — — Other alternative strategies 965 — — 965 International equity 22,724 22,724 — — Emerging market equity 7,638 7,638 — — Fixed income securities: U.S. fixed income 208,755 105,302 103,453 — Cash and equivalents 9,491 9,491 — — Total Domestic Plans 388,675 284,256 103,453 965 Foreign Plans Equity securities funds 14,377 — 14,377 — Fixed income securities funds 26,500 — 26,500 — Diversified pooled fund 41,054 — 41,054 — Other 17,049 — — 17,049 Cash and equivalents 4,465 — 4,465 — Total Foreign Plans 103,445 — 86,396 17,049 Total $ 492,120 $ 284,256 $ 189,849 $ 18,014 The definition of levels within the fair value hierarchy in the tables above is included in Note O . For domestic plans, U.S. core, small/midcap, international, emerging market equity securities and U.S. treasury securities are valued based on quoted prices in active markets. For commercial paper securities, the prices received generally utilize observable inputs in the pricing methodologies. Other alternative strategies funds consist of four investments. The Company's domestic level 3 investments primarily relate to funds which invest primarily in U.S. middle-market companies using various types of credit instruments. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. and Canadian securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of U.K. and foreign equity securities. 95 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Employee and Retiree Benefit Plans (Continued) The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below: ( Thousands of dollars ) Hedged Funds and Other Alternative Strategies Total at December 31, 2023 $ 24,454 Actual return (loss) on plan assets 1 : Relating to assets held at the reporting date ( 3,574 ) Purchases, sales and settlements ( 2,865 ) Total at December 31, 2024 18,015 Actual return on plan assets 1 : Relating to assets held at the reporting date 2,394 Purchases, sales and settlements 28,502 Total at December 31, 2025 $ 48,911 1 Gains and losses on Level 3 plan assets are recognized in the Consolidated Statements of Comprehensive Income (Loss) under the caption "Retirement and postretirement benefit plans.” 401(K) PLANS - Most full-time U.S. employees of the Company may participate in a 401(k) or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s plan, with a maximum match of 6.0 %. Amounts charged to expense for the Company’s match to these plans were $ 9.1 million in 2025, $ 8.7 million in 2024 and $ 8.5 million in 2023. Note K – Financial Instruments and Risk Management DERIVATIVE INSTRUMENTS – Murphy uses derivative instruments, such as swaps and zero-cost commodity price collar contracts, to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges, such as the NYMEX. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Commodity Price Risks The Company is subject to commodity price risk related to products it produces and sells. During 2025 and 2024 the Company entered into natural gas swap contracts. Under the swap contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold. During 2025, the Company entered into natural gas swap contracts that matured by December 31, 2025. The Company did not have any outstanding natural gas derivative contracts at year end. Volumes per day and the weighted average prices for these contracts were as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 40 $ 3.58 2/1/2025 6/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.65 7/1/2025 9/30/2025 Fixed price derivative swap United States Natural gas 60 $ 3.74 10/1/2025 12/31/2025 96 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Financial Instruments and Risk Management (Continued) During 2024, the Company entered into natural gas swap contracts that were effective in 2025. At December 31, 2024, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural gas 20 $ 3.20 1/1/2025 1/31/2025 Foreign Currency Exchange Risks The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2025 and 2024. At December 31, 2025 and 2024, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. See also Note O . ( Thousands of dollars ) Asset (Liability) Derivatives Fair Value at December 31, Type of Derivative Contract Balance Sheets Location 2025 2024 Commodity swaps Accounts payable $ — ( 1,707 ) The gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments for each of the three years presented are shown in the following table. Gain (Loss) ( Thousands of dollars ) Year Ended December 31, Type of Derivative Contract Statements of Operations Locations 2025 2024 2023 Commodity swaps Gain (loss) on derivative instruments $ 5,927 $ ( 1,707 ) $ — Credit Risks The Company is subject to credit risks primarily associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S. and Canada and cost sharing amounts, of operating and capital costs billed to partners, for properties operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended. Security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk associated with any one customer. Cash balances and cash equivalents are held with several major financial institutions, which limit the Company’s exposure to credit risk for its cash assets. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal, because counterparties to the majority of transactions are major financial institutions. 97 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note L – Net Income (Loss) Per Common Share Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for each of the three years presented . The following table reconciles the weighted-average shares outstanding used for these computations. ( Weighted-average shares, except per share amounts ) 2025 2024 2023 Basic method 143,124,118 150,011,458 155,233,560 Dilutive restricted stock units 901,204 1,015,894 1,412,869 Diluted method 144,025,322 151,027,352 156,646,429 NET INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ 0.73 $ 2.73 $ 4.27 Discontinued operations — ( 0.02 ) ( 0.01 ) Net income $ 0.73 $ 2.71 $ 4.26 NET INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 0.72 $ 2.72 $ 4.23 Discontinued operations — ( 0.02 ) ( 0.01 ) Net income $ 0.72 $ 2.70 $ 4.22 Note M – Other Financial Information Gain (Loss) from Foreign Currency Transactions Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $ 29.4 million loss in 2025, $ 45.4 million gain in 2024 and $ 10.8 million loss in 2023. Supplemental Information to Statements of Cash Flows ( Thousands of dollars ) 2025 2024 2023 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ ( 75,437 ) $ 71,081 $ 47,151 (Increase) decrease in inventories ( 1,461 ) 1,327 329 (Increase) decrease in prepaid expenses 539 1,192 ( 1,293 ) Increase (decrease) in accounts payable and accrued liabilities 1 3,101 3,287 ( 140,011 ) Increase (decrease) in income taxes payable ( 794 ) ( 2,004 ) ( 5,537 ) Net (increase) decrease in noncash working capital $ ( 74,052 ) $ 74,883 $ ( 99,361 ) Supplementary disclosures: Interest paid, net of amounts capitalized of $ 8.8 million in 2025, $ 11.4 million in 2024 and $ 14.5 million in 2023 88,119 78,806 108,912 Non-cash investing activities: Asset retirement costs capitalized $ 9,629 $ 47,233 $ 32,975 (Increase) decrease in capital expenditure accrual ( 98,778 ) ( 5,935 ) 17,517 1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments. 98 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note N – Accumulated Other Comprehensive Loss The components of ”Accumulated other comprehensive loss” on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table. ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) Retirement and Postretirement Benefit Plan Adjustments Total Balance at December 31, 2023 $ ( 381,632 ) $ ( 139,485 ) $ ( 521,117 ) 2024 components of other comprehensive income (loss): Before reclassifications to income ( 134,692 ) 23,713 ( 110,979 ) Reclassifications to income — 4,024 ¹ 4,024 Net other comprehensive income ( 134,692 ) 27,737 ( 106,955 ) Balance at December 31, 2024 ( 516,324 ) ( 111,748 ) ( 628,072 ) 2025 components of other comprehensive income (loss): Before reclassifications to income 73,993 ( 3,633 ) 70,360 Reclassifications to income — 3,485 ¹ 3,485 Net other comprehensive income (loss) 73,993 ( 148 ) 73,845 Balance at December 31, 2025 $ ( 442,331 ) $ ( 111,896 ) $ ( 554,227 ) 1 Reclassifications before taxes of $ 4.2 million and $ 5.4 million are included in the computation of net periodic benefit expense in 2025 and 2024, respectively. See Note J for additional information. Related income taxes of $ 0.7 million and $ 1.4 million are included in income tax expense in 2025 and 2024, respectively. Note O – Assets and Liabilities Measured at Fair Value Fair Values – Recurring The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. The fair value measurements for these assets and liabilities for the respective periods presented are shown in the following table. December 31, 2025 December 31, 2024 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 22,205 $ — $ — $ 22,205 $ 19,469 $ — $ — $ 19,469 Commodity swaps — — — — — 1,707 — 1,707 $ 22,205 $ — $ — $ 22,205 $ 19,469 $ 1,707 $ — $ 21,176 The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations. As of December 31, 2025, there were no outstanding commodity (NYMEX Henry Hub natural gas) swaps subject to fair value measurement. The liabilities associated with these contacts have been finalized as of December 31, 2025 and were based on realized NYMEX Henry Hub pricing. The commodity swaps liability as of December 31, 2024 was $ 1.7 million and recorded as “ Accounts payable ” in the Consolidated Balance Sheets. The fair value of 99 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note O – Assets and Liabilities Measured at Fair Value (Continued) the commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in fair value of natural gas derivative contracts was recorded in “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations. The Company was previously exposed to contingent consideration payments related to a prior asset purchase agreement, which required additional payments contingent on specified revenue thresholds and project milestones being met. At December 31, 2022, the Company’s liabilities were finalized and no longer subject to fair value measurement. Final cash payment was made in 2023 and was recorded to “Contingent consideration payment“ in the Consolidated Statements of Cash Flows. The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at December 31, 2025 and 2024. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2025 and 2024. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was minimal. December 31, 2025 2024 ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value Financial liabilities: Current and long-term debt $ 1,385,080 $ 1,326,101 $ 1,275,374 $ 1,185,961 Fair Values – Nonrecurring Impairment expenses of $ 115.0 million and $ 62.9 million were incurred in 2025 and 2024, respectively. In 2025, an impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) was recorded for the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation. In 2024, an impairment charge of $ 34.5 million was recorded for the Calliope field and an impairment charge of $ 28.4 million was recorded for the Nearly Headless Nick field, in the Gulf of America. Both impairment charges were due to operational issues that led to reserve reductions. The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region. The fair value information associated with the impaired properties is presented in the following tables. Year Ended December 31, 2025 Net Book Value Prior to Impairment Total Pretax Impairment Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 Assets: Impaired proved properties United States - Offshore $ — $ — $ 42,397 $ 157,399 $ 115,002 100 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note O – Assets and Liabilities Measured at Fair Value (Continued) Year Ended December 31, 2024 Net Book Value Prior to Impairment Total Pretax Impairment Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 Assets: Impaired proved properties United States - Offshore $ — $ — $ 501 $ 63,410 $ 62,909 Note P – Commitments The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Canada Onshore. The U.S. Onshore and U.S. Offshore transportation contracts require minimum monthly payments through 2045, while the Canada Onshore transportation contracts call for minimum monthly payments through 2051. In the U.S. and Canada Onshore, future required minimum annual payments for the next five years are $ 132.8 million in 2026, $ 107.3 million in 2027, $ 97.6 million in 2028, $ 66.3 million in 2029 and $ 45.8 million in 2030. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Commitments for Vietnam in Other Offshore include future operating agreements for production activities. Annual payments for the next five years are $ 23.6 million in 2026, $ 23.1 million in 2027, $ 24.0 million in 2028, $ 23.9 million in 2029 and $ 24.2 million in 2030. Commitments for capital expenditures were approximately $ 551.2 million at December 31, 2025, primarily consisting of $ 245.3 million for the Gulf of America, $ 82.6 million for the Eagle Ford Shale, $ 49.8 million for Canada, $ 127.5 million for Vietnam, and $ 45.0 million in for Côte d’Ivoire. Note Q – Environmental and Other Contingencies The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; trade policies, tariffs and other trade restrictions; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company. ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other GHG emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased. 101 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note Q – Environmental and Other Contingencies (Continued) Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this item, the Company will be using a threshold of $ 1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $ 1.0 million threshold. In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the EPA published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the GHGRP for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. The repeal calls into question the EPA’s authority to regulate GHGs, as well as the EPA’s prior scientific assessment of climate change risks. Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact the EPA’s regulation of GHG emissions going forward. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions. The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change 102 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note Q - Environmental and Other Contingencies (Continued) litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition. There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity. LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period. Note R – Common Stock Issued and Outstanding Activity in the number of shares of common stock issued and outstanding for each of the three years presented is shown below. ( Number of shares outstanding ) 2025 2024 2023 Beginning of year 145,845,124 152,748,642 155,467,319 Stock options exercised 1 — — 2,657 Restricted stock awards 1 553,478 1,105,268 689,824 Treasury shares purchased ( 3,613,450 ) ( 8,008,786 ) ( 3,411,158 ) End of year 142,785,152 145,845,124 152,748,642 1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon issuance of shares. The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $ 1,100.0 million of its common stock. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors. During the year ended December 31, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $ 100.0 million ($ 100.8 million including excise taxes and fees). As of December 31, 2025, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program. The share repurchase program is a component of the Company’s capital allocation framework, the details of which can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024. Note S – Business Segments Murphy’s reportable segments are organized into geographic areas of operations. The Company’s E&P activity is subdivided into segments for the U.S., Canada and all other countries. Each of these segments derive revenues primarily from the sale of crude oil, NGLs and/or natural gas. The Company’s management team and Chief Operating Decision Maker (CODM) evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense, and allocates financial and capital resources for each segment predominantly in the annual budget and forecasting process. The CODM also considers budget-to-actual variances on a monthly basis for the performance measure when making decisions about allocating capital and personnel to the segments. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the CODM. Customers that accounted for 10% or more of the Company’s sales revenue for each of the below three years ended December 31, are shown below. 103 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note S – Business Segments (Continued) 2025 2024 2023 Chevron Corporation 19 % 13 % 16 % ExxonMobil Corporation 12 % 20 % 27 % Phillips 66 N/A 10 % N/A Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices. No assets were held for sale as of December 31, 2025 and 2024. The Company has accounted for its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations for all periods presented. Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. “Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the years presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment. 104 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note S – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, and Discontinued Operations Consolidated Total Year ended December 31, 2025 Revenue from production $ 2,153.9 $ 530.2 $ 5.7 $ 2,689.8 $ — $ 2,689.8 Gain on sales of assets and other operating income 5.9 1.7 10.0 17.6 13.8 31.4 Total revenues and other income 2,159.8 531.9 15.7 2,707.4 13.8 2,721.2 Lease operating expenses Lease operating expenses and taxes other than income 391.4 178.9 2.5 572.8 — 572.8 Repair and maintenance 60.8 5.1 — 65.9 — 65.9 Workovers 124.9 1.6 — 126.5 — 126.5 Total lease operating expenses 577.1 185.6 2.5 765.2 — 765.2 Severance and ad valorem taxes 37.7 1.5 — 39.2 — 39.2 Transportation, gathering and processing 107.0 92.7 — 199.7 — 199.7 Selling and general expenses 13.7 23.7 8.8 46.2 91.1 137.3 Exploration expenses Geological and geophysical 27.2 0.1 8.7 36.0 — 36.0 Dry holes and previously suspended exploration costs ( 0.9 ) — 31.0 30.1 — 30.1 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 14.7 0.3 30.6 45.6 — 45.6 Total exploration expenses 41.0 0.4 70.3 111.7 — 111.7 Depreciation, depletion and amortization 822.1 144.8 2.5 969.4 8.4 977.8 Impairment of assets 115.0 — — 115.0 — 115.0 Accretion of asset retirement obligations 46.6 10.3 0.7 57.6 0.1 57.7 Other operating expenses (income) 10.8 1.8 ( 0.9 ) 11.7 2.2 13.9 Interest income ( 1.7 ) — — ( 1.7 ) ( 11.8 ) ( 13.5 ) Interest expense, net of capitalization 0.1 0.1 0.2 0.4 95.7 96.1 Income tax expense (benefit) Current income tax expense (benefit) 0.8 10.6 0.3 11.7 ( 1.8 ) 9.9 Deferred income tax expense (benefit) 76.9 4.0 ( 2.4 ) 78.5 ( 43.8 ) 34.7 Total income tax expense (benefit) 77.7 14.6 ( 2.1 ) 90.2 ( 45.6 ) 44.6 Other segment costs 4.2 1.6 0.3 6.1 31.6 37.7 Segment income (loss) - including NCI 1 $ 308.5 $ 54.8 $ ( 66.6 ) $ 296.7 $ ( 157.9 ) $ 138.8 Additions to property, plant, equipment $ 763.5 $ 152.5 $ 180.9 $ 1,096.9 $ 21.2 $ 1,118.1 Total assets at year-end 6,771.3 2,000.0 598.1 9,369.4 463.2 9,832.6 1 Includes results attributable to the noncontrolling interest in MP GOM. 105 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note S – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, and Discontinued Operations Consolidated Total Year ended December 31, 2024 Revenue from production $ 2,503.8 $ 504.5 $ 6.6 $ 3,014.9 $ — $ 3,014.9 Sales of purchased natural gas — 3.7 — 3.7 — 3.7 Gain on sales of assets and other operating income 4.5 1.5 — 6.0 3.9 9.9 Total revenues and other income 2,508.3 509.7 6.6 3,024.6 3.9 3,028.5 Lease operating expenses Lease operating expenses and taxes other than income 471.3 176.8 1.6 649.7 — 649.7 Repair and maintenance 63.7 4.8 — 68.5 — 68.5 Workovers 214.9 3.9 — 218.8 — 218.8 Total lease operating expenses 749.9 185.5 1.6 937.0 — 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 — 3.1 Selling and general expenses ( 3.3 ) 20.4 6.7 23.8 89.1 112.9 Exploration expenses — Geological and geophysical 14.4 0.2 12.6 27.2 — 27.2 Dry holes and previously suspended exploration costs 70.9 — 2.3 73.2 — 73.2 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 10.9 0.3 21.9 33.1 — 33.1 Total exploration expenses 96.2 0.5 36.8 133.5 — 133.5 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 8.9 865.8 Impairment of assets 62.9 — — 62.9 — 62.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 0.1 52.5 Other operating expenses (income) 9.3 2.8 2.1 14.2 ( 3.2 ) 11.0 Interest income ( 22.0 ) — — ( 22.0 ) ( 12.2 ) ( 34.2 ) Interest expense, net of capitalization 0.2 0.4 0.2 0.8 105.1 105.9 Income tax expense (benefit) Current income tax expense (benefit) 1.5 3.2 0.2 4.9 0.9 5.8 Deferred income tax expense (benefit) 123.8 8.8 ( 31.2 ) 101.4 ( 28.9 ) 72.5 Total income tax expense (benefit) 125.3 12.0 ( 31.0 ) 106.3 ( 28.0 ) 78.3 Other segment costs (income) 6.9 0.1 0.3 7.3 ( 44.0 ) ( 36.7 ) Segment income (loss) - including NCI 1 $ 561.9 $ 49.0 $ ( 12.5 ) $ 598.4 $ ( 111.9 ) $ 486.5 Additions to property, plant, equipment $ 601.7 $ 137.9 $ 71.8 $ 811.4 $ 29.2 $ 840.6 Total assets at year-end 6,953.8 1,919.8 302.0 9,175.6 491.9 9,667.5 1 Includes results attributable to the noncontrolling interest in MP GOM. 106 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note S – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, and Discontinued Operations Consolidated Total Year ended December 31, 2023 Revenue from production $ 2,921.8 $ 443.8 $ 11.0 $ 3,376.6 $ — $ 3,376.6 Sales of purchased natural gas — 72.2 — 72.2 — 72.2 Gain on sales of assets and other operating income 6.5 1.5 — 8.0 3.3 11.3 Total revenues and other income 2,928.3 517.5 11.0 3,456.8 3.3 3,460.1 Lease operating expenses Lease operating expenses and taxes other than income 532.3 144.7 1.9 678.9 — 678.9 Repair and maintenance 53.2 5.0 — 58.2 — 58.2 Workovers 45.2 2.1 — 47.3 — 47.3 Total lease operating expenses 630.7 151.8 1.9 784.4 — 784.4 Severance and ad valorem taxes 41.4 1.4 — 42.8 — 42.8 Transportation, gathering and processing 157.0 76.0 — 233.0 — 233.0 Costs of purchased natural gas — 51.7 — 51.7 — 51.7 Selling and general expenses 11.8 16.5 9.4 37.7 81.2 118.9 Exploration expenses — Geological and geophysical 6.6 0.1 19.4 26.1 — 26.1 Dry holes and previously suspended exploration costs 153.1 — 16.7 169.8 — 169.8 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 14.9 0.4 23.6 38.9 — 38.9 Total exploration expenses 174.6 0.5 59.7 234.8 — 234.8 Depreciation, depletion and amortization 706.0 142.2 2.3 850.5 11.0 861.5 Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 0.1 46.1 Other operating expenses (income) 27.2 15.5 8.1 50.8 ( 4.4 ) 46.4 Interest income ( 3.3 ) — — ( 3.3 ) ( 9.3 ) ( 12.6 ) Interest expense, net of capitalization 0.1 0.2 0.2 0.5 111.9 112.4 Income tax expense (benefit) Current income tax expense (benefit) 3.1 3.7 0.6 7.4 8.8 16.2 Deferred income tax expense (benefit) 229.6 7.5 ( 6.7 ) 230.4 ( 50.6 ) 179.8 Total income tax expense (benefit) 232.7 11.2 ( 6.1 ) 237.8 ( 41.8 ) 196.0 Other segment costs 7.2 1.1 0.6 8.9 12.1 21.0 Segment income (loss) - including NCI 1 $ 905.1 $ 41.6 $ ( 65.5 ) $ 881.2 $ ( 157.5 ) $ 723.7 Additions to property, plant, equipment $ 671.3 $ 206.2 $ 13.1 $ 890.6 $ 24.2 $ 914.8 Total assets at year-end 7,107.0 2,080.0 213.3 9,400.2 366.5 9,766.7 1 Includes results attributable to the noncontrolling interest in MP GOM. 107 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note S – Business Segments (Continued) Geographic Information Certain long-lived assets at December 31 1 ( Millions of dollars ) United States Canada Other Total 2025 $ 6,236.8 $ 1,460.6 $ 438.9 $ 8,136.3 2024 6,415.9 1,389.5 249.2 8,054.6 2023 6,555.0 1,497.3 172.8 8,225.1 1 Certain long-lived assets at December 31 represent total non-current assets, excluding investments, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets. Note T – Leases Nature of Leases The Company has entered into various operating and financial leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and natural gas field equipment. Remaining lease terms range from 1 year to 15 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of Company discretion and mutual agreement between the Company and the lessor. Purchase options also exist for certain leases. 108 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note T – Leases (Continued) Related Expenses Expenses related to finance and operating leases (both short-term and long-term) included in the Consolidated Financial Statements are as follows. Year Ended December 31, (Thousands of dollars) Financial Statements Category 2025 2024 Operating lease 1, 2 Lease operating expenses $ 342,520 $ 411,303 Operating lease 2 Transportation, gathering and processing 8,308 16,117 Operating lease 2 Selling and general expenses 10,405 10,990 Operating lease 2 Other operating expense 467 6,622 Operating lease 2 Exploration expenses 14,335 38,974 Operating lease 2 Property, plant and equipment 175,400 277,170 Operating lease 2 Asset retirement obligations 85,690 10 Finance lease Amortization of asset Depreciation, depletion and amortization 1,026 855 Interest on lease liabilities Interest expense, net 229 193 Sublease income Other income ( 240 ) ( 1,143 ) Net lease expense $ 638,140 $ 761,091 1 Variable lease expenses. For the years ended December 31, 2025 and 2024, included variable lease expenses of $ 34.6 million and $ 42.3 million, respectively, primarily related to operating costs at a natural gas processing plant in our Canada Onshore business. 2 Short-term leases due within 12 months. The table below shows amounts included in the Consolidated Financial Statements related to short-term leases due within 12 months. These expenses primarily related to drilling rigs and other oil and natural gas field equipment. (Thousands of dollars) Year Ended December 31, Financial Statements Category 2025 2024 Lease operating expenses $ 159,746 $ 236,402 Transportation, gathering and processing 8,308 12,993 Selling and general expenses 1,918 772 Other operating expense 16 6,230 Exploration expenses 13,211 38,500 Property, plant and equipment 96,909 97,104 Asset retirement obligations 65,418 10 Total short-term lease expense $ 345,526 $ 392,011 Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2026 $ 315,609 $ 3,302 $ 318,911 2027 146,130 3,302 149,432 2028 63,009 3,302 66,311 2029 60,214 2,491 62,705 2030 58,445 1,885 60,330 Remaining 366,321 774 367,095 Total future minimum lease payments 1,009,728 15,056 1,024,784 Less imputed interest ( 193,121 ) ( 2,402 ) ( 195,523 ) Present value of lease liabilities 1 $ 816,607 $ 12,654 $ 829,261 1 Includes both the current and long-term portion of the lease liabilities. 109 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note T – Leases (Continued) Lease Term and Discount Rate December 31, 2025 December 31, 2024 Weighted average remaining lease term: Operating leases 7 years 8 years Finance leases 5 years 6 years Weighted average discount rate: Operating leases 5.5 % 5.7 % Finance leases 5.4 % 4.9 % Other Information Year Ended December 31, (Thousands of dollars) 2025 2024 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 258,564 $ 328,847 Operating cash flows from finance leases 339 311 Financing cash flows from finance leases 1,238 665 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 247,566 $ 349,312 Finance leases 2 8,845 1,749 1 For the year ended December 31, 2025, right-of-use assets, obtained in exchange for operating lease liabilities, primarily included $ 153.7 million for a drill ship operating lease extension used in our U.S. Offshore business and $ 72.2 million for a drilling rig and two support vessels in our Vietnam business. December 31, 2024 included $ 254.1 million for a drill ship operating lease extension in our U.S. Offshore business and $ 52.7 million related to two drilling rigs and several natural gas compressors in our U.S. Onshore business. 2 For the year ended December 31, 2025, right-of-use assets obtained in exchange for finance lease liabilities primarily included $ 8.8 million related to computing equipment in the U.S. Note U – Subsequent Event On January 28, 2026, the Board of Directors of Murphy Oil Corporation (NYSE: MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $ 0.35 per share, which on an annualized basis would be $ 1.40 per share. The dividend is payable on March 2, 2026, to stockholders of record as of February 17, 2026. In January 2026, the Company completed a series of transactions regarding its long-term debt arrangements and RCF. In particular, the Company closed a public offering of $ 500.0 million aggregate principal amount of its 2034 Notes, used the proceeds to redeem an aggregate $ 227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $ 100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes. In addition, the Company entered into an amendment to its credit agreement which increased its RCF capacity from $ 1.35 billion to $ 2.0 billion and extended the term of the agreement to 2031. See Note F for additional information on these transactions. Subsequent to the balance sheet date, the Company announced oil discoveries at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and dry holes at the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire. A portion of the Civette-1X dry hole charge was recorded in 2025. The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026. See Note D for additional information . 110 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information concerning some of the schedules follows: SCHEDULE 1 – SUMMARY OF TOTAL PROVED EQUIVALENT RESERVES SCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL RESERVES SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES Reserves of oil and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgments are required to estimate reserves. Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year. The average prices used for 2025 were $ 65.34 per BBL for crude oil (WTI) and $ 3.39 per MCF for natural gas (Henry Hub). The average prices used for 2024 were $ 75.48 per BBL for crude oil (WTI) and $ 2.13 per MCF for natural gas (Henry Hub). The average prices used for 2023 were $ 78.22 per BBL for crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub). Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs) and commercially available technologies to establish “reasonable certainty” of economic producibility. Estimates are presented in millions of barrels of oil equivalents and dollars and billions of cubic feet rounded to one decimal. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available. Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of NGLs. All oil and natural gas reserves are from consolidated subsidiaries (including NCI) and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method. 111 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES GAAP requires calculation of future net cash flows using a 10 % annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. Schedule 7 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2025. 112 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2022 – 2025 Equivalents ( Millions of barrels of oil equivalent ) Total United States Canada Other Proved developed and undeveloped reserves: December 31, 2022 715.4 357.0 357.8 0.6 Revisions of previous estimates ( 13.3 ) ( 13.3 ) 0.2 ( 0.2 ) Improved recovery 0.4 — 0.4 — Extensions and discoveries 112.6 12.7 87.3 12.6 Sale of properties ( 5.2 ) — ( 5.2 ) — Production ( 70.4 ) ( 45.3 ) ( 25.0 ) ( 0.1 ) December 31, 2023 739.5 311.1 415.5 12.9 Revisions of previous estimates 14.3 8.1 6.3 ( 0.1 ) Improved recovery 11.3 11.3 — — Extensions and discoveries 31.4 16.0 15.4 — Production ( 67.5 ) ( 39.1 ) ( 28.3 ) ( 0.1 ) December 31, 2024 729.0 307.4 408.9 12.7 Revisions of previous estimates 26.0 18.0 7.1 0.9 Extensions and discoveries 43.0 4.9 38.1 — Purchases of properties 4.3 4.3 — — Sale of properties ( 3.4 ) ( 3.4 ) — — Production ( 68.9 ) ( 39.3 ) ( 29.5 ) ( 0.1 ) December 31, 2025 ¹ 730.0 291.9 424.6 13.5 Proved developed reserves: December 31, 2022 436.0 264.2 171.3 0.5 December 31, 2023 425.5 223.2 202.0 0.3 December 31, 2024 436.2 218.9 217.1 0.2 December 31, 2025 ² 418.9 197.8 220.9 0.2 Proved undeveloped reserves: December 31, 2022 279.4 92.8 186.5 0.1 December 31, 2023 314.0 87.9 213.5 12.6 December 31, 2024 292.8 88.5 191.8 12.5 December 31, 2025 ³ 311.1 94.1 203.7 13.3 1 Total and United States includes proved reserves of 15.0 MMBOE, consisting of 13.9 MMBBL of oil, 0.4 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 13.1 MMBOE, consisting of 12.1 MMBBL of oil, 0.4 MMBBL of NGLs and 3.9 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.9 MMBOE, consisting of 1.8 MMBBL of oil and 0.3 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 113 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2022 – 2025 (Continued) 2025 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices and higher gas prices that increased royalty rates and accelerated royalty incentive payouts in the Tupper Montney. Extensions and discoveries - In 2025, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale. Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions. 2024 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney. Improved Recovery – Proved equivalent reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney, the Eagle Ford Shale, and projects in the Gulf of America. 2023 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in the Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney. Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in the Tupper Montney, the Eagle Ford Shale, and Vietnam. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest, in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 114 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2022 – 2025 ( Millions of barrels ) Total United States Canada Other Proved developed and undeveloped crude oil reserves: December 31, 2022 303.6 263.6 39.5 0.5 Revisions of previous estimates ( 10.8 ) ( 8.9 ) ( 1.8 ) ( 0.1 ) Improved recovery 0.4 — 0.4 — Extensions and discoveries 22.5 8.9 1.5 12.1 Sale of properties ( 2.0 ) — ( 2.0 ) — Production ( 37.9 ) ( 35.6 ) ( 2.2 ) ( 0.1 ) December 31, 2023 275.8 228.0 35.4 12.4 Revisions of previous estimates 6.6 6.6 0.1 ( 0.1 ) Improved recovery 10.7 10.7 – — Extensions and discoveries 16.6 10.7 5.9 – Production ( 34.6 ) ( 30.8 ) ( 3.7 ) ( 0.1 ) December 31, 2024 275.1 225.2 37.7 12.2 Revisions of previous estimates 20.2 18.2 1.8 0.2 Extensions and discoveries 5.7 3.4 2.3 — Purchases of properties 3.5 3.5 – – Sales of properties ( 1.8 ) ( 1.8 ) — – Production ( 34.0 ) ( 30.3 ) ( 3.6 ) ( 0.1 ) December 31, 2025 ¹ 268.7 218.2 38.2 12.3 Proved developed crude oil reserves: December 31, 2022 209.0 194.4 14.2 0.4 December 31, 2023 186.3 163.7 22.3 0.3 December 31, 2024 184.7 164.1 20.4 0.2 December 31, 2025 ² 173.1 150.8 22.1 0.2 Proved undeveloped crude oil reserves: December 31, 2022 94.6 69.2 25.3 0.1 December 31, 2023 89.5 64.3 13.1 12.1 December 31, 2024 90.4 61.1 17.3 12.0 December 31, 2025 ³ 95.6 67.4 16.1 12.1 1 Total and United States includes proved reserves of 13.9 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 12.1 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.8 MMBBL attributable to the noncontrolling interest in MP GOM. 115 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2022 – 2025 (Continued) 2025 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The crude oil reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices. Extensions and discoveries - In 2025, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and in the Kaybob Duvernay in Canada. Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions. 2024 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The crude oil reserves revisions in 2024 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America. Improved Recovery – Proved oil reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and the Gulf of America. 2023 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The negative crude oil reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale and the Gulf of America. Extensions and discoveries - In 2023, proved oil reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale and Vietnam. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 116 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 3 – Summary of Proved Natural Gas Liquids Reserves Based on Average Prices for 2022 – 2025 ( Millions of barrels ) Total United States Canada Other Proved developed and undeveloped NGL reserves: December 31, 2022 41.7 37.6 4.1 — Revisions of previous estimates ( 1.4 ) ( 1.2 ) ( 0.2 ) — Extensions and discoveries 2.0 1.7 0.3 — Sale of properties ( 0.6 ) — ( 0.6 ) — Production ( 4.1 ) ( 3.8 ) ( 0.3 ) — December 31, 2023 37.6 34.3 3.3 — Revisions of previous estimates 1.2 0.3 0.9 — Improved recovery 0.4 0.4 — — Extensions and discoveries 2.9 2.4 0.5 — Production ( 3.5 ) ( 3.3 ) ( 0.2 ) — December 31, 2024 38.6 34.1 4.5 — Revisions of previous estimates 1.4 1.2 0.2 — Extensions and discoveries 1.1 0.7 0.4 — Purchases of properties 0.4 0.4 – — Sale of properties ( 0.8 ) ( 0.8 ) — — Production ( 4.0 ) ( 3.8 ) ( 0.2 ) — December 31, 2025 ¹ 36.7 31.8 4.9 — Proved developed NGL reserves: December 31, 2022 29.7 27.4 2.3 — December 31, 2023 25.9 24.1 1.8 — December 31, 2024 24.1 21.9 2.2 — December 31, 2025 ² 21.7 19.2 2.5 — Proved undeveloped NGL reserves: December 31, 2022 12.0 10.2 1.8 — December 31, 2023 11.7 10.2 1.5 — December 31, 2024 14.5 12.2 2.3 — December 31, 2025 15.0 12.6 2.4 — 1 Total and United States includes total proved reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM. 117 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 3 – Summary of Proved Natural Gas Liquids Reserves Based on Average Prices for 2022 – 2025 (Continued) 2025 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The NGL reserves revisions in 2025 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America, partially offset by lower commodity prices in the United States. Extensions and discoveries - In 2025, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale. Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions. 2024 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The NGL reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney. Improved Recovery – Proved NGL reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale. 2023 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The negative NGL reserves revisions in 2023 resulted predominantly from impacts of lower commodity prices in the U.S. and performance adjustments in the Eagle Ford Shale. These revisions were partially offset by improvements in the Gulf of America. Extensions and discoveries - In 2023, proved NGL reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 118 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2022 – 2025 ( Billions of cubic feet ) Total United States Canada Other Proved developed and undeveloped natural gas reserves: December 31, 2022 2,219.9 334.9 1,884.8 0.2 Revisions of previous estimates ( 6.9 ) ( 19.0 ) 12.1 — Extensions and discoveries 528.9 12.3 513.8 2.8 Sale of properties ( 15.6 ) — ( 15.6 ) — Production ( 170.1 ) ( 35.1 ) ( 135.0 ) — December 31, 2023 2,556.2 293.1 2,260.1 3.0 Revisions of previous estimates 39.1 7.7 31.4 — Improved recovery 1.2 1.2 – — Extensions and discoveries 71.4 17.0 54.4 — Production ( 176.1 ) ( 30.1 ) ( 146.0 ) — December 31, 2024 2,491.8 288.9 2,199.9 3.0 Revisions of previous estimates 26.7 ( 8.7 ) 30.8 4.6 Extensions and discoveries 217.2 4.7 212.5 — Purchases of properties 2.4 2.4 — — Sale of properties ( 5.1 ) ( 5.1 ) — — Production ( 185.3 ) ( 31.0 ) ( 154.3 ) — December 31, 2025 1,2 2,547.7 251.2 2,288.9 7.6 Proved developed natural gas reserves: December 31, 2022 1,183.1 254.1 928.8 0.2 December 31, 2023 1,279.3 212.4 1,066.7 0.2 December 31, 2024 1,364.2 196.8 1,167.2 0.2 December 31, 2025 2,3 1,345.1 166.4 1,178.5 0.2 Proved undeveloped natural gas reserves: December 31, 2022 1,036.8 80.8 956.0 — December 31, 2023 1,276.9 80.7 1,193.4 2.8 December 31, 2024 1,127.6 92.1 1,032.7 2.8 December 31, 2025 4 1,202.6 84.8 1,110.4 7.4 1 Total and United States includes total proved reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM. 2 Includes proved natural gas reserves to be consumed in operations as fuel of 54.2 BCF, 35.1 BCF and 7.4 BCF for the U.S., Canada and Other, respectively, with 1.7 BCF attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved developed reserves of 3.9 BCF attributable to the noncontrolling interest in MP GOM. 4 Total and United States includes proved undeveloped reserves of 0.3 BCF attributable to the noncontrolling interest in MP GOM. 119 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2022 – 2025 (Continued) 2025 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The natural gas reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney, partially offset by negative revisions due to increased royalty rates and accelerated royalty incentive payouts resulting from higher commodity prices in the Tupper Montney and the effects of reduced oil price in the Eagle Ford Shale. Extensions and discoveries - In 2025, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale. Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions 2024 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The natural gas reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney. Improved Recovery – Proved natural gas reserves were added in 2024 for the non-operated St. Malo waterflood in the Gulf of America. Extensions and discoveries - In 2024, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale. 2023 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S. and performance adjustments in the Tupper Montney and the Eagle Ford Shale. These negative revisions were partially offset by positive revisions in the Gulf of America, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney. Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in the Tupper Montney. Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets. 120 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 5 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities ( Millions of dollars ) United States Canada Other Total Year ended December 31, 2025 Property acquisition costs Unproved $ 5.5 $ — $ — $ 5.5 Proved 23.6 — — 23.6 Total acquisition costs 29.1 — — 29.1 Exploration costs 71.6 0.3 144.3 216.2 Development costs 696.2 152.5 102.9 951.6 Total costs incurred 796.9 152.8 247.2 1,196.9 Charged to expense Dry hole expense ( 0.9 ) — 31.0 30.1 Geophysical and other costs 34.3 0.3 35.3 69.9 Total charged to expense 1 33.4 0.3 66.3 100.0 Property additions $ 763.5 $ 152.5 $ 180.9 $ 1,096.9 Year ended December 31, 2024 Property acquisition costs Unproved $ 7.8 $ 0.2 $ — $ 8.0 Proved — — — — Total acquisition costs 7.8 0.2 – 8.0 Exploration costs 85.3 0.4 60.2 145.9 Development costs 598.7 137.7 45.1 781.5 Total costs incurred 691.8 138.3 105.3 935.4 Charged to expense Dry hole expense 70.9 — 2.3 73.2 Geophysical and other costs 19.2 0.4 31.2 50.8 Total charged to expense 1 90.1 0.4 33.5 124.0 Property additions $ 601.7 $ 137.9 $ 71.8 $ 811.4 Year ended December 31, 2023 Property acquisition costs Unproved $ — $ — $ 8.5 $ 8.5 Proved 12.8 — 14.3 27.1 Total acquisition costs 12.8 — 22.8 35.6 Exploration costs 157.8 0.4 39.9 198.1 Development costs 667.2 206.2 7.4 880.8 Total costs incurred 837.8 206.6 70.1 1,114.5 Charged to expense Dry hole expense 153.1 — 16.7 169.8 Geophysical and other costs 13.4 0.4 40.3 54.1 Total charged to expense 1 166.5 0.4 57.0 223.9 Property additions $ 671.3 $ 206.2 $ 13.1 $ 890.6 1 Excludes undeveloped lease amortization for the years ended 2025, 2024 and 2023 of $ 11.7 million, $ 9.6 million and $ 10.9 million, respectively. 121 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 6 – Results of Operations for Oil and Gas Producing Activities 1 ( Millions of dollars ) United States Canada Other Total Year ended December 31, 2025 Revenues Crude oil and natural gas liquids sales $ 2,047.4 $ 254.4 $ 5.7 $ 2,307.5 Natural gas sales 106.5 275.8 — 382.3 Total oil and natural gas revenues 2,153.9 530.2 5.7 2,689.8 Other operating revenues 5.9 1.7 10.0 17.6 Total revenues 2,159.8 531.9 15.7 2,707.4 Costs and expenses Lease operating expenses 577.1 185.6 2.5 765.2 Severance and ad valorem taxes 37.7 1.5 — 39.2 Transportation, gathering and processing 107.0 92.7 — 199.7 Exploration costs charged to expense 33.5 0.3 66.2 100.0 Undeveloped lease amortization 7.5 0.1 4.1 11.7 Depreciation, depletion and amortization 822.1 144.8 2.5 969.4 Accretion of asset retirement obligations 46.6 10.3 0.7 57.6 Impairment of assets 115.0 — — 115.0 Selling and general expenses 13.7 23.7 8.8 46.2 Other expenses (benefits) 13.4 3.5 ( 0.4 ) 16.5 Total costs and expenses 1,773.6 462.5 84.4 2,320.5 Results of operations before taxes 386.2 69.4 ( 68.7 ) 386.9 Income tax expense (benefit) 77.7 14.6 ( 2.1 ) 90.2 Results of operations $ 308.5 $ 54.8 $ ( 66.6 ) $ 296.7 Year ended December 31, 2024 Revenues Crude oil and natural gas liquids sales $ 2,436.0 $ 272.3 $ 6.6 $ 2,714.9 Natural gas sales 67.8 232.2 — 300.0 Sales of purchased natural gas — 3.7 — 3.7 Total oil and natural gas revenues 2,503.8 508.2 6.6 3,018.6 Other operating revenues 4.5 1.5 — 6.0 Total revenues 2,508.3 509.7 6.6 3,024.5 Costs and expenses Lease operating expenses 749.9 185.5 1.6 937.0 Severance and ad valorem taxes 37.8 1.4 — 39.2 Transportation, gathering and processing 130.9 79.9 — 210.8 Costs of purchased natural gas — 3.1 — 3.1 Exploration costs charged to expense 90.0 0.4 33.5 123.9 Undeveloped lease amortization 6.2 0.1 3.3 9.6 Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 Impairment of assets 62.9 — — 62.9 Selling and general expenses ( 3.3 ) 20.4 6.7 23.8 Other expenses (benefits) ( 5.6 ) 3.3 2.6 0.3 Total costs and expenses 1,821.1 448.7 50.1 2,319.9 Results of operations before taxes 687.2 61.0 ( 43.5 ) 704.6 Income tax expense (benefit) 125.3 12.0 ( 31.0 ) 106.3 Results of operations $ 561.9 $ 49.0 $ ( 12.5 ) $ 598.4 1 Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM. 122 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 6 – Results of Operations for Oil and Gas Producing Activities 1 (Continued) ( Millions of dollars ) United States Canada Other Total Year ended December 31, 2023 Revenues Crude oil and natural gas liquids sales $ 2,829.1 $ 165.7 $ 11.0 $ 3,005.8 Natural gas sales 92.7 278.2 — 370.9 Sales of purchased natural gas — 72.2 — 72.2 Total oil and natural gas revenues 2,921.8 516.1 11.0 3,448.9 Other operating revenues 6.5 1.4 — 7.9 Total revenues 2,928.3 517.5 11.0 3,456.8 Costs and expenses Lease operating expenses 630.7 151.8 1.9 784.4 Severance and ad valorem taxes 41.4 1.4 — 42.8 Transportation, gathering and processing 157.0 76.0 — 233.0 Costs of purchased natural gas — 51.7 — 51.7 Exploration costs charged to expense 166.5 0.4 57.0 223.9 Undeveloped lease amortization 8.1 0.1 2.7 10.9 Depreciation, depletion and amortization 706.0 142.2 2.3 850.5 Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 Selling and general expenses 11.8 16.5 9.4 37.7 Other expenses 31.2 16.8 8.9 56.9 Total costs and expenses 1,790.5 464.7 82.6 2,337.8 Results of operations before taxes 1,137.8 52.8 ( 71.6 ) 1,119.0 Income tax expense (benefit) 232.7 11.2 ( 6.1 ) 237.8 Results of operations $ 905.1 $ 41.6 $ ( 65.5 ) $ 881.2 1 Results exclude corporate overhead, interest and discontinued operations. Results include amounts attributable to the noncontrolling interest in MP GOM. 123 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 1 ( Millions of dollars ) United States Canada Other Total December 31, 2025 Future cash inflows $ 15,502.7 $ 6,850.9 $ 873.7 $ 23,227.3 Future development costs ( 1,969.6 ) ( 812.6 ) ( 204.0 ) ( 2,986.2 ) Future production costs ( 6,707.7 ) ( 4,240.9 ) ( 343.4 ) ( 11,292.0 ) Future income taxes ( 602.4 ) ( 342.8 ) ( 176.2 ) ( 1,121.4 ) Future net cash flows 6,223.0 1,454.6 150.1 7,827.7 10% annual discount for estimated timing of cash flows ( 2,459.4 ) ( 625.4 ) ( 118.7 ) ( 3,203.5 ) Standardized measure of discounted future net cash flows $ 3,763.6 $ 829.2 $ 31.4 $ 4,624.2 December 31, 2024 Future cash inflows $ 18,118.1 $ 6,304.4 $ 1,012.9 $ 25,435.4 Future development costs ( 2,024.9 ) ( 825.9 ) ( 252.5 ) ( 3,103.3 ) Future production costs ( 7,645.7 ) ( 4,026.5 ) ( 341.7 ) ( 12,013.9 ) Future income taxes ( 893.5 ) ( 251.2 ) ( 203.4 ) ( 1,348.1 ) Future net cash flows 7,554.0 1,200.8 215.3 8,970.1 10% annual discount for estimated timing of cash flows ( 2,887.3 ) ( 486.0 ) ( 200.9 ) ( 3,574.2 ) Standardized measure of discounted future net cash flows $ 4,666.7 $ 714.8 $ 14.4 $ 5,395.9 December 31, 2023 Future cash inflows $ 18,927.6 $ 8,012.7 $ 1,004.2 $ 27,944.5 Future development costs ( 1,685.3 ) ( 769.6 ) ( 304.3 ) ( 2,759.2 ) Future production costs ( 7,856.2 ) ( 4,223.6 ) ( 288.7 ) ( 12,368.5 ) Future income taxes ( 1,057.5 ) ( 634.6 ) ( 121.3 ) ( 1,813.4 ) Future net cash flows 8,328.6 2,384.9 289.9 11,003.4 10% annual discount for estimated timing of cash flows ( 2,840.6 ) ( 1,056.9 ) ( 252.5 ) ( 4,150.0 ) Standardized measure of discounted future net cash flows $ 5,488.0 $ 1,328.0 $ 37.4 $ 6,853.4 1 Includes amounts attributable to the noncontrolling interest in MP GOM. 124 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 1 (Continued) The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. ( Millions of dollars ) 2025 2024 2023 Net changes in prices and production costs 2 $ ( 1,126.6 ) $ ( 1,116.5 ) $ ( 5,845.6 ) Net changes in development costs 46.4 ( 152.7 ) ( 78.8 ) Sales and transfers of oil and natural gas produced, net of production costs ( 1,685.7 ) ( 1,824.8 ) ( 2,264.8 ) Net change due to extensions and discoveries 122.0 583.7 770.4 Net change due to purchases and sales of proved reserves 62.6 — ( 96.1 ) Development costs incurred 686.2 668.6 703.7 Accretion of discount 598.3 773.5 1,393.3 Revisions of previous quantity estimates 403.9 ( 688.1 ) ( 771.5 ) Net change in income taxes 121.2 298.8 1,229.6 Net (decrease) increase ( 771.7 ) ( 1,457.5 ) ( 4,959.8 ) Standardized measure at January 1 5,395.9 6,853.4 11,813.2 Standardized measure at December 31 $ 4,624.2 $ 5,395.9 $ 6,853.4 1 Includes amounts attributable to the noncontrolling interest in MP GOM. 2 The average prices used for crude oil (WTI) were $ 65.34 /BBL in 2025, $ 75.48 /BBL in 2024 and $ 78.22 /BBL in 2023. The average prices used for natural gas (Henry Hub) were $ 3.39 /MCF in 2025, $ 2.13 /MCF in 2024 and $ 2.64 /MCF in 2023. 125 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued Schedule 8 – Capitalized Costs Relating to Oil and Gas Producing Activities ( Millions of dollars ) United States Canada Other Total December 31, 2025 Unproved oil and natural gas properties 1 $ 207.0 $ 6.4 $ 16.3 $ 229.7 Proved oil and natural gas properties 17,417.6 4,865.4 439.1 22,722.1 Gross capitalized costs 17,624.6 4,871.8 455.4 22,951.8 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties ( 118.5 ) — ( 11.5 ) ( 130.0 ) Proved oil and natural gas properties ( 11,275.7 ) ( 3,412.0 ) ( 47.0 ) ( 14,734.7 ) Net capitalized costs $ 6,230.4 $ 1,459.8 $ 396.9 $ 8,087.1 December 31, 2024 Unproved oil and natural gas properties 1 $ 247.3 $ 6.6 $ 29.1 $ 283.0 Proved oil and natural gas properties 16,598.8 4,498.1 246.7 21,343.6 Gross capitalized costs 16,846.1 4,504.7 275.8 21,626.6 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties ( 111.0 ) — ( 20.7 ) ( 131.7 ) Proved oil and natural gas properties ( 10,326.2 ) ( 3,116.2 ) ( 44.2 ) ( 13,486.6 ) Net capitalized costs $ 6,408.9 $ 1,388.5 $ 210.9 $ 8,008.3 1 Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells and exploratory wells capitalized pending further evaluation. 126 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year Year ended December 31, 2025 Revenue from contracts with customers 1 $ 672.7 $ 683.0 $ 721.0 $ 613.1 $ 2,689.8 Income (loss) from continuing operations before income taxes 1 122.8 34.9 ( 3.7 ) 28.9 182.9 Income (loss) from continuing operations 1 90.0 33.8 ( 7.8 ) 22.3 138.3 Net income (loss) including noncontrolling interest 89.4 35.1 ( 8.3 ) 22.6 138.8 Net income (loss) attributable to Murphy 73.0 22.3 ( 3.0 ) 11.9 104.2 Income (loss) from continuing operations per common share ² Basic 0.51 0.15 ( 0.02 ) 0.08 0.73 Diluted 0.50 0.15 ( 0.02 ) 0.08 0.72 Net income (loss) per common share ² Basic 0.51 0.16 ( 0.02 ) 0.08 0.73 Diluted 0.50 0.16 ( 0.02 ) 0.08 0.72 Cash dividend per common share 0.325 0.325 0.325 0.325 1.300 Year ended December 31, 2024 Revenue from contracts with customers 1 $ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6 Income from continuing operations before income taxes 1 145.6 189.6 153.8 78.6 567.6 Income from continuing operations 1 115.5 156.9 151.7 65.2 489.3 Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5 Net income attributable to Murphy 90.0 127.7 139.1 50.3 407.1 Income from continuing operations per common share ² Basic 0.60 0.84 0.93 0.35 2.73 Diluted 0.60 0.83 0.93 0.34 2.72 Net income per common share ² Basic 0.59 0.84 0.93 0.35 2.71 Diluted 0.59 0.83 0.93 0.34 2.70 Cash dividend per common share 0.300 0.300 0.300 0.300 1.200 1 “Revenue from contracts with customers”, “Income (loss) from continuing operations before income taxes”, “Income (loss) from continuing operations” and “Net income (loss) including noncontrolling interest” includes results attributable to the noncontrolling interest in MP GOM. 2 The sum of quarterly income (loss) from continuing operations per share and net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding. 127 Table of Contents DEFINITIONS Currencies: CAD or C$ - Canadian dollar USD or US$ - United States dollar Units of Measure: BBL - Barrels BCF - Billion cubic feet BOEPD - Barrels of oil equivalent per day MCF - Thousand cubic feet MMBBL - Million barrels MMBOE - Million barrels of oil equivalent MMBTU - Million British thermal units MMCF - Million cubic feet Industry: AECO - Alberta Energy Company and is the Canadian benchmark price for natural gas Crude oil - Collectively, crude oil and condensate hydrocarbons Crude oil, natural gas and natural gas liquids - Collectively, oil and natural gas Development well - A well that is drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive Dry hole - An exploratory well that does not find oil or natural gas in commercial quantities E&P - Exploration and production Exploratory well - A well drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area FPSO - Floating production, storage and offloading vessel Hydrocarbons - Organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products Liquids - Collectively, crude oil, condensate and natural gas liquid hydrocarbons Net acres or net wells - The portions of gross acres or gross wells owned by the Company NGLs - Natural gas liquids NYMEX - New York Mercantile Exchange OPEC - Organization of the Petroleum Exporting Countries Operator - The company serving as the manager and often the decision-maker of a drilling or production project Production Sharing Contract (PSC) - Agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recovered QRE - Qualified reserve estimator Seismic - Two-dimensional or three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons Working interest - Right to drill and produce oil and natural gas on the leased acreage, as well as the obligation to pay costs WTI - West Texas Intermediate Abbreviations: AIP - Annual Incentive Plan ARO - Asset retirement obligation ASC - Accounting Standards Codification ASU - Accounting Standards Update BOEM - U.S. Bureau of Ocean Energy Management 128 Table of Contents DEFINITIONS - Continued BSEE - U.S. Bureau of Safety and Environmental Enforcement CERCLA - U.S. Comprehensive Environmental Response, Compensation and Liability Act CODM - Chief operating decision maker CRSU - Cash-settled restricted time-based stock unit DD&A - Depreciation, depletion and amortization EBITDA - Earnings before interest, taxes, depreciation and amortization EBITDAX - Earnings before interest, taxes, depreciation and amortization, and exploration expenses EPA - U.S. Environmental Protection Agency ESG - Environmental, social and governance FASB - Financial Accounting Standards Board FCF - Free cash flow GAAP - U.S. generally accepted accounting principles GHG - Greenhouse gas GHGRP - Greenhouse Gas Reporting Program IRA - Inflation Reduction Act MP GOM - MP Gulf of Mexico, LLC NCI - Noncontrolling interest NED - Non-employee director OBBBA - One Big Beautiful Bill Act OPA - U.S. Oil Pollution Act OT - Operational technology PCAOB - Public Company Accounting Oversight Board PSU - Performance-based restricted stock unit RCF - Senior unsecured guaranteed revolving credit facility ROACE - Return on average capital employed RSU - Time-based restricted stock unit SAR - Stock appreciation right SEC - U.S. Securities and Exchange Commission SOFR - Secured Overnight Financing Rate TCFD - Task Force on Climate-related Financial Disclosures WEC - Waste emission charge 129