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, 2024, 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, 2024. 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, 2024 and their report is included on page 65 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 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 54 Table of Contents PART II Item 9B. OTHER INFORMATION During the three months ended December 31, 2024, 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. 55 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 28 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 14, 2025 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 Fwy, 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 14, 2025 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, 2024, 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 14, 2025 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 14, 2025 under the caption “Election of Directors”. Item 14. PRINCIPAL ACCOUNTING 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 14, 2025 under the caption “Audit Committee Report”. 56 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 62 Report of Management – Internal Control Over Financial Reporting 62 Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (KPMG LLP , Houston, TX, Auditor Firm ID: 185 ) 63 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting (KPMG LLP, Houston, TX, Auditor Firm ID: 185) 65 Consolidated Balance Sheets 66 Consolidated Statements of Operations 67 Consolidated Statements of Comprehensive Income (Loss) 68 Consolidated Statements of Cash Flows 69 Consolidated Statements of Stockholders’ Equity 70 Notes to Consolidated Financial Statements 71 Note A – Significant Accounting Policies 71 Note B – New Accounting Principles and Recent Accounting Pronouncements 74 Note C – Revenue from Contracts with Customers 75 Note D – Property, Plant and Equipment 77 Note E – Inventories 79 Note F – Financing Arrangements and Debt 80 Note G – Asset Retirement Obligations 81 Note H – Income Taxes 82 Note I – Incentive Plans 84 Note J – Employee and Retiree Benefit Plans 87 Note K – Financial Instruments and Risk Management 93 Note L – Net Income (Loss) Per Common Share 94 Note M – Other Financial Information 95 Note N – Accumulated Other Comprehensive Loss 95 Note O – Assets and Liabilities Measured at Fair Value 96 Note P – Commitments 97 Note Q – Environmental and Other Contingencies 98 Note R – Common Stock Issued and Outstanding 99 Note S – Business Segments 100 Note T – Leases 104 Note U – Subsequent Event 105 Supplemental Oil and Gas Information (unaudited) 106 Supplemental Quarterly Information (unaudited) 122 57 Table of Contents PART IV 2. Financial Statement Schedules Schedule II – Valuation Accounts and Reserves 123 All other 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, 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 Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee Exhibit 4.2 to Form 10-K filed March 16, 2005 4.2 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 4.3 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 4.4 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 4.5 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 4.6 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 4.7 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 4.8 S eventh Sup plemental Indenture date d as of October 3, 2024 ,between Murphy Oil Corporation and R egions Bank, as trustee, rela t ing to 6.000% Note s due 2032 Exhibit 4.2 to Form 8-K filed October 3, 2024 10.1 Murphy Oil Corporation Annual Incentive Plan Exhibit 10.3 to Form 10-K filed February 25, 2022 10.2 Murphy Oil Corporation 2018 Long-Term Incentive Plan Exhibit B to definitive proxy statement filed March 23, 2018 10.3 Amendment to the Murphy Oil Corporation 2018 Long-Term Incentive Plan Exhibit 10.15 to Form 10-K filed February 27, 2020 58 Table of Contents PART IV 10.4 Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Incentive Plan) Exhibit 10.14 to Form 10-K filed February 27, 2019 10.5 Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Incentive Plan) Exhibit 10.17 to Form 10-K filed February 27, 2020 10.6 Form of employee time-based restricted stock unit – stock settled 3-year grant agreement (2018 Long-Term Incentive Plan) Exhibit 10.15 to Form 10-K filed February 27, 2019 10.7 Form of employee time-based restricted stock unit – stock settled 5-year grant agreement (2018 Long-Term Incentive Plan) Exhibit 10.16 to Form 10-K filed February 27, 2019 10.8 Murphy Oil Corporation 2020 Long-Term Incentive Plan Exhibit A to definitive proxy statement filed March 30, 2020 10.9 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 10.10 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 10.11 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 10.12 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 10.13 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 10.14 Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 23, 2018 10.15 First Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.1 to Form 8-K filed April 25, 2018 10.16 Second Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.24 to Form 10-K filed February 27, 2020 10.17 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 10.18 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 10.19 Murphy Oil Corporation 2021 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 26, 2021 10.20 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 10.21 Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors Exhibit 10.6 to Form 10-K filed February 26, 2016 10.22 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 10.23 Form of employee performance-based restricted stock unit (2020 LTI Plan) Exhibit 10.30 to Form 10-K filed February 23, 2024 10.24 Form of employee time-based restricted stock unit – A (2020 LTI Plan) Exhibit 10.31 to Form 10-K filed February 23, 2024 10.25 Form of employee time-based restricted stock unit – B (2020 LTI Plan) Exhibit 10.32 to Form 10-K filed February 23, 2024 10.26 Form of employee time-based restricted stock unit – C (2020 LTI Plan) Exhibit 10.33 to Form 10-K filed February 23, 2024 10.27 Form of employee time-based restricted stock unit – D (2020 LTI Plan) Exhibit 10.34 to Form 10-K filed February 23, 2024 10.28 Form of non-employee director elective restricted stock unit (2021 NED Plan) Exhibit 10.35 to Form 10-Q filed May 2, 2024 10.29 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 59 Table of Contents PART IV 10.30 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 10.31 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 *10.32 Form of Severance Protection Agreement *10.33 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 *19.1 Murphy Oil Corporation Insider Trading Policy *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 Ne therland , S ewell & Associates , Inc. *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 independ ent reserves audit report for MP GOM JV *99.2 McDaniel independent reserves audit report for Canada Onshore proved crude oil and natural gas reserves *99.3 Netherland, Sewell & Associates, Inc. independent reserves audit report U.S. Gulf of Mexico 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) Item 16. FORM 10-K SUMMARY None. 60 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 27, 2025 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 27, 2025 by the following persons on behalf of the registrant and in the capacities indicated. /s/ CLAIBORNE P. DEMING /s/ JAMES V. KELLEY Claiborne P. Deming, Chairman and Director James V. Kelley, Director /s/ ERIC M. HAMBLY /s/ R. MADISON MURPHY Eric M. Hambly, President and Chief Executive Officer and Director (Principal Executive Officer) R. Madison Murphy, Director /s/ LAWRENCE R. DICKERSON /s/ JEFFREY W. NOLAN Lawrence R. Dickerson, Director Jeffrey W. Nolan, Director /s/ MICHELLE A. EARLEY /s/ ROBERT N. RYAN, JR. Michelle A. Earley, Director Robert N. Ryan, Jr., Director /s/ ELISABETH W. KELLER /s/ LAURA A. SUGG Elisabeth W. Keller, Director Laura A. Sugg, Director /s/ ROBERT B. TUDOR, III /s/ THOMAS J. MIRELES Robert B. Tudor, III, Director Thomas J. Mireles, Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ PAUL D. VAUGHAN Paul D. Vaughan Vice President and Controller (Principal Accounting Officer) 61 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 63 . 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, 2024. KPMG LLP has performed an audit of the Company’s internal control over financial reporting, and their opinion thereon can be found on page 65 . 62 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, 2024 and 2023, 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, 2024, and the related notes and financial statement schedule II (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, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2024, 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, 2024, 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 27, 2025 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 63 Table of Contents independent assessment. For the year ended December 31, 2024, the Company recorded depreciation, depletion, and amortization expense of $865.8 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 and comparing the development projects with the available development plans. We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices and recalculated the relevant market differentials. 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 27, 2025 64 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, 2024, 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, 2024, 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, 2024 and 2023, 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, 2024, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 27, 2025 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 27, 2025 65 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31 (Thousands of dollars except share amounts) 2024 2023 ASSETS Current assets Cash and cash equivalents $ 423,569 $ 317,074 Accounts receivable, net 272,530 343,992 Inventories Note E 54,858 54,454 Prepaid expenses 34,322 36,674 Total current assets 785,279 752,194 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ 13,811,539 in 2024 and $ 13,135,385 in 2023 Note D 8,054,653 8,225,197 Operating lease assets Note T 777,536 745,185 Deferred income taxes Note H — 435 Deferred charges and other assets 50,011 43,686 Total assets $ 9,667,479 $ 9,766,697 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease Note F $ 871 $ 723 Accounts payable 472,165 446,891 Income taxes payable 19,003 21,007 Other taxes payable 31,685 29,339 Operating lease liabilities Note T 253,208 207,840 Other accrued liabilities 117,802 130,033 Current asset retirement obligations 1 Note G 48,080 10,712 Total current liabilities 942,814 846,545 Long-term debt, including finance lease obligation Note F 1,274,502 1,328,352 Asset retirement obligations Note G 960,804 904,051 Deferred credits and other liabilities 274,345 309,605 Non-current operating lease liabilities Note T 537,381 551,845 Deferred income taxes Note H 335,790 276,646 Total liabilities $ 4,325,636 $ 4,217,044 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 in 2024 and 195,100,628 shares in 2023 195,101 195,101 Capital in excess of par value 848,950 880,297 Retained earnings 6,773,289 6,546,079 Accumulated other comprehensive loss Note N ( 628,072 ) ( 521,117 ) Treasury stock ( 1,995,018 ) ( 1,737,566 ) Murphy Shareholders' Equity 5,194,250 5,362,794 Noncontrolling interest 147,593 186,859 Total equity 5,341,843 5,549,653 Total liabilities and equity $ 9,667,479 $ 9,766,697 1 The prior-period amount has been reclassified to conform to the current period presentation. The accompanying notes are an integral part of these consolidated financial statements. 66 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31 (Thousands of dollars except per share amounts) 2024 2023 2022 Revenues and other income Revenue from production $ 3,014,856 $ 3,376,639 $ 4,038,451 Sales of purchased natural gas 3,742 72,215 181,689 Total revenue from sales to customers 3,018,598 3,448,854 4,220,140 (Loss) on derivative instruments ( 1,707 ) — ( 320,410 ) Gain on sale of assets and other operating income 11,583 11,293 32,932 Total revenues and other income 3,028,474 3,460,147 3,932,662 Costs and expenses Lease operating expenses 936,960 784,391 679,342 Severance and ad valorem taxes 39,162 42,787 57,012 Transportation, gathering and processing 210,827 232,985 212,711 Costs of purchased natural gas 3,147 51,682 171,991 Exploration expenses, including undeveloped lease amortization 133,538 234,776 133,197 Selling and general expenses 110,085 117,306 131,121 Depreciation, depletion and amortization 865,753 861,602 776,817 Accretion of asset retirement obligations 52,511 46,059 46,243 Impairment of assets 62,909 — — Other operating expense 10,989 46,530 137,518 Total costs and expenses 2,425,881 2,418,118 2,345,952 Operating income from continuing operations 602,593 1,042,029 1,586,710 Other income (loss) Other income (loss) 70,902 ( 8,587 ) 14,310 Interest expense, net ( 105,926 ) ( 112,373 ) ( 150,759 ) Total other loss ( 35,024 ) ( 120,960 ) ( 136,449 ) Income from continuing operations before income taxes 567,569 921,069 1,450,261 Income tax expense 78,272 195,921 309,464 Income from continuing operations 489,297 725,148 1,140,797 Loss from discontinued operations, net of income taxes ( 2,812 ) ( 1,467 ) ( 2,078 ) Net income including noncontrolling interest 486,485 723,681 1,138,719 Less: Net income attributable to noncontrolling interest 79,314 62,122 173,672 NET INCOME ATTRIBUTABLE TO MURPHY $ 407,171 $ 661,559 $ 965,047 NET INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ 2.73 $ 4.27 $ 6.23 Discontinued operations ( 0.02 ) ( 0.01 ) ( 0.01 ) Net income $ 2.71 $ 4.26 $ 6.22 NET INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 2.72 $ 4.23 $ 6.14 Discontinued operations ( 0.02 ) ( 0.01 ) ( 0.01 ) Net income $ 2.70 $ 4.22 $ 6.13 Cash dividends per common share $ 1.200 $ 1.100 $ 0.825 Average common shares outstanding (thousands) Basic 150,011 155,234 155,277 Diluted 151,027 156,646 157,475 The accompanying notes are an integral part of these consolidated financial statements. 67 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Years Ended December 31 (Thousands of dollars) 2024 2023 2022 Net income including noncontrolling interest $ 486,485 $ 723,681 $ 1,138,719 Other comprehensive income (loss), net of tax Net (loss) gain from foreign currency translation ( 134,692 ) 36,598 ( 106,335 ) Retirement and postretirement benefit plans 27,737 ( 23,029 ) 99,360 Other comprehensive income (loss) ( 106,955 ) 13,569 ( 6,975 ) Comprehensive income including noncontrolling interest 379,530 737,250 1,131,744 Less: Comprehensive income attributable to noncontrolling interest 79,314 62,122 173,672 COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ 300,216 $ 675,128 $ 958,072 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 CASH FLOWS Years Ended December 31 (Thousands of dollars) 2024 2023 2022 Operating Activities Net income including noncontrolling interest $ 486,485 $ 723,681 $ 1,138,719 Adjustments to reconcile net income to net cash provided by continuing operations activities Depreciation, depletion and amortization 865,753 861,602 776,817 Unsuccessful exploration well costs and previously suspended exploration costs 73,201 169,795 82,085 Deferred income tax expense 72,434 179,823 286,079 Impairment of assets 62,909 — — Accretion of asset retirement obligations 52,511 46,059 46,243 Long-term non-cash compensation 45,057 61,953 89,246 Amortization of undeveloped leases 9,587 10,925 13,300 Loss from discontinued operations 2,812 1,467 2,078 Mark-to-market loss (gain) on derivative instruments 1,707 — ( 214,788 ) Contingent consideration payment — ( 139,574 ) — Mark-to-market loss on contingent consideration — 7,113 78,285 Gain from sale of assets — — ( 17,899 ) Other operating activities, net ( 18,349 ) ( 74,728 ) ( 34,193 ) Net decrease (increase) in non-cash working capital 74,883 ( 99,361 ) ( 65,728 ) Net cash provided by continuing operations activities 1,728,990 1,748,755 2,180,244 Investing Activities Property additions and dry hole costs ( 908,164 ) ( 1,066,015 ) ( 985,461 ) Acquisition of oil and natural gas properties — ( 35,578 ) ( 128,538 ) Proceeds from sales of property, plant and equipment — 102,913 4,528 Net cash required by investing activities ( 908,164 ) ( 998,680 ) ( 1,109,471 ) Financing Activities Retirement of debt ( 650,112 ) ( 498,175 ) ( 647,707 ) Early redemption of debt cost ( 15,700 ) — ( 8,295 ) Debt issuance 600,000 — — Debt issuance cost ( 10,145 ) — — Borrowings on revolving credit facility 350,000 600,000 400,000 Repayment of revolving credit facility ( 350,000 ) ( 600,000 ) ( 400,000 ) Issue costs of revolving credit facility ( 14,718 ) ( 20 ) ( 14,353 ) Repurchase of common stock ( 301,350 ) ( 150,022 ) — Cash dividends paid ( 179,961 ) ( 170,978 ) ( 128,219 ) Distributions to noncontrolling interest ( 118,580 ) ( 29,382 ) ( 183,038 ) Withholding tax on stock-based incentive awards ( 25,310 ) ( 14,276 ) ( 17,631 ) Finance lease obligation payments ( 665 ) ( 622 ) ( 636 ) Contingent consideration payment — ( 60,243 ) ( 81,742 ) Net cash required by financing activities ( 716,541 ) ( 923,718 ) ( 1,081,621 ) Net cash required by discontinued operations — — ( 14,500 ) Effect of exchange rate changes on cash and cash equivalents 2,210 ( 1,246 ) ( 3,873 ) Net increase (decrease) in cash and cash equivalents 106,495 ( 174,889 ) ( 29,221 ) Cash and cash equivalents at beginning of period 317,074 491,963 521,184 Cash and cash equivalents at end of period $ 423,569 $ 317,074 $ 491,963 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 STOCKHOLDERS’ EQUITY Years Ended December 31 (Thousands of dollars except number of shares) 2024 2023 2022 Common Stock Balance at beginning and end of year - par $ 1.00 , authorized 450,000,000 shares at December 31, 2024, 2023 and 2022, issued 195,100,628 shares at December 31, 2024, 2023 and 2022 195,101 195,101 195,101 Capital in Excess of Par Value Balance at beginning of year 880,297 893,578 926,698 Restricted stock transactions and other 1 ( 70,539 ) ( 42,667 ) ( 58,362 ) Share-based compensation 39,192 29,386 25,242 Balance at end of year 848,950 880,297 893,578 Retained Earnings Balance at beginning of year 6,546,079 6,055,498 5,218,670 Net income attributable to Murphy 407,171 661,559 965,047 Cash dividends paid ( 179,961 ) ( 170,978 ) ( 128,219 ) Balance at end of year 6,773,289 6,546,079 6,055,498 Accumulated Other Comprehensive Loss Balance at beginning of year ( 521,117 ) ( 534,686 ) ( 527,711 ) Foreign currency translation (loss) gain, net of income taxes ( 134,692 ) 36,598 ( 106,335 ) Retirement and postretirement benefit plans, net of income taxes 27,737 ( 23,029 ) 99,360 Balance at end of year ( 628,072 ) ( 521,117 ) ( 534,686 ) Treasury Stock Balance at beginning of year ( 1,737,566 ) ( 1,614,717 ) ( 1,655,447 ) Repurchase of common stock ( 302,681 ) ( 151,241 ) — Awarded restricted stock, net of forfeitures 45,229 28,392 40,730 Balance at end of year – 49,255,504 shares of common stock in 2024, 42,351,986 shares of common stock in 2023 and 39,633,309 shares of common stock in 2022 ( 1,995,018 ) ( 1,737,566 ) ( 1,614,717 ) Murphy Shareholders’ Equity 5,194,250 5,362,794 4,994,774 Noncontrolling Interest Balance at beginning of year 186,859 154,119 163,485 Net income attributable to noncontrolling interest 79,314 62,122 173,672 Distributions to noncontrolling interest owners ( 118,580 ) ( 29,382 ) ( 183,038 ) Balance at end of year 147,593 186,859 154,119 Total Equity $ 5,341,843 $ 5,549,653 $ 5,148,893 1 Prior-period amounts have been aggregated to conform to the current period presentation. The accompanying notes are an integral part of these consolidated financial statements. 70 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 71 - 105 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 crude oil, natural gas and NGLs 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, 2024 and 2023, 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, 2024 and 2023, 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. 71 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. Interest is capitalized on significant development projects that are expected to take one year or more to complete. 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 criteria laid out by 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 72 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” 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 Statement 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 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 Company’s 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. Sale and purchase contracts in the normal course of business are not designated as hedges for accounting purposes. 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 “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 73 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Continued) 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 Statement 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 Reportable Segment Disclosures. In November 2023, the FASB issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. The Company adopted this standard in the fourth quarter of 2024. The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note S . 74 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) 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 expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. Income Tax Disclosures. In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. 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. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. Note C – Revenue from Contracts with Customers Nature of Goods and Services The Company explores for and produces crude oil, natural gas and NGLs (collectively referred to as 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. 75 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) 2024 2023 2022 Net crude oil and condensate revenue United States - Onshore $ 586,584 $ 676,139 $ 856,219 United States - Offshore 1 1,777,723 2,072,353 2,229,658 Canada - Onshore 70,855 78,088 131,400 Canada - Offshore 193,961 78,650 117,747 Other 6,537 11,022 22,824 Total crude oil and condensate revenue 2,635,660 2,916,252 3,357,848 Net natural gas liquids revenue United States - Onshore 32,853 33,178 64,015 United States - Offshore 1 38,858 47,434 60,424 Canada - Onshore 7,454 8,914 18,338 Total natural gas liquids revenue 79,165 89,526 142,777 Net natural gas revenue United States - Onshore 17,443 21,346 64,037 United States - Offshore 1 50,329 71,332 161,160 Canada - Onshore 232,259 278,183 312,629 Total natural gas revenue 300,031 370,861 537,826 Revenue from production 3,014,856 3,376,639 4,038,451 Sales of purchased natural gas 2 United States - Offshore — — 204 Canada - Onshore 3,742 72,215 181,485 Total sales of purchased natural gas 3,742 72,215 181,689 Total revenue from sales to customers 3,018,598 3,448,854 4,220,140 (Loss) on derivative instruments ( 1,707 ) — ( 320,410 ) Gain on sale of assets and other operating income 11,583 11,293 32,932 Total revenues and other income $ 3,028,474 $ 3,460,147 $ 3,932,662 1 Includes revenue attributable to 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, 2024 and 2023, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 178.3 million and $ 193.7 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, 2024, 2023 or 2022. 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. 76 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, 2024, 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: Long-Term Contracts Outstanding at December 31, 2024 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGLs Q2 2030 Deliveries from dedicated acreage in Eagle Ford As produced Canada Natural Gas Q4 2025 Contracts to sell natural gas at USD index pricing 25 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCFD Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCFD Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCFD Canada Natural Gas Q4 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCFD Canada NGLs Q2 2025 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, 2024 December 31, 2023 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 21,716,358 $ 8,021,620 2 $ 21,228,490 $ 8,201,475 2 Corporate and other 149,834 33,033 132,092 23,722 Property, plant and equipment $ 21,866,192 $ 8,054,653 $ 21,360,582 $ 8,225,197 ¹ Includes unproved mineral rights as follows: $ 283,015 $ 151,341 $ 351,000 $ 228,329 2 Includes $ 13,335 in 2024 and $ 15,356 in 2023 related to administrative assets and support equipment. Divestments On September 15, 2023, the Company completed the previously announced divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash proceeds of C$ 139.0 million. No gain or loss was recorded related to this transaction, and the effective date of the transaction was March 1, 2023. 77 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D – Property, Plant and Equipment (Continued) During the third quarter of 2022, the Company completed the disposition of its 62.5 % working interest of the Thunder Hawk field for a purchase price of $ 20.0 million less closing adjustments of $ 23.1 million, resulting in a total net payment to the buyer of $ 3.1 million. Additionally, the buyer assumed the ARO liabilities of approximately $ 47.9 million. A $ 17.9 million gain on sale was recorded in the period related to the sale. In September 2022, the Company completed the disposition of its working interests in Block CA-2 in Brunei for contingent consideration valued at approximately $ 8.7 million. No gain or loss was recorded related to this sale. Acquisitions In August 2022, the Company acquired an additional working interest of 3.37 % in the non-operated Lucius field for a purchase price of $ 78.5 million, net of closing adjustments. In June 2022, the Company acquired an additional working interest of 11.0 % in the non-operated Kodiak field for a purchase price of $ 50.0 million, net of closing adjustments. Impairments 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 and 2022. The following table reflects the recognized before tax impairments for each of the three years presented. (Thousands of dollars) 2024 2023 2022 United States - Offshore $ 62,909 $ — $ — $ 62,909 $ — $ — 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, 2024, 2023 and 2022, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 72.1 million, $ 49.1 million and $ 171.9 million, respectively. The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented. ( Thousands of dollars ) 2024 2023 2022 Beginning balance at January 1 $ 49,118 $ 171,860 $ 179,481 Additions pending the determination of proved reserves 49,408 48 33,440 Reclassifications to proved properties based on the determination of proved reserves — ( 82,185 ) — Divestment — — ( 7,915 ) Capitalized exploration well costs charged to expense ( 26,471 ) ( 40,605 ) ( 33,146 ) Ending balance at December 31 $ 72,055 $ 49,118 $ 171,860 Capital additions of $ 49.4 million, for the year ended December 31, 2024, are 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. Capitalized well costs charged to dry hole expense of $ 26.5 million, for the year ended December 31, 2024, related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well. The preceding table excludes well costs of $ 46.7 million and $ 129.2 million incurred and expensed directly to dry hole during the year ended December 31, 2024 and 2023, respectively. In 2024, these costs primarily include $ 27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 26.1 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America. In 2023, the amount primarily includes $ 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. 78 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D – Property, Plant and Equipment (Continued) The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well. 2024 2023 2022 ( Thousands of dollars ) Amount No. of Wells Amount No. of Wells Amount No. of Wells Aging of capitalized well costs Zero to one year $ 49,790 5 $ — — $ 15,527 2 One to two years — — — — 13,307 2 Two to three years — — 2,698 1 — — Three years or more 22,265 3 46,420 3 143,026 5 $ 72,055 8 $ 49,118 4 $ 171,860 9 Of the $ 22.3 million of exploratory well costs capitalized more than one year at December 31, 2024, $ 15.1 million was in Vietnam, $ 4.4 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. Note E – Inventories Inventories consisted of the following for the respective periods presented: December 31, ( Thousands of dollars ) 2024 2023 Unsold crude oil $ 18,745 $ 10,304 Materials and supplies 36,113 44,150 Inventories $ 54,858 $ 54,454 79 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) 2024 2023 Notes payable 5.875 % notes, due December 2027 $ 78,899 $ 443,249 6.375 % notes, due July 2028 148,590 372,226 7.05 % notes, due May 2029 117,582 179,708 6.00 % notes, due October 2032 600,000 — 5.875 % notes, due December 2042 ¹ 339,761 339,761 Total notes payable 1,284,832 1,334,944 Unamortized debt issuance cost and discount on notes payable ( 14,336 ) ( 10,107 ) Total notes payable, net of unamortized discount 1,270,496 1,324,837 Finance lease obligations, due through November 2034 4,877 4,238 Total debt including current maturities 1,275,373 1,329,075 Current maturities ( 871 ) ( 723 ) Total long-term debt $ 1,274,502 $ 1,328,352 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 2025, nil in 2026, $ 78.9 million in 2027, $ 148.6 million in 2028, $ 117.6 million in 2029 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 During the fourth quarter of 2024, the Company entered into a credit agreement governing a $ 1.35 billion senior unsecured guaranteed RCF with a maturity date of October 7, 2029. The RCF extends the borrowing term and increases the borrowing capacity of the previous RCF. On the date the Company achieves certain credit ratings (Investment Grade Ratings Date), certain covenants will be modified as set forth in the RCF. In addition, prior to Investment Grade Ratings Date, the Company will be 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 bear 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 is 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 is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10 %. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) 0.10 %. 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 $ 14.7 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 RCF. At December 31, 2024, the Company had no outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF. At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68 %. At December 31, 2024, the Company was in compliance with all covenants related to the RCF. 80 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note F - Financing Arrangements and Debt (Continued) Debt Offering On October 3, 2024, the Company closed the public offering of $ 600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000 % per annum and mature on October 1, 2032. The Company has incurred transaction costs of $ 10.1 million on the issuance of these new notes. The Company will pay interest semi-annually on April 1 and October 1 of each year, beginning April 1, 2025. 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. 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. In November 2023, the Company tendered a total of $ 249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $ 250.0 million in aggregate principal. The cost of debt extinguishment of $ 1.3 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023. There were no additional cash costs related to the November 2023 debt extinguishment on the 2027 Notes, 2028 Notes and 2029 Notes for the year ended December 31, 2023. In September 2023, the Company redeemed the remaining $ 248.7 million principal outstanding of the 2025 Notes. The non-cash costs of debt extinguishment of $ 0.9 million were included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023. 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. (Thousands of dollars) 2024 2023 Balance at beginning of year $ 914,763 $ 911,653 Accretion 52,511 46,059 Liabilities incurred 25,619 20,628 Revisions of previous estimates 29,279 29,056 Liabilities settled ( 1,898 ) ( 95,637 ) Changes due to translation of foreign currencies ( 11,390 ) 3,004 Balance at end of period 1,008,884 914,763 Current portion of liability ( 48,080 ) ( 10,712 ) Non-current portion of liability $ 960,804 $ 904,051 81 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note G - Asset Retirement Obligations (Continued) 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 ) 2024 2023 2022 Income (loss) from continuing operations before income taxes United States $ 468,202 $ 901,761 $ 1,306,200 Foreign 99,367 19,308 144,061 Total $ 567,569 $ 921,069 $ 1,450,261 Income tax expense (benefit) U.S. Federal – Current $ — $ — $ — – Deferred 55,377 170,115 234,749 Total U.S. Federal 55,377 170,115 234,749 State ( 4,488 ) 6,622 9,010 Foreign – Current 4,685 13,182 18,134 – Deferred 22,698 6,002 47,571 Total Foreign 27,383 19,184 65,705 Total $ 78,272 $ 195,921 $ 309,464 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 ) 2024 2023 2022 Income tax expense based on the U.S. statutory tax rate $ 119,190 $ 193,424 $ 304,555 Foreign income subject to foreign tax rates different than the U.S. statutory rate 12,119 7,597 10,823 State income taxes, net of federal benefit ( 3,568 ) 4,725 7,118 U.S. tax benefit on certain foreign upstream investments ( 33,677 ) — — Change in deferred tax asset valuation allowance related to other foreign exploration expenditures 2,636 10,853 24,748 Tax effect on income attributable to noncontrolling interest ( 16,656 ) ( 13,046 ) ( 36,471 ) Other, net ( 1,772 ) ( 7,632 ) ( 1,309 ) Total $ 78,272 $ 195,921 $ 309,464 82 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note H – Income Taxes (Continued) 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 ) 2024 2023 Deferred tax assets Property and leasehold costs $ 225,379 $ 240,065 Liabilities for dismantlements 36,719 34,258 Postretirement and other employee benefits 66,293 82,437 U. S. net operating loss 289,594 357,490 Investment in partnership 9,096 14,655 Other deferred tax assets 100,352 48,778 Total gross deferred tax assets 727,433 777,683 Less: Valuation allowance ( 149,498 ) ( 146,861 ) Net deferred tax assets 577,935 630,822 Deferred tax liabilities Deferred tax on undistributed foreign earnings ( 5,000 ) ( 5,000 ) Accumulated depreciation, depletion and amortization ( 811,178 ) ( 847,981 ) Other deferred tax liabilities ( 97,547 ) ( 54,052 ) Total gross deferred tax liabilities ( 913,725 ) ( 907,033 ) Net deferred tax (liabilities) assets $ ( 335,790 ) $ ( 276,211 ) 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 $ 2.6 million in 2024, 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 $ 1.4 billion at year-end 2024 with a corresponding deferred tax asset of $ 289.6 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 2036 and 2037. Other Information Currently, the Company considers $ 100 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $ 5 million liability. At December 31, 2024, $ 1.5 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. 83 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note H – Income Taxes (Continued) ( Thousands of dollars ) 2024 2023 2022 Balance at January 1 $ 6,384 $ 3,928 $ 2,903 Additions for tax positions related to current year 1,643 — 77 Additions for tax positions related to prior year 1,952 2,456 948 Balance at December 31 $ 9,979 $ 6,384 $ 3,928 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, 2024, 2023 and 2022, 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 2025, 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 Statement of Operations during 2025. 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, 2024, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2016; Canada – 2016; and Malaysia – 2017. 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. The Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) and the 2020 Long-Term Incentive Plan (2020 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 2020 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), SARs, restricted stock, RSUs, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5 million shares are issuable during the life of the 2020 Long-Term Plan. 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, 1.2 million shares are available for grant under the 2020 Long-Term Plan at December 31, 2024. The Company also has a Stock Plan for Non-Employee Directors (NEDs) that permits the issuance of RSUs and stock options or a combination thereof to the Company’s NEDs. 84 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) 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 ) 2024 2023 2022 Compensation charged against income before income tax benefit $ 40,831 $ 58,760 $ 74,587 Related income tax benefit recognized in income 5,513 9,330 12,710 As of December 31, 2024, there were $ 46.9 million in compensation costs, to be expensed over approximately the next three years , related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable withholding obligations, upon each stock option exercise and RSU vest. Equity-Settled Awards PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023 and 2024 under the 2020 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 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 2024, 2023 and 2022 are presented in the following table. 2024 2023 2022 Fair value per share at grant date $ 41.95 $ 60.46 $ 37.77 - $ 47.37 Assumptions Expected volatility 50.00 % 81.00 % 79.00 % - 81.00 % Risk-free interest rate 4.14 % 3.90 % 1.39 % - 2.85 % Stock beta 1.062 1.034 1.195 - 1.200 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. 85 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2024 2023 2022 Outstanding at beginning of year 1,818,188 2,148,467 2,670,756 Granted 536,900 409,160 595,700 Vested and issued ( 938,599 ) ( 408,135 ) ( 654,177 ) Forfeited ( 24,068 ) ( 331,304 ) ( 463,812 ) Outstanding at end of year 1,392,421 1,818,188 2,148,467 TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s NEDs under the 2021 NED Plan, and to certain employees under the 2020 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 2024 2023 2022 Non-Employee Directors 1 Closing Stock Price at Grant Date $ 30.26 - $ 45.70 $ 43.27 $ 32.84 Long-Term Incentive Plan 2 Average High/Low Stock Price at Grant Date $ 37.78 - $ 45.98 $ 42.20 $ 29.80 - $ 49.86 1 Under the 2021 NED Plan, RSUs granted in 2024 are scheduled to vest in February 2025. 2 The RSUs granted under the 2020 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 ) 2024 2023 2022 Outstanding at beginning of year 1,219,584 1,227,792 1,451,438 Granted 741,228 556,100 416,492 Vested and issued ( 330,444 ) ( 517,047 ) ( 462,418 ) Forfeited ( 71,768 ) ( 47,261 ) ( 177,720 ) Outstanding at end of year 1,558,600 1,219,584 1,227,792 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, 2023 there were no outstanding stock options. As of December 31, 2024, there were no outstanding SARs. Prior to 2017, the Committee fixed the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixed the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Incentive Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years . For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee. The fair value of each option award was estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant. 86 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Incentive Plans (Continued) Changes in stock options outstanding during the last three years are presented in the following table. Number of Shares Average Exercise Price Outstanding at December 31, 2021 1,319,500 $ 37.77 Exercised ( 760,500 ) 23.29 Forfeited ( 546,000 ) 49.65 Outstanding at December 31, 2022 13,000 28.51 Exercised ( 11,000 ) 28.51 Forfeited ( 2,000 ) 28.51 Outstanding at December 31, 2023 — — Exercisable at December 31, 2021 1,319,500 34.25 Exercisable at December 31, 2022 13,000 28.51 Cash-Settled Awards The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of SARs and CRSUs. SAR awards have terms similar to stock options. 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 $ 1.7 million in 2024, $ 29.4 million in 2023 and $ 49.3 million in 2022. 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 $ 37.1 million, $ 30.9 million and $ 42.9 million was recorded in 2024, 2023 and 2022, 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. 87 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 ) 2024 2023 2024 2023 Change in benefit obligation Obligation at January 1 $ 699,151 $ 663,073 $ 63,808 $ 67,679 Service cost 7,042 6,542 436 495 Interest cost 33,554 34,140 2,923 3,241 Participant contributions — — 2,730 2,629 Actuarial (gain) loss 1 ( 35,417 ) 26,625 825 ( 5,567 ) Medicare Part D subsidy — — 358 299 Exchange rate changes ( 3,263 ) 6,089 ( 14 ) 2 Benefits paid ( 45,743 ) ( 56,296 ) ( 16,072 ) ( 4,970 ) Plan amendments 2 — 18,978 — — Obligation at December 31 655,324 699,151 54,994 63,808 Change in plan assets Fair value of plan assets at January 1 477,809 450,944 — — Actual return on plan assets 27,317 39,953 — — Employer contributions 35,477 37,546 12,984 2,042 Participant contributions — — 2,730 2,629 Medicare Part D subsidy — — 358 299 Exchange rate changes ( 2,740 ) 5,662 — — Benefits paid ( 45,743 ) ( 56,296 ) ( 16,072 ) ( 4,970 ) Fair value of plan assets at December 31 492,120 477,809 — — Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 1,819 3,192 — — Other accrued liabilities ( 10,617 ) ( 10,219 ) ( 4,237 ) ( 4,433 ) Deferred credits and other liabilities ( 154,406 ) ( 214,315 ) ( 50,757 ) ( 59,375 ) Fund Status and net plan liability recognized at December 31 $ ( 163,204 ) $ ( 221,342 ) $ ( 54,994 ) $ ( 63,808 ) 1 Actuarial gains in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation. 2 At December 31, 2023, the Company recognized an increase to its domestic plan benefit obligation related to a plan amendment. The amendment provides a permanent increase to benefits for retirees and beneficiaries who commenced payments prior to 2020. At December 31, 2024, 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) $ ( 163,218 ) $ 39,742 Prior service (credit) cost ( 18,233 ) 3,405 $ ( 181,451 ) $ 43,147 88 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 ) 2024 2023 2024 2023 2024 2023 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 497,947 $ 534,751 $ 489,225 $ 523,096 $ 477,983 $ 461,363 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 145,058 151,146 143,859 148,661 — — Unfunded other postretirement plans 54,994 63,808 54,994 63,808 — — 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 ) 2024 2023 2022 2024 2023 2022 Service cost $ 7,042 $ 6,542 $ 7,875 $ 436 $ 495 $ 968 Interest cost 33,554 34,140 22,747 2,923 3,241 2,211 Expected return on plan assets ( 33,427 ) ( 32,839 ) ( 36,458 ) — — — Amortization of prior service cost (credit) 2,316 620 ( 684 ) ( 532 ) ( 532 ) ( 532 ) Recognized actuarial loss (gain) 9,438 9,776 16,098 ( 3,586 ) ( 3,512 ) ( 615 ) Net periodic benefit expense 18,923 18,239 9,578 ( 759 ) ( 308 ) 2,032 Other pension costs 251 219 — — — — Total net periodic benefit expense $ 19,174 $ 18,458 $ 9,578 $ ( 759 ) $ ( 308 ) $ 2,032 The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2024 2023 2024 2023 Benefit obligation at December 31 $ 115,428 $ 133,822 $ 106 $ 115 Fair value of plan assets at December 31 103,445 119,236 — — Net plan liabilities recognized ( 11,983 ) ( 14,586 ) ( 106 ) ( 115 ) Net periodic benefit expense (benefit) 1,480 1,387 ( 44 ) ( 44 ) 89 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, 2024 and 2023 and net periodic benefit expense for 2024 and 2023. Benefit Obligations Net Periodic Benefit Expense Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, December 31, Year Year 2024 2023 2024 2023 2024 2023 2024 2023 Discount rate on obligation, interest cost and service cost 5.58 % 5.03 % 5.65 % 5.15 % 5.17 % 5.27 % 5.15 % 5.41 % Rate of compensation increase 3.38 % 3.52 % — — 3.50 % 3.52 % — — Cash balance interest credit rate 3.20 % 3.20 % — — — — — — Expected return on plan assets — — — — 7.19 % 7.35 % — — 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 2025 $ 49,406 $ 4,237 2026 50,193 4,252 2027 51,634 4,267 2028 51,632 4,386 2029 51,457 4,278 2030-2034 261,891 20,594 For purposes of measuring postretirement benefit obligations at December 31, 2024, the future annual rates of increase in the cost of health care were assumed to be 7.5 % for 2025 decreasing each year to an ultimate rate of 4.0 % in 2048 and thereafter. During 2024, the Company made contributions of $ 34.7 million to its domestic defined benefit pension plans and $ 13.0 million to its domestic postretirement benefits plan. During 2025, the Company currently expects to make contributions of $ 25.6 million to its domestic defined benefit pension plans, $ 0.8 million to its foreign defined benefit pension plans and $ 4.2 million to its domestic postretirement benefits plan. PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement (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 90 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, 2024 2023 Equity securities 57.3 % 62.6 % Fixed income securities 36.2 % 29.1 % Alternatives 3.7 % 5.1 % Cash equivalents 2.8 % 3.2 % 100.0 % 100.0 % The Company’s weighted average expected return on plan assets was 7.2 % in 2024 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 7.2 % expected return was comprised of the weighted average expected future equity securities return of 8.0 % and a fixed income securities return of 5.2 %. An average expected investment expense of 0.8 % is included in this calculation. Over the last 10 years, the return on funded retirement plan assets has averaged 3.3 %. 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 91 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, 2023, 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, 2023 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 $ 105,212 $ 105,212 $ — $ — U.S. small/midcap 64,165 64,165 — — Other alternative strategies 3,831 — — 3,831 International equity 31,820 31,820 — — Emerging market equity 10,525 10,525 — — Fixed income securities: U.S. fixed income 132,608 56,381 76,227 — Cash and equivalents 10,412 10,412 — — Total Domestic Plans 358,573 278,515 76,227 3,831 Foreign Plans Equity securities funds 24,389 — 24,389 — Fixed income securities funds 23,930 — 23,930 — Diversified pooled fund 45,162 — 45,162 — Other 20,623 — — 20,623 Cash and equivalents 5,133 — 5,133 — Total Foreign Plans 119,236 — 98,613 20,623 Total $ 477,809 $ 278,515 $ 174,841 $ 24,454 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 two investments. One of these investments is valued annually based on net asset value and permits withdrawals annually after a 90 -day notice, and the other investment is valued quarterly based on net asset values and has a three-year lock-up period and a 95 -day notice following the lock-up period. The latter of these investments was sold during 2024. 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. 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 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, 2022 $ 32,734 Actual return on plan assets: Relating to assets held at the reporting date 711 Purchases, sales and settlements ( 8,991 ) Total at December 31, 2023 24,454 Actual return on plan assets: Relating to assets held at the reporting date ( 3,574 ) Relating to assets sold during the period ( 2,865 ) Total at December 31, 2024 $ 18,015 401(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 allotment based on years of participation in the plans, with a maximum match of 6.0 %. Amounts charged to expense for the Company’s match to these plans were $ 8.7 million in 2024, $ 8.5 million in 2023 and $ 6.0 million in 2022. 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 2024, the Company entered into natural gas swap contracts that will be effective in 2025. 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. At December 31, 2024 volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are 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 Subsequent to year end, the Company entered into additional natural gas derivative contracts. Volumes per day and the weighted average prices for these contracts are 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 93 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Financial Instruments and Risk Management (Continued) At December 31, 2023 the Company did no t have any outstanding crude oil or natural gas derivative contracts. 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, 2024 and 2023. At December 31, 2024 and 2023, 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 Sheet Location 2024 2023 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 Statement of Operations Locations 2024 2023 2022 Commodity swaps Loss on derivative instruments $ ( 1,707 ) $ — $ ( 160,690 ) Commodity collars Loss on derivative instruments — — ( 159,721 ) 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. Note L – Net Income (Loss) Per Common Share Net income (loss) 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 ) 2024 2023 2022 Basic method 150,011,458 155,233,560 155,276,533 Dilutive stock options and restricted stock units 1,015,894 1,412,869 2,198,305 Diluted method 151,027,352 156,646,429 157,474,838 The following table reflects certain options to purchase shares of common stock that were outstanding during each of the three years presented but were not included in the computation of diluted earnings per share because the incremental shares from the assumed conversion were antidilutive. 2024 2023 2022 Antidilutive stock options excluded from diluted shares — — 126,000 Weighted average price of these options — — $ 49.65 94 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note M – Other Financial Information Gain 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 $ 45.4 million gain in 2024, $ 10.8 million loss in 2023 and $ 23.0 million gain in 2022. Supplemental Information to Statement of Cash Flows ( Thousands of dollars ) 2024 2023 2022 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ 71,081 $ 47,151 $ ( 137,228 ) (Increase) decrease in inventories 1,327 329 ( 1,534 ) (Increase) decrease in prepaid expenses 1,192 ( 1,293 ) ( 3,413 ) Increase (decrease) in accounts payable and accrued liabilities ¹ 3,287 ( 140,011 ) 69,854 Increase (decrease) in income taxes payable ( 2,004 ) ( 5,537 ) 6,593 Net decrease (increase) in non-cash operating working capital $ 74,883 $ ( 99,361 ) $ ( 65,728 ) Supplementary disclosures: Cash income taxes paid, net of refunds $ 12,648 $ 12,356 $ 24,853 Interest paid, net of amounts capitalized of $ 11.4 million in 2024, $ 14.5 million in 2023 and $ 16.3 million in 2022 78,806 108,912 149,597 Non-cash investing activities: Asset retirement costs capitalized $ 47,233 $ 32,975 $ ( 21,147 ) (Increase) decrease in capital expenditure accrual ( 5,935 ) 17,517 ( 31,397 ) 1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments. 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, 2022 $ ( 418,230 ) $ ( 116,456 ) $ ( 534,686 ) 2023 components of other comprehensive income (loss): Before reclassifications to income 36,598 ( 27,580 ) 9,018 Reclassifications to income — 4,551 ¹ 4,551 Net other comprehensive income 36,598 ( 23,029 ) 13,569 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 (loss) ( 134,692 ) 27,737 ( 106,955 ) Balance at December 31, 2024 $ ( 516,324 ) $ ( 111,748 ) $ ( 628,072 ) 1 Reclassifications before taxes of $ 5.4 million and $ 5.6 million are included in the computation of net periodic benefit expense in 2024 and 2023, respectively. See Note J for additional information. Related income taxes of $ 1.4 million and $ 1.1 million are included in income tax expense in 2024 and 2023, respectively. 95 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued 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, 2024 December 31, 2023 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 19,469 $ — $ — $ 19,469 $ 17,785 $ — $ — $ 17,785 Commodity swaps — 1,707 — 1,707 — — — — $ 19,469 $ 1,707 $ — $ 21,176 $ 17,785 $ — $ — $ 17,785 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. 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 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 is recorded in “(Loss) Gain on derivative instruments” in the Consolidated Statements of Operations. The Company acquired Gulf of America assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. (collectively, LLOG) and, in a separate agreement, from Petrobras America Inc. (PAI) in 2019 and 2018, respectively. Under the terms of both transactions, contingent consideration was paid after meeting specified revenue thresholds and project milestones and recorded to “Contingent consideration payment” in the Consolidated Statements of Cash Flows. As at December 31, 2022, the Company’s liabilities with PAI and LLOG were based on realized inputs of volumes and pricing as a result of contractual thresholds and time durations being achieved. As a result, the related liability as at December 31, 2022, of $ 192.7 million, was no longer subject to fair value measurement. The liability was included in “Other accrued liabilities” in the Consolidated Balance Sheets and the changes in fair value of the contingent consideration during 2022 were recorded in “Other income (loss)” in the Consolidated Statements of Operations. 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, 2024 and 2023. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2024 and 2023. 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 nominal. 96 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) December 31, 2024 2023 ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value Financial liabilities: Current and long-term debt $ 1,275,374 $ 1,185,961 $ 1,329,075 $ 1,265,185 Fair Values – Nonrecurring Impairment expenses of $ 62.9 million were incurred in 2024. In the first quarter of 2024, an impairment charge of $ 34.5 million was triggered for the Calliope field, and in the fourth quarter of 2024, an impairment charge of $ 28.4 million was triggered for the Nearly Headless Nick field. Both of the impairments were due to operational issues that led to reserve reductions. There were no impairment expenses incurred in 2023. 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 table: 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 2024 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 $ 148.8 million in 2025, $ 117.7 million in 2026, $ 105.5 million in 2027, $ 96.0 million in 2028 and $ 64.2 million in 2029. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total costs incurred under these service arrangements were $ 225.9 million in 2024, $ 295.1 million in 2023 and $ 216.4 million in 2022. Commitments for capital expenditures were approximately $ 417.0 million at December 31, 2024, including $ 53.6 million for the Gulf of America, $ 112.2 million for Eagle Ford Shale, $ 31.2 million for Canada and $ 220.0 million for Other Offshore, mainly for capital projects in Vietnam. Commitments for operating agreements include approximately $ 178.0 million at December 31, 2024 for Other Offshore for the purpose of supporting future development activities in Vietnam. 97 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued 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; 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 facilities once production has ceased. 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 recent 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. There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. 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 U.S. EPA. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. The charge, referred to as the WEC, is a component of the Biden Administration’s Methane Emissions Reduction Program to limit methane emissions from the oil and gas industry under the 2022 IRA. Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice. 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. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. rejoined the Paris Agreement, which became effective for the U.S. on February 19, 2021. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement again. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. 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 98 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note Q - Environmental and Other Contingencies (Continued) 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 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 ) 2024 2023 2022 Beginning of year 152,748,642 155,467,319 154,463,050 Stock options exercised 1 — 2,657 181,655 Restricted stock awards 1 1,105,268 689,824 822,614 Treasury shares purchased ( 8,008,786 ) ( 3,411,158 ) — End of year 145,845,124 152,748,642 155,467,319 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, 2024, the Company repurchased 8.0 million shares of its common stock under the share repurchase program for $ 300.0 million ($ 302.7 million including excise taxes and fees). As of December 31, 2024, the Company had $ 650.1 million of its common stock remaining available to repurchase under the program. Subsequent to year end, as of February 25, 2025, the Company repurchased 3.4 million shares of its common stock in open-market transactions for $ 95.1 million, excluding taxes and fees. As of this date, the Company had $ 555.0 million of its common stock remaining available to repurchase under the program. 99 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued Note R - Common Stock Issued and Outstanding (Continued) 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 exploration and production 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. For the income statement periods presented in these financial statements, Murphy’s former CEO, Roger Jenkins, acted as the CODM. As of January 1, 2025, Murphy appointed a new CEO, Eric Hambly. 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. 2024 2023 2022 Chevron Corporation 13 % 16 % 19 % ExxonMobil Corporation 20 % 27 % 12 % Phillips 66 10 % N/A 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, 2024 and 2023. The former U.K., Malaysia and U.S. refining and marketing units have been reported as discontinued operations for all periods presented in these consolidated financial statements. 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 and other activities, including interest income, other gains and losses (including foreign exchange gains/losses and realized/unrealized gains/losses on crude oil and natural gas contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. “Other segment costs” 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” 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. 100 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, Other, 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 Revenues from external customers 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 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 Current income tax expense 1.5 3.2 0.2 4.9 0.9 5.8 Deferred income tax expense 123.8 8.8 ( 31.2 ) 101.4 ( 28.9 ) 72.5 Total income tax expense 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 a noncontrolling interest in MP GOM. 101 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, Other, 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 Revenues from external customers 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 Other miscellaneous operating expenses 20.1 15.5 8.1 43.7 ( 4.4 ) 39.3 Loss on contingent consideration 7.1 — — 7.1 — 7.1 Total other operating expenses 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 Current income tax expense 3.1 3.7 0.6 7.4 8.8 16.2 Deferred income tax expense 229.6 7.5 ( 6.7 ) 230.4 ( 50.6 ) 179.8 Total income tax expense 232.7 11.2 ( 6.1 ) 237.8 ( 41.8 ) 196.0 Other segment costs (income) 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 a noncontrolling interest in MP GOM. 102 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, Other, and Discontinued Operations Consolidated Total Year ended December 31, 2022 Revenue from production $ 3,435.5 $ 580.0 $ 23.0 $ 4,038.5 $ — $ 4,038.5 Sales of purchased natural gas 0.2 181.5 — 181.7 — 181.7 Gain on sales of assets and other operating income (loss) 25.5 1.4 — 26.9 ( 314.4 ) ( 287.5 ) Revenues from external customers 3,461.2 762.9 23.0 4,247.1 ( 314.4 ) 3,932.7 Lease operating expenses Lease operating expenses and taxes other than income 458.2 147.9 1.5 607.6 — 607.6 Repair and maintenance 34.9 4.7 — 39.6 — 39.6 Workovers 29.6 2.5 — 32.1 — 32.1 Total lease operating expenses 522.7 155.1 1.5 679.3 — 679.3 Severance and ad valorem taxes 55.7 1.3 — 57.0 — 57.0 Transportation, gathering and processing 142.2 70.5 — 212.7 — 212.7 Costs of purchased natural gas 0.2 171.8 — 172.0 — 172.0 Selling and general expenses 20.4 21.9 2.2 44.5 88.8 133.3 Exploration Expenses — Geological and geophysical 8.3 0.4 1.8 10.5 — 10.5 Dry holes and previously suspended exploration costs 23.0 — 59.1 82.1 — 82.1 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 16.2 0.7 23.7 40.6 — 40.6 Total exploration expenses 47.5 1.1 84.6 133.2 — 133.2 Depreciation, depletion and amortization 617.0 141.5 5.4 763.9 12.9 776.8 Accretion of asset retirement obligations 36.5 9.6 0.1 46.2 — 46.2 Other operating expenses Other miscellaneous operating expenses 41.3 10.5 2.4 54.2 5.0 59.2 Loss on contingent consideration 78.3 — — 78.3 — 78.3 Total other operating expenses 119.6 10.5 2.4 132.5 5.0 137.5 Interest Income ( 0.3 ) — — ( 0.3 ) ( 2.5 ) ( 2.8 ) Interest expense, net of capitalization 0.1 — 0.3 0.4 150.4 150.8 Income tax expense Current income tax expense 8.1 8.8 2.3 19.2 4.2 23.4 Deferred income tax expense 362.7 34.8 0.6 398.1 ( 112.0 ) 286.1 Total income tax expense 370.8 43.6 2.9 417.3 ( 107.8 ) 309.5 Other segment costs (income) 6.9 1.8 0.6 9.3 ( 20.8 ) ( 11.5 ) Segment income (loss) - including NCI 1 $ 1,521.9 $ 134.2 $ ( 77.0 ) $ 1,579.1 $ ( 440.4 ) $ 1,138.7 Additions to property, plant, equipment $ 838.6 $ 208.5 $ ( 5.7 ) $ 1,041.4 $ 21.9 $ 1,063.3 Total assets at year-end 6,930.6 2,125.6 217.4 9,273.6 1,035.4 10,309.0 1 Includes results attributable to a noncontrolling interest in MP GOM. 103 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 2024 $ 6,415.9 $ 1,389.5 $ 249.2 $ 8,054.6 2023 6,555.0 1,497.3 172.8 8,225.1 2022 6,562.8 1,499.1 166.1 8,228.0 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 16 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. Related Expenses Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows: Year Ended December 31, (Thousands of dollars) Financial Statement Category 2024 2023 Operating lease 1, 2 Lease operating expenses $ 411,303 $ 246,721 Operating lease 2 Transportation, gathering and processing 16,117 37,797 Operating lease 2 Selling and general expenses 10,990 9,859 Operating lease 2 Other operating expense 6,622 675 Operating lease 2 Exploration expenses 38,974 110,577 Operating lease 2 Property, plant and equipment 277,170 204,595 Operating lease 2 Asset retirement obligations 10 57,442 Finance lease Amortization of asset Depreciation, depletion and amortization 855 1,505 Interest on lease liabilities Interest expense, net 193 221 Sublease income Other income ( 1,143 ) ( 1,402 ) Net lease expense $ 761,091 $ 667,990 1 Variable lease expenses. For the years ended December 31, 2024 and 2023, includes variable lease expenses of $ 42.3 million and $ 36.7 million, respectively, primarily related to additional volumes processed at a natural gas processing plant. 2 Short-term leases due within 12 months. For the year ended December 31, 2024, includes $ 236.4 million in lease operating expenses, $ 13.0 million for “Transportation, gathering and processing”, $ 38.5 million for “Exploration expenses, including undeveloped lease amortization”, $ 0.8 million in “Selling and general expenses”, $ 6.2 million in “Other operating expense”, $ 97.1 million in “Property, plant and equipment, net” and nil in “Asset retirement obligations” relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment. For the year ended December 31, 2023, includes $ 78.2 million in lease operating expenses, $ 29.4 million in “Transportation, gathering and processing”, $ 80.3 million for “Exploration expenses, including undeveloped lease amortization”, $ 1.6 million in “Selling and general expenses", $ 0.3 million in “Other operating expense”, $ 112.7 million in “Property, plant and equipment, net” and $ 57.4 million in “Asset retirement obligations” relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment. 104 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note T – Leases (Continued) Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2025 $ 290,474 $ 1,257 $ 291,731 2026 123,487 1,257 124,744 2027 66,521 1,257 67,778 2028 59,398 1,257 60,655 2029 56,849 456 57,305 Remaining 406,450 927 407,377 Total future minimum lease payments 1,003,179 6,411 1,009,590 Less imputed interest ( 212,590 ) ( 1,534 ) ( 214,124 ) Present value of lease liabilities 1 $ 790,589 $ 4,877 $ 795,466 1 Includes both the current and long-term portion of the lease liabilities. Lease Term and Discount Rate December 31, 2024 December 31, 2023 Weighted average remaining lease term: Operating leases 8 years 10 years Finance leases 6 years 5 years Weighted average discount rate: Operating leases 5.7 % 5.9 % Finance leases 4.9 % 4.7 % Other Information Year Ended December 31, (Thousands of dollars) 2024 2023 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 328,847 $ 271,488 Operating cash flows from finance leases 311 221 Financing cash flows from finance leases 665 622 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 349,312 $ 5,923 1 For the year ended December 31, 2024, right-of-use assets obtained in exchange for lease liabilities primarily includes $ 254.1 million related to the extension of an operating lease pertaining to a drill ship used in our U.S. Offshore business and $ 52.7 million pertaining to two drilling rigs and several natural gas compressor units at our U.S. Onshore business. December 31, 2023 includes $ 4.5 million related to natural gas compressor units at various U.S. Onshore locations. Note U – Subsequent Event On January 30, 2025, the Board of Directors of Murphy Oil Corporation (NYSE: MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $ 0.325 per share, or $ 1.30 per share on an annualized basis. The dividend is payable on March 3, 2025, to stockholders of record as of February 18, 2025. 105 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 crude oil, natural gas and NGLs 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 2024 were $ 75.48 per BBL for NYMEX 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 NYMEX crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub). The average prices used for 2022 were $ 93.67 per BBL for NYMEX crude oil (WTI) and $ 6.36 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 with one decimal; totals within the tables may not add as a result of rounding. 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 crude oil, natural gas and NGL reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method. 106 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, 2024. 107 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 2021 – 2024 Equivalents ( Millions of barrels of oil equivalent ) Total United States Canada Other Proved developed and undeveloped reserves: December 31, 2021 716.9 343.4 372.8 0.7 Revisions of previous estimates ( 23.6 ) 29.0 ( 52.8 ) 0.2 Improved recovery 5.3 5.3 — — Extensions and discoveries 80.1 20.6 59.5 — Purchases of properties 5.0 5.0 — — Sale of properties ( 4.4 ) ( 4.4 ) — — Production ( 63.9 ) ( 41.9 ) ( 21.7 ) ( 0.3 ) 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 ¹ 729.0 307.4 408.9 12.7 Proved developed reserves: December 31, 2021 419.2 241.9 176.8 0.6 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 ² 436.2 218.9 217.1 0.2 Proved undeveloped reserves: December 31, 2021 297.7 101.6 196.0 0.1 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 ³ 292.8 88.5 191.8 12.5 1 Total and United States includes proved reserves of 15.9 MMBOE, consisting of 14.5 MMBBL of oil, 0.6 MMBBL of NGLs and 5 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 14.4 MMBOE, consisting of 13.2 MMBBL of oil, 0.5 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.5 MMBOE, consisting of 1.3 MMBBL of oil, 0.1 MMBBL of NGLs and 0.8 BCF of natural gas attributable to the noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. 108 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 2021 – 2024 (Continued) 2024 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in 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 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 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 Tupper Montney. Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in 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. 2022 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive well performance in the Gulf of America. Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Tupper Montney and Kaybob Duvernay, as well as the Gulf of America and Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. 109 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 2021 – 2024 ( Millions of barrels ) Total United States Canada Other Proved developed and undeveloped crude oil reserves: December 31, 2021 291.5 255.0 35.9 0.6 Revisions of previous estimates 23.4 19.9 3.3 0.2 Improved recovery 4.7 4.7 — — Extensions and discoveries 18.9 16.1 2.8 — Purchases of properties 4.2 4.2 — — Sale of properties ( 3.6 ) ( 3.6 ) — — Production ( 35.5 ) ( 32.7 ) ( 2.5 ) ( 0.3 ) 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 ¹ 275.1 225.2 37.7 12.2 Proved developed crude oil reserves: December 31, 2021 191.5 174.9 16.0 0.5 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 ² 184.7 164.1 20.4 0.2 Proved undeveloped crude oil reserves: December 31, 2021 99.9 80.0 19.8 0.1 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 ³ 90.4 61.1 17.3 12.0 1 Total and United States includes proved reserves of 14.5 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 13.2 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 1.3 MMBBL attributable to the noncontrolling interest in MP GOM. 4 Totals within the tables may not add as a result of rounding. 110 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 2021 – 2024 (Continued) 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 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 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. 2022 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The positive crude oil reserves revisions in 2022 resulted predominantly from improved well performance in the Gulf of America and impacts of higher commodity prices in the U.S. Extensions and discoveries - In 2022, proved oil reserves were added for drilling and expansion activities predominantly in the Gulf of America and the Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. 111 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 2021 – 2024 ( Millions of barrels ) Total United States Canada Other Proved developed and undeveloped NGL reserves: December 31, 2021 38.4 35.1 3.3 — Revisions of previous estimates 4.4 3.9 0.5 — Improved recovery 0.2 0.2 — — Extensions and discoveries 2.5 1.9 0.6 — Purchase of properties 0.3 0.3 — — Sale of properties ( 0.2 ) ( 0.2 ) — — Production ( 3.9 ) ( 3.6 ) ( 0.3 ) — 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 ¹ 38.6 34.1 4.5 — Proved developed NGL reserves: December 31, 2021 28.4 25.6 2.8 — December 31, 2022 29.7 27.4 2.3 — December 31, 2023 25.9 24.1 1.8 — December 31, 2024 ² 24.1 21.9 2.2 — Proved undeveloped NGL reserves: December 31, 2021 10.0 9.5 0.5 — December 31, 2022 12.0 10.2 1.8 — December 31, 2023 11.7 10.2 1.5 — December 31, 2024 ³ 14.5 12.2 2.3 — 1 Total and United States includes total proved reserves of 0.6 MMBBL attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 0.5 MMBBL attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.1 MMBBL attributable to the noncontrolling interest in MP GOM. 112 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 2021 – 2024 (Continued) 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 Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in 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 Tupper Montney and 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. 2022 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The positive NGL reserves revisions in 2022 resulted predominantly from improved well performance in the Gulf of America, Eagle Ford Shale, and Kaybob Duvernay. Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the Gulf of America and Eagle Ford Shale, as well as in Tupper Montney and Kaybob Duvernay. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale. 113 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 2021 – 2024 ( Billions of cubic feet ) Total United States Canada Other Proved developed and undeveloped natural gas reserves: December 31, 2021 2,322.3 320.3 2,001.8 0.2 Revisions of previous estimates ( 309.8 ) 30.7 ( 340.5 ) — Improved recovery 2.6 2.6 — — Extensions and discoveries 352.4 15.7 336.7 — Purchases of properties 2.9 2.9 — — Sale of properties ( 3.6 ) ( 3.6 ) — — Production ( 146.9 ) ( 33.7 ) ( 113.2 ) — 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 1,4 2,491.8 288.9 2,199.9 3.0 Proved developed natural gas reserves: December 31, 2021 1,196.0 248.1 947.7 0.2 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 2,4 1,364.2 196.8 1,167.2 0.2 Proved undeveloped natural gas reserves: December 31, 2021 1,126.4 72.2 1,054.1 — 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 ³ 1,127.6 92.1 1,032.7 2.8 1 Total and United States includes total proved reserves of 5.0 BCF attributable to the noncontrolling interest in MP GOM. 2 Total and United States includes proved developed reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM. 3 Total and United States includes proved undeveloped reserves of 0.8 BCF attributable to the noncontrolling interest in MP GOM. 4 Includes proved natural gas reserves to be consumed in operations as fuel of 67.9 BCF, 36.0 BCF and 2.8 BCF for the U.S., Canada and Other, respectively, with 1.1 BCF attributable to the noncontrolling interest in MP GOM. 5 Totals within the tables may not add as a result of rounding. 114 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 2021 – 2024 (Continued) 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 Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in 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 Tupper Montney and 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 Tupper Montney and 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 Tupper Montney. Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in 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. 2022 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. Extensions and discoveries - In 2022, proved natural gas reserves were added for drilling and expansion activities predominantly in Tupper Montney, as well as in the Gulf of America and Eagle Ford Shale. Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America and divested certain working interests in the Gulf of America and Eagle Ford Shale. 115 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, 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 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 166.5 0.4 57.0 223.9 Property additions $ 671.3 $ 206.2 $ 13.1 $ 890.6 Year ended December 31, 2022 Property acquisition costs Unproved $ 1.8 $ — $ — $ 1.8 Proved 128.5 — — 128.5 Total acquisition costs 130.3 — — 130.3 Exploration costs 42.2 0.8 70.3 113.3 Development costs 704.9 208.5 4.3 917.7 Total costs incurred 877.4 209.3 74.6 1,161.3 Charged to expense Dry hole expense 23.0 — 59.1 82.1 Geophysical and other costs 15.8 0.8 21.1 37.7 Total charged to expense 38.8 0.8 80.2 119.8 Property additions $ 838.6 $ 208.5 $ ( 5.6 ) $ 1,041.5 116 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, 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 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 noncontrolling interest in MP GOM. 117 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, 2022 Revenues Crude oil and natural gas liquids sales $ 3,210.3 $ 267.5 $ 22.8 $ 3,500.6 Natural gas sales 225.3 312.6 — 537.9 Sales of purchased natural gas 0.2 181.5 — 181.7 Total oil and natural gas revenues 3,435.8 761.6 22.8 4,220.2 Other operating revenues 25.4 1.3 — 26.7 Total revenues 3,461.2 762.9 22.8 4,246.9 Costs and expenses Lease operating expenses 522.7 155.1 1.5 679.3 Severance and ad valorem taxes 55.7 1.3 — 57.0 Transportation, gathering and processing 142.2 70.5 — 212.7 Costs of purchased natural gas 0.2 171.8 — 172.0 Exploration costs charged to expense 38.8 0.8 80.2 119.8 Undeveloped lease amortization 8.7 0.2 4.4 13.3 Depreciation, depletion and amortization 617.0 141.5 5.4 763.9 Accretion of asset retirement obligations 36.5 9.6 0.1 46.2 Selling and general expenses 20.4 21.9 2.2 44.5 Other expenses 126.3 12.4 3.1 141.8 Total costs and expenses 1,568.5 585.1 96.9 2,250.5 Results of operations before taxes 1,892.7 177.8 ( 74.1 ) 1,996.4 Income tax expense (benefit) 370.8 43.6 2.9 417.3 Results of operations $ 1,521.9 $ 134.2 $ ( 77.0 ) $ 1,579.1 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. 118 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, 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 December 31, 2022 Future cash inflows $ 27,277.9 $ 12,360.2 $ 59.2 $ 39,697.3 Future development costs ( 1,594.5 ) ( 642.4 ) ( 1.4 ) ( 2,238.3 ) Future production costs ( 8,297.4 ) ( 4,199.0 ) ( 12.1 ) ( 12,508.5 ) Future income taxes ( 2,606.8 ) ( 1,788.7 ) ( 5.4 ) ( 4,400.9 ) Future net cash flows 14,779.2 5,730.1 40.3 20,549.6 10% annual discount for estimated timing of cash flows ( 5,709.8 ) ( 3,015.6 ) ( 11.0 ) ( 8,736.4 ) Standardized measure of discounted future net cash flows $ 9,069.4 $ 2,714.5 $ 29.3 $ 11,813.2 1 Includes noncontrolling interest in MP GOM. 2 Totals within the table may not add as a result of rounding. 119 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 ) 2024 2023 2022 Net changes in prices and production costs 2 $ ( 1,116.5 ) $ ( 5,845.6 ) $ 4,812.2 Net changes in development costs ( 152.7 ) ( 78.8 ) ( 531.1 ) Sales and transfers of oil and natural gas produced, net of production costs ( 1,824.8 ) ( 2,264.8 ) ( 2,917.4 ) Net change due to extensions and discoveries 583.7 770.4 1,223.5 Net change due to purchases and sales of proved reserves — ( 96.1 ) 102.1 Development costs incurred 668.6 703.7 769.3 Accretion of discount 773.5 1,393.3 802.6 Revisions of previous quantity estimates ( 688.1 ) ( 771.5 ) 1,652.9 Net change in income taxes 298.8 1,229.6 ( 1,399.9 ) Net (decrease) increase ( 1,457.5 ) ( 4,959.8 ) 4,514.2 Standardized measure at January 1 6,853.4 11,813.2 7,299.0 Standardized measure at December 31 $ 5,395.9 $ 6,853.4 $ 11,813.2 1 Includes noncontrolling interest in MP GOM. 2 The average prices used for 2024 were $ 75.48 per BBL for NYMEX 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 NYMEX crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub). The average prices used for 2022 were $ 93.67 per BBL for NYMEX crude oil (WTI) and $ 6.36 per MCF for natural gas (Henry Hub). 120 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, 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 December 31, 2023 Unproved oil and natural gas properties 1 $ 337.3 $ 13.1 $ 49.7 $ 400.1 Proved oil and natural gas properties 15,868.4 4,716.0 153.7 20,738.1 Gross capitalized costs 16,205.7 4,729.1 203.4 21,138.2 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties ( 105.3 ) — ( 17.4 ) ( 122.7 ) Proved oil and natural gas properties ( 9,552.9 ) ( 3,233.7 ) ( 42.8 ) ( 12,829.4 ) Net capitalized costs $ 6,547.5 $ 1,495.4 $ 143.2 $ 8,186.1 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. 121 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 1 Year ended December 31, 2024 Revenue from contracts with customers $ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6 Income from continuing operations before income taxes 145.6 189.6 153.8 78.6 567.6 Income from continuing operations 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 Year ended December 31, 2023 Revenue from contracts with customers $ 840.0 $ 812.9 $ 953.8 $ 842.2 $ 3,448.9 Income from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0 Income from continuing operations 214.0 92.5 278.2 140.5 725.2 Net income including noncontrolling interest 214.3 91.9 277.8 139.7 723.7 Net income attributable to Murphy 191.6 98.3 255.3 116.4 661.6 Income from continuing operations per common share ² Basic 1.23 0.63 1.64 0.76 4.27 Diluted 1.22 0.62 1.63 0.75 4.23 Net income per common share ² Basic 1.23 0.63 1.64 0.76 4.26 Diluted 1.22 0.62 1.63 0.75 4.22 Cash dividend per common share 0.275 0.275 0.275 0.275 1.100 1 Revenue from contracts with customers, “Income from continuing operations before income taxes”, “Income from continuing operations” and “Net income including noncontrolling interest” include 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. 122 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SCHEDULE II - VALUATION ACCOUNTS AND RESERVES ( Millions of dollars ) Balance at January 1 Charged to Expense Deductions Other Balance at December 31 2024 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6 Deferred tax asset valuation allowance 146.9 2.6 — — 149.5 2023 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6 Deferred tax asset valuation allowance 136.0 10.9 — — 146.9 2022 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6 Deferred tax asset valuation allowance 111.2 24.8 — — 136.0 123 Table of Contents DEFINITIONS Currencies: CAD or C$ - Canadian dollar USD or US$ - United States dollar Units of Measurement: BBL - Barrels BCF - Billion cubic feet BOE - Barrels of oil equivalent BOEPD - Barrels of oil equivalent per day MCF - Thousand cubic feet MMBBL - Million barrels of oil 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 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 is 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 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 Accounting: ARO - Asset retirement obligation ASC - Accounting Standards Codification ASU - Accounting Standards Update 124 Table of Contents DEFINITIONS - Continued CODM - Chief Operating Decision Maker DD&A - Depreciation, depletion and amortization EBITDA - Earnings before interest, taxes, depreciation and amortization FASB - Financial Accounting Standards Board GAAP - U.S. Generally Accepted Accounting Principles NCI - Noncontrolling interest PCAOB - Public Company Accounting Oversight Board SEC - U.S. Securities and Exchange Commission Other: AIP - Annual Incentive Plan BOEM - U.S. Bureau of Ocean Energy Management BSEE - U.S. Bureau of Safety and Environmental Enforcement CRSU - Cash-settled restricted time-based stock unit EPA - U.S. Environmental Protection Agency ESG - Environmental, Social and Governance GHG - Greenhouse gas IRA - Inflation Reduction Act MP GOM - MP Gulf of Mexico, LLC PAI - Petrobras America Inc. PSU - Performance-based restricted stock unit RCF - Revolving credit facility ROACE - Return on average capital employed RSU - Time-based restricted stock unit SAR - Stock appreciation right SOFR - Secured Overnight Financing Rate TCFD - Task Force on Climate-related Financial Disclosures TSR - Total Shareholder Return WEC - Waste Emission Charge 125