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 Murphy 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, 2021, 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, 2021. 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, 2021 and their report is included on page 67 of this Form 10-K report. There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Item 9B. OTHER INFORMATION None Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS None 56 Table of Contents PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Certain information regarding executive officers of the Company is included on page 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 11, 2022 under the captions “Election of Directors” and “Committees.” Murphy Oil has adopted a Code of Ethical Conduct, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at 9805 Katy Fwy, Suite G-200, Houston, TX 77024. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s Website. 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 11, 2022 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors” and in various compensation schedules. 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 11, 2022 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “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 11, 2022 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 11, 2022 under the caption “Audit Committee Report.” 57 Table of Contents PART IV Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) 1. Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below. Page No. Report of Management – Consolidated Financial Statements 63 Report of Management – Internal Control Over Financial Reporting 63 Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements (KPMG LLP , Houston, TX, Auditor Firm ID: 185 ) 64 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting (KPMG LLP, Houston, TX, Auditor Firm ID: 185) 67 Consolidated Balance Sheets 68 Consolidated Statements of Operations 69 Consolidated Statements of Comprehensive Income (Loss) 70 Consolidated Statements of Cash Flows 71 Consolidated Statements of Stockholders’ Equity 72 Notes to Consolidated Financial Statements 73 Note A – Significant Accounting Policies 73 Note B – New Accounting Principles and Recent Accounting Pronouncements 77 Note C – Revenue from Contracts with Customers 78 Note D – Property, Plant and Equipment 81 Note E – Assets Held for Sale and Discontinued Operations 83 Note F – Inventories 83 Note G – Financing Arrangements and Debt 84 Note H – Asset Retirement Obligations 85 Note I – Income Taxes 85 Note J – Incentive Plans 88 Note K – Employee and Retiree Benefit Plans 91 Note L – Financial Instruments and Risk Management 97 Note M – Earnings per Share 99 Note N – Other Financial Information 99 Note O – Accumulated Other Comprehensive Loss 100 Note P – Assets and Liabilities Measured at Fair Value 100 Note Q – Commitments 102 Note R – Environmental and Other Contingencies 103 Note S – Common Stock Issued and Outstanding 104 Note T – Business Segments 104 Note U – Leases 106 Note V – Restructuring Charges 109 Supplemental Oil and Natural Gas Information (unaudited) 110 Supplemental Quarterly Information (unaudited) 127 2. Financial Statement Schedules Schedule II – Valuation Accounts and Reserves 128 58 Table of Contents 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 for the year ended December 31, 2018 2.4 Share Sale and Purchase Agreement between Canam Offshore Limited and PTTEP HK Offshore Limited for the sale and purchase of the entire issued share capital of Murphy Sarawak Oil Co., Ltd. and Murphy Sabah Oil Co., Ltd., dated March 21, 2019 Exhibit 10.3 to Form 10-Q filed May 2, 2019 3.1 Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005 Exhibit 3.1 to Form 10-K for the year ended December 31, 2010 3.2 By-Laws of Murphy Oil Corporation, as amended effective February 3, 2016 Exhibit 3.2 to Form 8-K filed February 5, 2016 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 for the year ended December 31, 2004 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 for the year ended December 31, 2004 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 First Supplemental Indenture dated as of May 18, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 4.00% Notes due 2022 Exhibit 4.2 to Form 8-K filed May 18, 2012 4.5 Second Supplemental Indenture dated as of November 30, 2012, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 3.70% Notes due 2022 and 5.125% notes due 2042 Exhibit 4.1 to Form 8-K filed November 30, 2012 4.6 Third Supplemental Indenture dated as of August 17, 2016, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 6.875% Notes due 2024 Exhibit 4.1 to Form 8-K filed August 17, 2016 4.7 Fourth Supplemental Indenture dated as of August 18, 2017, between Murphy Oil Corporation and U.S. Bank National Association, as trustee, relating to 5.75% Notes due 2025 Exhibit 4.1 to Form 8-K filed August 18, 2017 4.8 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 4.9 Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 Exhibit 4.9 to Form 10-K filed on February 27, 2020 59 Table of Contents 10.1 Credit Agreement dated as of November 28, 2018 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 10.4 to Form 10-K for the year ended December 31, 2018 10.2 Murphy Oil Corporation 2017 Annual Incentive Plan Exhibit A to definitive proxy statement filed March 28, 2016 *10.3 Murphy Oil Corporation Annual Incentive Plan 10.4 Murphy Oil Corporation 2012 Long-Term Incentive Plan Exhibit A to definitive proxy statement filed March 29, 2012 10.5 Amendment to the Murphy Oil Corporation 2012 Long-Term Incentive Plan Exhibit 10.8 to Form 10-K filed on February 27, 2020 10.6 Form of employee stock option (2012 Long-Term Plan) Exhibit 99.1 to Form 10-K for the year ended December 31, 2013 10.7 Form of employee performance-based restricted stock unit grant agreement (2012 Long-Term Plan) Exhibit 99.2 to Form 10-K for the year ended December 31, 2014 10.8 Form of stock appreciation right (2012 Long-Term Plan) Exhibit 99.3 to Form 10-Q filed May 7, 2014 10.9 Form of employee time-based restricted stock unit grant agreement (2012 Long-Term Plan) Exhibit 99.1 to Form 10-Q filed May 7, 2014 10.10 Form of employee time-based restricted stock unit-cash grant agreement (2012 Long-Term Plan) Exhibit 99.2 to Form 10-Q filed May 7, 2014 10.11 Murphy Oil Corporation 2018 Long-Term Incentive Plan Exhibit B to definitive proxy statement filed March 23, 2018 10.12 Amendment to the Murphy Oil Corporation 2018 Long-Term Incentive Plan Exhibit 10.15 to Form 10-K filed on February 27, 2020 10.13 Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Plan) Exhibit 10.14 to Form 10-K for the year ended December 31, 2018 10.14 Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Plan) Exhibit 10.17 to Form 10-K filed on February 27, 2020 10.15 Form of employee time-based restricted stock unit – stock settled 3-year grant agreement (2018 Long-Term Plan) Exhibit 10.15 to Form 10-K for the year ended December 31, 2018 10.16 Form of employee time-based restricted stock unit – stock settled 5-year grant agreement (2018 Long-Term Plan) Exhibit 10.16 to Form 10-K for the year ended December 31, 2018 10.17 Murphy Oil Corporation 2020 Long-Term Incentive Plan Exhibit A to definitive proxy statement filed March 30, 2020 10.18 Form of employee performance-based restricted stock unit – stock settled grant agreement (2020 LTI Plan) Exhibit 10.21 to Form 10-K filed on February 26, 2021 10.19 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 on February 26, 2021 10.20 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 on February 26, 2021 10.21 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 on February 26, 2021 10.22 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 on February 26, 2021 60 Table of Contents 10.23 Murphy Oil Corporation 2013 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 22, 2013 10.24 Form of non-employee director restricted stock unit award (2013 NED Plan) Exhibit 99.2 to Form 10-Q filed November 6, 2013 10.25 Murphy Oil Corporation 2018 Stock Plan for Non-Employee Directors Exhibit A to definitive proxy statement filed March 23, 2018 10.26 First Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.1 to Form 8-K filed April 25, 2018 10.27 Second Amendment to the 2018 Stock Plan for Non-Employee Directors Exhibit 10.24 to Form 10-K filed on February 27, 2020 10.28 Form of non-employee director restricted stock unit award – stock settled grant agreement (2018 NED Plan) Exhibit 10.20 to Form 10-K for the year ended December 31, 2018 10.29 Form of non-employee director restricted stock unit award – stock settled grant agreement (2018 NED Plan) Exhibit 10.26 to Form 10-K filed on February 27, 2020 10.30 Murphy Oil Corporation Non-Qualified Deferred Compensation Plan for Non-Employee Directors Exhibit 10.6 to Form 10-K for the year ended December 31, 2015 10.31 Tax Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc. Exhibit 10.1 to Form 8-K filed September 5, 2013 10.32 Employee Matters Agreement dated as of August 30, 2013, between Murphy Oil Corporation and Murphy USA Inc. Exhibit 10.3 to Form 8-K filed September 5, 2013 10.33 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 *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. *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 *99.1 Ryder Scott reserves audit report for Eagle Ford Shale and Gulf of Mexico *99.2 Ryder Scott reserves audit report for MP GOM JV *99.3 McDaniel independent audit report for Canada Onshore and Offshore proved crude oil and natural gas reserves 101.INS XBRL Instance Document 101.SCH XBRL Taxonomy Extension Schema Document 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF XBRL Taxonomy Extension Definition Linkbase Document 101.LAB XBRL Taxonomy Extension Labels Linkbase Document 101.PRE XBRL Taxonomy Extension Presentation Linkbase 61 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MURPHY OIL CORPORATION By /s/ ROGER W. JENKINS Date: February 25, 2022 Roger W. Jenkins, President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 25, 2022 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/ ROGER W. JENKINS /s/ R. MADISON MURPHY Roger W. Jenkins, President and Chief Executive Officer and Director (Principal Executive Officer) R. Madison Murphy, Director /s/ T. JAY COLLINS /s/ JEFFREY W. NOLAN T. Jay Collins, Director Jeffrey W. Nolan, Director /s/ STEVEN A. COSSE /s/ ROBERT N. RYAN, JR. Steven A. Cossé, Director Robert N. Ryan, Jr., Director /s/ LAWRENCE R. DICKERSON /s/ NEAL E. SCHMALE Lawrence R. Dickerson, Director Neal E. Schmale, Director /s/ MICHELLE A. EARLEY /s/ LAURA A. SUGG Michelle A. Earley, Director Laura A. Sugg, Director /s/ ELISABETH W. KELLER /s/ DAVID R. LOONEY Elisabeth W. Keller, Director David R. Looney, Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/ CHRISTOPHER D. HULSE Christopher D. Hulse Vice President and Controller (Principal Accounting Officer) 62 Table of Conten ts 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 64. 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, 2021. KPMG LLP has performed an audit of the Company’s internal control over financial reporting, and their opinion thereon can be found on page 67. 63 Table of Conten ts 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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2022 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 Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. 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 independent assessment. For the year ended 64 Table of Conten ts December 31, 2021, the Company recorded depreciation, depletion, and amortization expense of $795.1 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. Evaluation of the realizability of deferred tax assets As discussed in Note I to the consolidated financial statements, the Company had gross deferred tax assets of $1,147.1 million, which includes a deferred tax asset for U.S. net operating losses of $577.5 million, as of December 31, 2021. A valuation allowance is provided for deferred tax assets if it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period, which is dependent upon the generation of taxable income. We identified the evaluation of the realizability of deferred tax assets as a critical audit matter. The evaluation of the realizability of deferred tax assets, especially those related to U.S. net operating loss carryforwards, required subjective auditor judgment to assess the application of tax laws and the projections of future taxable income over the periods in which those temporary differences become deductible. Changes in assumptions regarding future taxable income could have a significant impact on the Company’s evaluation of the realizability of the deferred tax assets. 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 related to the Company’s evaluation of the realizability of deferred tax assets, including controls related to the application of tax laws and the development of projections of future taxable income. We evaluated the assumptions used in the development of projected future taxable income by comparing such assumptions to estimated oil and gas reserve quantities developed by the Company, by comparing projected cost estimates to historical actual costs, and by comparing future commodity prices used in the determination of projected future taxable income to external sources. We also evaluated the Company’s history of realizing deferred tax assets by evaluating the expiration of net operating loss carryforwards and testing the reversal pattern of taxable temporary differences. We involved income tax professionals with specialized skills and knowledge who assisted in assessing the Company’s application of tax laws. Assessment of recoverability of property, plant, and equipment related to oil and gas properties As described in Note A to the consolidated financial statements, the Company reviews their oil and gas properties for triggering events that would indicate potential impairment. The Company analyzes 65 Table of Conten ts indicators for possible triggers of impairment such as a significant reduction in sales prices for oil or natural gas, unfavorable revisions of oil or natural gas reserves, changes to contracts, environmental regulations, tax law or other regulatory changes. If a triggering event is identified in relation to one or more properties, an undiscounted cash flow analysis is required to quantitatively evaluate recoverability. The Company compares estimated future net cash flows expected in connection with the property to the carrying amount of the property to determine if the carrying amount is recoverable or if further quantitative analysis is required. We identified the assessment of recoverability of property, plant, and equipment related to oil and gas properties as a critical audit matter. There is a high degree of subjectivity in performing procedures due to the uncertainty associated with future commodity prices and estimated oil and gas reserves used in the Company’s assessment. The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s property, plant, and equipment process for oil and gas properties including controls over the Company’s triggering event assessment process and oil and gas reserve estimation process. We compared future commodity price assumptions to publicly available market information. We assessed the competence, capabilities, and objectivity of the Company’s internal petroleum reserve engineers, who estimated the oil and gas reserves, and the third-party reserve specialists engaged by the Company to evaluate the estimated proved oil and gas reserves. /s/ KPMG LLP We have served as the Company’s auditor since 1952. Houston, Texas February 25, 2022 66 Table of Conten ts REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and 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, 2021, 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, 2021, 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, 2021 and 2020, 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, 2021, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 25, 2022 expressed an unqualified opinion on those consolidated financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management - Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ KPMG LLP Houston, Texas February 25, 2022 67 Table of Conten ts MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31 (Thousands of dollars except share amounts) 2021 2020 ASSETS Current assets Cash and cash equivalents $ 521,184 310,606 Accounts receivable, net 258,150 262,014 Inventories Note F 54,198 66,076 Prepaid expenses 31,925 33,860 Assets held for sale Note E 15,453 327,736 Total current assets 880,910 1,000,292 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ 12,457,851 in 2021 and $ 11,455,305 in 2020 Note D 8,127,852 8,269,038 Operating lease assets Note U 881,389 927,658 Deferred income taxes Note I 385,516 395,253 Deferred charges and other assets 29,273 28,611 Total assets $ 10,304,940 10,620,852 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 654 — Accounts payable 623,129 407,097 Income taxes payable 19,951 18,018 Other taxes payable 20,306 22,498 Operating lease liabilities 139,427 103,758 Other accrued liabilities 360,859 150,578 Liabilities associated with assets held for sale Note E — 14,372 Total current liabilities 1,164,326 716,321 Long-term debt, including finance lease obligation Note G 2,465,414 2,988,067 Asset retirement obligations Note H 839,776 816,308 Deferred credits and other liabilities 570,574 680,580 Non-current operating lease liabilities Note U 761,162 845,088 Deferred income taxes Note I 182,892 180,341 Total liabilities 5,984,144 6,226,705 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 2021 and 195,100,628 shares in 2020 195,101 195,101 Capital in excess of par value 926,698 941,692 Retained earnings 5,218,670 5,369,538 Accumulated other comprehensive loss Note O ( 527,711 ) ( 601,333 ) Treasury stock ( 1,655,447 ) ( 1,690,661 ) Murphy Shareholders' Equity 4,157,311 4,214,337 Noncontrolling interest 163,485 179,810 Total equity 4,320,796 4,394,147 Total liabilities and equity $ 10,304,940 10,620,852 See Notes to Consolidated Financial Statements, page 73. 68 Table of Conten ts MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31 (Thousands of dollars except per share amounts) 2021 2020 2019 Revenues and other income Revenue from sales to customers $ 2,801,215 1,751,709 2,817,111 (Loss) gain on derivative instruments ( 525,850 ) 202,661 ( 856 ) Gain on sale of assets and other income 23,916 12,971 12,798 Total revenues and other income 2,299,281 1,967,341 2,829,053 Costs and expenses Lease operating expenses 539,546 600,076 605,180 Severance and ad valorem taxes 41,212 28,526 47,959 Transportation, gathering and processing 187,028 172,399 176,315 Exploration expenses, including undeveloped lease amortization 69,044 86,479 95,105 Selling and general expenses 121,950 140,243 232,736 Restructuring expenses — 49,994 — Depreciation, depletion and amortization 795,105 987,239 1,147,842 Accretion of asset retirement obligations 46,613 42,136 40,506 Impairment of assets 196,296 1,206,284 — Other (benefit) expense 21,052 16,274 38,117 Total costs and expenses 2,017,846 3,329,650 2,383,760 Operating income (loss) from continuing operations 281,435 ( 1,362,309 ) 445,293 Other income (loss) Interest income and other (loss) ( 16,771 ) ( 17,303 ) ( 22,520 ) Interest expense, net ( 221,773 ) ( 169,423 ) ( 219,275 ) Total other loss ( 238,544 ) ( 186,726 ) ( 241,795 ) Income (loss) from continuing operations before income taxes 42,891 ( 1,549,035 ) 203,498 Income tax expense (benefit) ( 5,862 ) ( 293,741 ) 14,683 Income (loss) from continuing operations 48,753 ( 1,255,294 ) 188,815 Income (loss) from discontinued operations, net of income taxes ( 1,225 ) ( 7,151 ) 1,064,487 Net income (loss) including noncontrolling interest 47,528 ( 1,262,445 ) 1,253,302 Less: Net income (loss) attributable to noncontrolling interest 121,192 ( 113,668 ) 103,570 NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ ( 73,664 ) ( 1,148,777 ) 1,149,732 INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ ( 0.47 ) ( 7.43 ) 0.52 Discontinued operations ( 0.01 ) ( 0.05 ) 6.49 Net income (loss) $ ( 0.48 ) ( 7.48 ) 7.01 INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ ( 0.47 ) ( 7.43 ) 0.52 Discontinued operations ( 0.01 ) ( 0.05 ) 6.46 Net income (loss) $ ( 0.48 ) ( 7.48 ) 6.98 Cash dividends per Common share $ 0.50 0.625 1.00 Average Common shares outstanding (thousands) Basic 154,291 153,507 163,992 Diluted 154,291 153,507 164,812 See Notes to Consolidated Financial Statements, page 73. 69 Table of Conten ts MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Years Ended December 31 (Thousands of dollars) 2021 2020 2019 Net income (loss) including noncontrolling interest $ 47,528 ( 1,262,445 ) 1,253,302 Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation 12,116 29,241 66,600 Retirement and postretirement benefit plans 59,816 ( 57,617 ) ( 35,979 ) Deferred loss on interest rate hedges reclassified to interest expense 1,690 1,204 5,005 Other comprehensive income (loss) 73,622 ( 27,172 ) 35,626 Comprehensive income (loss) 121,150 ( 1,289,617 ) 1,288,928 Comprehensive income (loss) attributable to noncontrolling interest ( 121,192 ) 113,668 ( 103,570 ) COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ ( 42 ) ( 1,175,949 ) 1,185,358 See Notes to Consolidated Financial Statements, page 73. 70 Table of Conten ts MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31 (Thousands of dollars) 2021 2020 2019 Operating Activities Net income (loss) including noncontrolling interest $ 47,528 ( 1,262,445 ) 1,253,302 Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities Depreciation, depletion and amortization 795,105 987,239 1,147,842 Impairment of assets 196,296 1,206,284 — Mark to market loss on derivative instruments 112,113 69,310 33,364 Mark to market loss (gain) on contingent consideration 63,147 ( 13,783 ) 8,672 Long-term non-cash compensation 63,382 46,558 76,958 Accretion of asset retirement obligations 46,613 42,136 40,506 Amortization of undeveloped leases 18,925 26,743 27,973 Previously suspended exploration costs 17,339 21,099 12,840 Deferred income tax (benefit) expense ( 4,146 ) ( 278,042 ) 28,530 Loss (income) from discontinued operations 1,225 7,151 ( 1,064,487 ) Net decrease (increase) in noncash working capital 118,457 ( 32,027 ) ( 16,887 ) Other operating activities, net ( 53,821 ) ( 35,080 ) ( 59,508 ) Noncash restructuring expense — 17,565 — Net cash provided by continuing operations activities 1,422,163 802,708 1,489,105 Investing Activities Property additions and dry hole costs ( 670,479 ) ( 759,809 ) ( 1,244,069 ) Proceeds from sales of property, plant and equipment 270,503 13,750 20,382 Property additions for King's Quay FPS ( 17,734 ) ( 112,961 ) ( 100,202 ) Acquisition of oil and natural gas properties — — ( 1,212,315 ) Net cash required by investing activities ( 417,710 ) ( 859,020 ) ( 2,536,204 ) Financing Activities Retirement of debt ( 876,358 ) ( 12,225 ) ( 521,332 ) Debt issuance, net of cost 541,913 ( 613 ) 542,394 Repayment of revolving credit facility ( 365,000 ) ( 250,000 ) ( 2,050,000 ) Borrowings on revolving credit facility 165,000 450,000 1,725,000 Distributions to noncontrolling interest ( 137,517 ) ( 43,673 ) ( 128,158 ) Cash dividends paid ( 77,204 ) ( 95,989 ) ( 163,669 ) Early redemption of debt cost ( 39,335 ) — ( 26,626 ) Withholding tax on stock-based incentive awards ( 5,209 ) ( 7,094 ) ( 6,991 ) Capital lease obligation payments ( 803 ) ( 695 ) ( 688 ) Repurchase of common stock — — ( 499,924 ) Net cash (required) provided by financing activities ( 794,513 ) 39,711 ( 1,129,994 ) Cash Flows from Discontinued Operations 1 Operating activities — ( 1,202 ) 73,783 Investing activities — 4,494 2,022,034 Financing activities — — ( 4,914 ) Net cash provided by discontinued operations — 3,292 2,090,903 Cash from discontinued operations — 18,438 2,120,397 Effect of exchange rate changes on cash and cash equivalents 638 2,009 3,533 Net increase in cash and cash equivalents 210,578 3,846 ( 53,163 ) Cash and cash equivalents at beginning of period 310,606 306,760 359,923 Cash and cash equivalents at end of period $ 521,184 310,606 306,760 1 Net cash provided by discontinued operations are not part of the cash flow reconciliation. See Notes to Consolidated Financial Statements, page 73. 71 Table of Conten ts MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Years Ended December 31 (Thousands of dollars except number of shares) 2021 2020 2019 Cumulative Preferred Stock – par $ 100 , authorized 400,000 shares, none issued $ — — — Common Stock – par $ 1.00 , authorized 450,000,000 shares at December 31, 2021, 2020 and 2019, issued 195,100,628 at December 31, 2021, 195,100,628 shares at December 31, 2020 and 195,089,269 at December 31, 2019 Balance at beginning of year 195,101 195,089 195,077 Exercise of stock options — 12 12 Balance at end of year 195,101 195,101 195,089 Capital in Excess of Par Value Balance at beginning of year 941,692 949,445 979,642 Stock-based compensation 25,429 26,052 33,235 Restricted stock transactions and other ( 38,749 ) ( 33,649 ) ( 38,731 ) Exercise of stock options, including income tax benefits ( 1,674 ) ( 156 ) ( 182 ) Fair value increase in common controlled assets — — ( 24,519 ) Balance at end of year 926,698 941,692 949,445 Retained Earnings Balance at beginning of year 5,369,538 6,614,304 5,513,529 Net income (loss) for the year attributable to Murphy ( 73,664 ) ( 1,148,777 ) 1,149,732 Cash dividends ( 77,204 ) ( 95,989 ) ( 163,669 ) Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact — — 114,712 Balance at end of year 5,218,670 5,369,538 6,614,304 Accumulated Other Comprehensive Loss Balance at beginning of year ( 601,333 ) ( 574,161 ) ( 609,787 ) Foreign currency translation gains (losses), net of income taxes 12,116 29,241 66,600 Retirement and postretirement benefit plans, net of income taxes 59,816 ( 57,617 ) ( 35,979 ) Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes 1,690 1,204 5,005 Balance at end of year ( 527,711 ) ( 601,333 ) ( 574,161 ) Treasury Stock Balance at beginning of year ( 1,690,661 ) ( 1,717,217 ) ( 1,249,162 ) Awarded restricted stock, net of forfeitures 33,888 26,556 31,869 Exercise of stock options 1,326 — — Purchase of treasury shares — — ( 499,924 ) Balance at end of year – 40,637,578 of Common Stock in 2021, 41,502,003 shares of Common Stock in 2020, and 42,153,908 shares of Common Stock in 2019 ( 1,655,447 ) ( 1,690,661 ) ( 1,717,217 ) Murphy Shareholders’ Equity 4,157,311 4,214,337 5,467,460 Noncontrolling Interest Balance at beginning of year 179,810 337,151 368,343 Net income (loss) attributable to noncontrolling interest 121,192 ( 113,668 ) 103,570 Distributions to noncontrolling interest owners ( 137,517 ) ( 43,673 ) ( 128,158 ) Acquisition closing adjustments — — ( 6,604 ) Balance at end of year 163,485 179,810 337,151 Total Equity $ 4,320,796 4,394,147 5,804,611 See Notes to Consolidated Financial Statements, page 73. 72 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS These notes are an integral part of the consolidated financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 68-72 of the Form 10-K report. Note A – Significant Accounting Polices 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 United States and Canada and conducts oil and natural gas exploration activities worldwide. The Company sold its Malaysian assets in 2019, and they are reported as discontinued operations. In connection with the LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) acquisition, we hold a 0.5 % interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House Floating Production System (FPS) LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of December 31, 2021, our maximum exposure to loss was $ 3.4 million (excluding operational impacts), which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest. PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. 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. Beginning in the fourth quarter of 2018, Murphy reports 100 % of the sales volume, revenues, costs, assets and liabilities including the 20 % noncontrolling interest (NCI), of MP GOM in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45. Other investments are generally carried at cost. Intercompany accounts and transactions are eliminated. REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties in which Murphy shares in the undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2021 and 2020, 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. 73 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Contd.) ACCOUNTS RECEIVABLE – At December 31, 2021 and 2020, 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. 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. 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 includes 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 F . 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 major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such 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 recognized when there are indications 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 fair value. In 2021 and 2020, the Company recognized pretax noncash impairment charges of $ 196.3 million and $ 1,206.3 million, respectively, to reduce the carrying values at select properties. In 2021, the Company recorded an impairment charge of $ 171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans and $ 25.0 million for assets reported as Assets held for sale in the Consolidated Balance Sheets. See also Note D for further discussion of impairment charges. The Company records a liability for asset retirement obligations (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 and site restoration are charged against the related liability. See Note H . Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. 74 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Contd.) 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. 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 Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets (related to Brunei) are presented on the Consolidated Balance Sheet within Property, plant and equipment with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt. 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, or 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 based on 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. 75 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Contd.) 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 decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk. 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 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 P . 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 that are equity settled and expense is recognized over the three -year vesting period. The fair value of time-lapse restricted stock units 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 performance-based restricted stock units 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 (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are 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 SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note J . 76 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note A – Significant Accounting Policies (Contd.) 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 K . NET INCOME (LOSS) PER COMMON SHARE – Basic 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. USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates. Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years ending after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company adopted the standard in the fourth quarter of 2020, and it did not have a material impact on its consolidated financial statements. Financial Instruments – Credit Losses. In June 2016, the FASB issued Accounting Standards Update (ASU) 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020, and it did not have a material impact on its consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020, and it did not have a material impact on its consolidated financial statements. Income Taxes . In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. The Company adopted this guidance in the first quarter of 2021, and it did not have a material impact on its consolidated financial statements. Recent Accounting Pronouncements None affecting the Company. 77 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note C – Revenue from Contracts with Customers Nature of Goods and Services The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are 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 and condensate, natural gas liquids, and natural gas. For operated oil and gas production where the 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 U.S. GAAP. U.S. - In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are 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. Disaggregation of Revenue The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies. 78 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note C – Revenue from Contracts with Customers (Contd.) For the years ended December 31, 2021, 2020, and 2019 the Company recognized $ 2,801.2 million, $ 1,751.7 million and $ 2,817.1 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. Years Ended December 31, (Thousands of dollars) 2021 2020 2019 Net crude oil and condensate revenue United States Onshore $ 626,136 353,311 750,278 Offshore 1,478,993 940,265 1,477,816 Canada Onshore 119,799 93,591 116,174 Offshore 92,741 71,495 159,254 Other 4,924 1,806 11,642 Total crude oil and condensate revenue 2,322,593 1,460,468 2,515,164 Net natural gas liquids revenue United States Onshore 50,189 22,504 30,615 Offshore 44,411 19,749 26,968 Canada Onshore 16,375 8,921 12,001 Total natural gas liquids revenue 110,975 51,174 69,584 Net natural gas revenue United States Onshore 39,803 20,132 27,668 Offshore 81,944 49,300 46,259 Canada Onshore 245,900 170,635 158,436 Total natural gas revenue 367,647 240,067 232,363 Total revenue from contracts with customers 1 2,801,215 1,751,709 2,817,111 Gain (loss) on crude contracts ( 525,850 ) 202,661 ( 856 ) Gain on sale of assets and other income 2 23,916 12,971 12,798 Total revenue and other income $ 2,299,281 1,967,341 2,829,053 1 Includes revenue attributable to noncontrolling interest in MP GOM. 2 Gain on sale of Malaysia operations of $ 985.4 million in 2019 is reported in discontinued operations. See Note E . Contract Balances and Asset Recognition As of December 31, 2021 and 2020, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 169.8 million and $ 135.2 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, 2021, 2020 or 2019. 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. 79 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note C – Revenue from Contracts with Customers (Contd.) Performance Obligations The Company recognizes oil and 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, 2021, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract: Current Long-Term Contracts Outstanding at December 31, 2021 Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGL Q1 2023 Deliveries from dedicated acreage in Eagle Ford As produced Canada Natural Gas Q4 2022 Contracts to sell natural gas at USD index pricing 8 MMCFD Canada Natural Gas Q4 2022 Contracts to sell natural gas at CAD fixed prices 5 MMCFD Canada Natural Gas Q4 2022 Contracts to sell natural gas at USD fixed pricing 20 MMCFD Canada Natural Gas Q4 2023 Contracts to sell natural gas at USD index pricing 25 MMCFD Canada Natural Gas Q4 2023 1 Contracts to sell natural gas at CAD fixed prices 38 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD index pricing 31 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD fixed prices 100 MMCFD Canada Natural Gas Q4 2024 1 Contracts to sell natural gas at CAD fixed prices 34 MMCFD Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD fixed pricing 15 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCFD Canada NGL Q3 2023 Contracts to sell natural gas liquids at CAD pricing 952 MMCFD 1 These contracts are scheduled to commence after the balance sheet date, during Q1 2022. Fixed price contracts are accounted for as normal sales and purchases for accounting purposes. 80 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D – Property, Plant and Equipment December 31, 2021 December 31, 2020 (Thousands of dollars) Cost Net Cost Net Exploration and production ¹ $ 20,440,568 8,098,396 2 19,583,682 8,232,191 2 Corporate and other 145,135 29,456 140,661 36,847 Property, plant and equipment $ 20,585,703 8,127,852 19,724,343 8,269,038 ¹ Includes unproved mineral rights as follows: $ 615,724 131,107 649,704 530,194 2 Includes $ 22,543 in 2021 and $ 22,940 in 2020 related to administrative assets and support equipment. Divestments In March 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $ 267.7 million, which reimburses the Company for previously incurred capital expenditures. In 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $ 2.0 billion. A gain on sale of $ 985.4 million was recorded as part of discontinued operations on the Consolidated Statement of Operations in 2019. Murphy was entitled to receive a $ 100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020; however, the results were not achieved. Acquisitions In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG). Under the terms of the transaction, Murphy paid cash consideration of $ 1,236.2 million and has an obligation to pay additional contingent consideration of up to $ 200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $ 50.0 million following first oil from certain development projects. The revenue threshold was not exceeded for 2019 or 2020; however, the threshold was met in 2021. In 2018, the Company, through a subsidiary, acquired all of the Gulf of Mexico producing assets from Petrobras America Inc. (PAI), a subsidiary of Petrobras. Under the terms of the transaction, Murphy paid cash consideration of $ 780.7 million and has an obligation to pay additional contingent consideration of up to $ 150.0 million if certain price and production thresholds are exceeded beginning in 2019 through 2025; and $ 50.0 million carry for PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. The price and production thresholds were not exceeded for 2019 and 2020; however, the thresholds were met in 2021. As of December 31, 2021, Murphy had completely funded the carried interest. Impairments During the first quarter of 2021, the Company recorded an impairment charge of $ 171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans. Subsequently, the Company acquired an additional 7.525 % working interest at Terra Nova following a commercial agreement to sanction an asset life extension project. In the fourth quarter of 2021, the Company recorded an impairment charge of $ 25.0 million for assets reported as Assets held for sale in the Consolidated Balance Sheet. In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $ 1,206.3 million to reduce the carrying values of certain properties to their estimated fair values at the time of impairment. 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. 81 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note D - Property, Plant and Equipment (Contd.) The following table reflects the recognized before tax impairments for the three years ended December 31, 2021. December 31, (Thousands of dollars) 2021 2020 2019 Canada $ 171,296 — — Other Foreign 18,000 39,709 — Corporate 7,000 14,060 — U.S. — 1,152,515 — $ 196,296 1,206,284 — 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, 2021, 2020 and 2019, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 179.5 million, $ 181.6 million and $ 217.3 million, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2021. ( Thousands of dollars ) 2021 2020 2019 Beginning balance at January 1 $ 181,616 217,326 207,855 Additions pending the determination of proved reserves 16,725 3,999 83,712 Reclassifications to proved properties based on the determination of proved reserves — — ( 61,096 ) Capitalized exploration well costs charged to expense ( 18,860 ) ( 39,709 ) ( 13,145 ) Ending balance at December 31 $ 179,481 181,616 217,326 The capitalized well costs charged to expense during 2021 and 2020 principally represent charges for asset impairments (see above). The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs has been capitalized. The projects are aged based on the last well drilled in the project. 2021 2020 2019 ( Thousands of dollars ) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Aging of capitalized well costs: Zero to one year $ 13,273 3 3 $ — — — $ 63,409 5 5 One to two years — — — 54,220 5 5 — — — Two to three years 53,070 5 5 — — — 27,396 1 — Three years or more 113,138 6 — 127,396 6 — 126,521 5 — $ 179,481 14 8 $ 181,616 11 5 $ 217,326 11 5 Of the $ 166.2 million of exploratory well costs capitalized more than one year at December 31, 2021, $ 93.1 million is in Vietnam, $ 45.0 million is in the U.S., $ 7.9 million is in Brunei, $ 15.3 million is in Mexico, and $ 4.8 million is in Canada. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 82 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note E – Assets Held for Sale and Discontinued Operations The following table presents the carrying value of the major categories of assets and liabilities that are reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2021 and 2020. As of December 31, 2021, these include the net property, plant equipment of the CA-2 project in Brunei and the Company’s office building in El Dorado, Arkansas. The Company’s CA-1 asset in Brunei is no longer being marketed for sale. As of December 31, 2020, the balance also included $ 250.1 million for the King’s Quay Floating Production System (FPS), which was sold in March 2021 (see Note D ). ( Thousands of dollars ) 2021 2020 Current assets Cash $ — 10,185 Inventories — 406 Property, plant, and equipment, net 15,453 307,704 Deferred income taxes and other assets — 9,441 Total current assets associated with assets held for sale 15,453 327,736 Current liabilities Accounts payable — 5,306 Other accrued liabilities — 45 Current maturities of long-term debt (finance lease) — 737 Taxes payable — 1,510 Asset retirement obligation — 261 Long-term debt (finance lease) — 6,513 Total current liabilities associated with assets held for sale $ — 14,372 The Company has accounted for its former Malaysian exploration and production operations and its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations are presented in the following table. ( Thousands of dollars ) 2021 2020 2019 Revenues 1 $ 795 4,090 1,364,943 Costs and expenses Lease operating expense — — 127,138 Depreciation, depletion and amortization — — 33,697 Other costs and expenses (benefits) 2,020 11,241 81,538 Total income from discontinued operations before taxes ( 1,225 ) ( 7,151 ) 1,122,570 Income tax expense — — 58,083 Income from discontinued operations $ ( 1,225 ) ( 7,151 ) 1,064,487 1 2019 includes a $ 985.4 million gain on sale of the Malaysia operations. Note F – Inventories Inventories consisted of the following at December 31, 2021 and 2020: December 31, ( Thousands of dollars ) 2021 2020 Unsold crude oil $ 15,497 16,399 Materials and supplies 38,701 49,677 Inventories $ 54,198 66,076 83 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note G – Financing Arrangements and Debt As of December 31, 2021, the Company has a $ 1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At December 31, 2021, the Company had no outstanding borrowings under the RCF and $ 31.4 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF. At December 31, 2021, the interest rate in effect on borrowings under the facility would have been 1.78 %. At December 31, 2021, the Company was in compliance with all covenants related to the RCF. In March 2021, the Company issued $ 550.0 million of new notes that bear interest at a rate of 6.375 % and mature on July 15, 2028. The Company incurred transaction costs of $ 8.1 million on the issuance of these new notes and the Company will pay interest semi-annually on January 15 and July 15 of each year. The proceeds of the $ 550.0 million notes, along with cash on hand, were used to redeem and cancel $ 259.3 million of the Company’s 4.00 % notes due June 2022 and $ 317.1 million of the Company’s 4.95 % notes due December 2022 (originally issued as 3.70 % notes due 2022; collectively the 2022 Notes). The cost of the debt extinguishment of $ 36.9 million is included in Interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2021. The cash costs of $ 34.2 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2021. In August 2021, the Company redeemed $ 150.0 million aggregate principal amount of its 6.875 % senior notes due 2024 (2024 Notes). The cost of the debt extinguishment of $ 3.5 million is included in Interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2021. The cash costs of $ 2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2021. In December 2021, the Company redeemed an additional $ 150.0 million aggregate principal amount of the 2024 Notes. The cost of the debt extinguishment of $ 3.4 million is included in Interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2021. The cash costs of $ 2.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2021. Long-term debt consisted of the following as of December 31, 2021 and 2020: December 31, (Thousands of dollars) 2021 2020 Notes payable 4.00 % notes, due June 2022 $ — 259,291 4.95 % notes, due December 2022 ¹ — 317,067 6.875 % notes, due August 2024 242,428 542,428 5.75 % notes, due August 2025 548,675 548,675 5.875 % notes, due December 2027 543,249 543,249 6.375 % notes, due July 2028 550,000 — 7.05 % notes, due May 2029 250,000 250,000 6.375 % notes, due December 2042 ¹ 349,000 349,000 Total notes payable 2,483,352 2,809,710 Unamortized debt issuance cost and discount on notes payable ( 22,773 ) ( 21,643 ) Total notes payable, net of unamortized discount 2,460,579 2,788,067 Capitalized lease obligation, due through March 2029 ¹ 5,489 — Total debt including current maturities 2,466,068 2,788,067 Senior Unsecured Revolving Credit Facility — 200,000 Current maturities ( 654 ) — Total long-term debt $ 2,465,414 2,988,067 1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s. 84 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note G - Financing Arrangements and Long-Term Debt (Contd.) The amount of long-term debt repayable over each of the next five years and thereafter are as follows: nil in 2022, nil in 2023, $ 242.4 million in 2024, $ 548.7 million in 2025, nil in 2026 and $ 1.69 billion thereafter. The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 15, 2024. Note H – Asset Retirement Obligations The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2021 and 2020 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 asset retirement obligation for 2021 and 2020 is shown in the following table. (Thousands of dollars) 2021 2020 Balance at beginning of year $ 849,956 865,109 Accretion expense 46,613 42,136 Liabilities incurred 54,439 14,736 Revisions of previous estimates 48,737 ( 70,098 ) Liabilities settled ( 27,824 ) ( 4,816 ) Liabilities associated with assets held for sale 263 ( 21 ) Changes due to translation of foreign currencies ( 291 ) 2,910 Balance at end of year 971,893 849,956 Current portion of liability at end of year ¹ ( 132,117 ) ( 33,648 ) Noncurrent portion of liability at end of year $ 839,776 816,308 1 Included in Other accrued liabilities on the Consolidated Balance Sheets. 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 I – 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 ) 2021 2020 2019 Income (loss) from continuing operations before income taxes United States $ 114,659 ( 1,407,598 ) 282,199 Foreign ( 71,768 ) ( 141,437 ) ( 78,701 ) Total $ 42,891 ( 1,549,035 ) 203,498 Income tax expense (benefit) U.S. Federal – Current $ — ( 10,627 ) — – Deferred ( 1,480 ) ( 249,253 ) 30,598 Total U.S. Federal ( 1,480 ) ( 259,880 ) 30,598 State 3,303 ( 8,413 ) 5,139 Foreign – Current ( 5,158 ) ( 5,072 ) ( 17,823 ) – Deferred ( 2,527 ) ( 20,376 ) ( 3,231 ) Total Foreign ( 7,685 ) ( 25,448 ) ( 21,054 ) Total $ ( 5,862 ) ( 293,741 ) 14,683 85 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Income Taxes (Contd.) The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense. ( Thousands of dollars ) 2021 2020 2019 Income tax expense (benefit) based on the U.S. statutory tax rate $ 9,007 ( 325,299 ) 42,735 Alberta tax rate reduction and tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform) — — ( 17,019 ) Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 13,270 ( 3,791 ) ( 1,122 ) State income taxes, net of federal benefit 2,500 ( 6,646 ) 4,060 U.S. tax benefit on certain foreign upstream investments ( 8,916 ) — ( 14,975 ) Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures 4,814 7,707 10,927 Tax effect on income attributable to noncontrolling interest ( 25,450 ) 23,712 ( 21,750 ) Other, net ( 1,087 ) 10,576 11,827 Total $ ( 5,862 ) ( 293,741 ) 14,683 An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2021 and 2020 showing the tax effects of significant temporary differences follows. ( Thousands of dollars ) 2021 2020 Deferred tax assets Property and leasehold costs $ 241,833 95,141 Liabilities for dismantlements 37,728 28,475 Postretirement and other employee benefits 114,790 128,281 U. S. net operating loss 577,531 589,067 Investment in partnership 39,396 65,216 Other deferred tax assets 135,838 112,685 Total gross deferred tax assets 1,147,116 1,018,865 Less valuation allowance ( 111,259 ) ( 106,448 ) Net deferred tax assets 1,035,857 912,417 Deferred tax liabilities Deferred tax on undistributed foreign earnings ( 5,000 ) ( 5,000 ) Accumulated depreciation, depletion and amortization ( 786,846 ) ( 665,255 ) Other deferred tax liabilities ( 41,387 ) ( 27,250 ) Total gross deferred tax liabilities ( 833,233 ) ( 697,505 ) Net deferred tax (liabilities) assets $ 202,624 214,912 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 relate 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 $ 4.8 million in 2021, 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 an estimated U.S. net operating loss of $ 2.75 billion at year-end 2021 with a corresponding deferred tax asset of $ 577.5 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. 86 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note I – Income Taxes (Contd.) 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, 2021, $ 1.4 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 Deferred credits and other liabilities in the Consolidated Balance Sheets. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table. ( Thousands of dollars ) 2021 2020 2019 Balance at January 1 $ 2,832 2,538 2,903 Additions for tax positions related to current year 71 3,042 456 Settlements due to lapse of time — — ( 821 ) Settlements with taxing authorities — ( 2,748 ) — Balance at December 31 $ 2,903 2,832 2,538 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 as of December 31, 2021, 2020 and 2019 for interest and penalties of $ 0.3 million, $ 0.3 million and $ 0.1 million, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2021, 2020 and 2019 included net benefits for interest and penalties of nil , $ 0.1 million and $ 0.1 million, respectively, associated with uncertain tax positions. In 2022, the Company currently expects to add between $ 0.1 million and $ 1.0 million to the provision for uncertain tax positions. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, 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 2022. 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, 2021, 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 – 2014. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate. Coronavirus Aid, Relief, and Economic Security Act In the fourth quarter of 2020, under the provisions of the Coronavirus Aid, Relief, and Economic Security (CARES) Act, the Company received a refund of its remaining outstanding AMT credit balance of approximately $ 18.5 million. 87 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – 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 share-based awards that settle in cash 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 2017 Annual Incentive Plan (2017 AIP), the 2012 Long-Term Incentive Plan (2012 Long-Term Plan), the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) and the 2020 Long-Term Incentive Plan (2020 Long-Term Plan). The 2017 AIP authorizes the Executive 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 2017 Annual Incentive Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. the 2017 AIP expired on December 31, 2021 and has been replaced with the 2022 Annual Incentive Plan, effective January 1, 2022. 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), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), 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, 3.48 million shares are available for grant under the 2020 Long-Term Plan at December 31, 2021. At the Company’s annual stockholders’ meeting held on May 12, 2021, shareholders approved the replacement of the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) with the 2021 Stock Plan for Non-Employee Directors (2021 NED Plan). The 2021 NED Plan permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 NED Plan. 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 future stock option exercises and vesting of restricted stock and restricted stock units. Amounts recognized in the financial statements with respect to share-based plans are shown in the following table: ( Thousands of dollars ) 2021 2020 2019 Compensation charged against income (loss) before income tax benefit $ 43,660 24,812 50,170 Related income tax benefit recognized in income 7,196 2,672 7,389 As of December 31, 2021, there were $ 45.8 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 restricted stock award. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the years ended December 31, 2021, 2020 and 2019. Equity-Settled Awards PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based restricted stock units (PSUs) to be settled in Common shares were granted in 2021 under the 2020 Long-Term Plan and 2020 and 2019 under the 88 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Incentive Plans (Contd.) 2018 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 recognized compensation cost associated with the stock award would not be reversed. For PSUs, the performance conditions are based on the Company’s total shareholder return ( 80 % weighting), compared to an industry peer group of companies, and the EBITDA divided by Average Capital Employed (ACE) metric ( 20 % weighting) for PSU awards beginning in 2020, over the performance period. 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. Changes in PSUs outstanding for each of the last three years are presented in the following table. ( Number of stock units ) 2021 2020 2019 Outstanding at beginning of year 2,207,429 2,129,733 1,660,417 Granted 1,156,800 999,700 957,600 Vested and issued ( 642,473 ) ( 429,194 ) ( 331,917 ) Forfeited ( 51,000 ) ( 492,810 ) ( 156,367 ) Outstanding at end of year 2,670,756 2,207,429 2,129,733 The fair value of the equity-settled performance-based awards granted in each year 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 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 2021, 2020 and 2019 are presented in the following table. 2021 2020 2019 Fair value per share at grant date $ 16.03 $ 21.51 $ 28.09 Assumptions Expected volatility 74.00 % 39.00 % 46.00 % Risk-free interest rate 0.18 % 1.40 % 2.50 % Stock beta 1.169 0.864 1.037 Expected life 3.0 years 3.0 years 3.0 years TIME-BASED RESTRICTED STOCK UNITS – Time-based restricted stock units (RSUs) have been granted to the Company’s Non-Employee Directors (NED) under the 2018 NED Plan and 2021 NED Plan and to certain employees under the 2012 Long-Term Plan, 2018 Long-Term Plan and 2020 Long-Term Plan. The fair value of the time-based restricted stock units awarded in 2021, 2020 and 2019 are presented in the following table. Type of Plan Valuation Methodology 2021 2020 2019 Non-Employee Directors 1, 2 Closing Stock Price at Grant Date $ 13.14 - 23.58 $ 22.59 $ 21.68 Long-Term Incentive Plan 3 Average High/Low Stock Price at Grant Date $ 12.30 $ 21.68 $ 28.16 1 Under the 2018 NED Plan, the RSUs granted in 2019 vest on the third anniversary of the date of grant and the RSUs granted in 2020 vest on the first anniversary of the date of grant. 2 Under the 2021 NED Plan, RSUs granted in 2021 are scheduled to vest in February 2022. 3 The RSUs granted under the 2012 Plan will vest on the fifth anniversary of the date of grant. The RSUs granted under the 2018 and 2020 Long-Term Plan generally vest on the third anniversary of the date of grant. 89 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Incentive Plans (Contd.) Changes in RSUs outstanding for each of the last three years are presented in the following table. ( Number of share units ) 2021 2020 2019 Outstanding at beginning of year 1,383,043 1,535,080 1,538,854 Granted 573,907 446,848 409,692 Vested and issued ( 476,012 ) ( 271,285 ) ( 275,738 ) Forfeited ( 29,500 ) ( 327,600 ) ( 137,728 ) Outstanding at end of year 1,451,438 1,383,043 1,535,080 STOCK OPTIONS – In 2018, the Company ceased the inclusion of stock options and stock appreciation rights as a part of the long-term incentive compensation mix. Prior to 2018, 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 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. 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, 2018 3,994,595 $ 44.66 Exercised ( 57,500 ) 17.57 Forfeited ( 1,016,685 ) 48.29 Outstanding at December 31, 2019 2,920,410 43.93 Exercised ( 47,000 ) 17.57 Forfeited ( 825,010 ) 54.85 Outstanding at December 31, 2020 2,048,400 40.14 Exercised ( 170,000 ) 17.57 Forfeited ( 558,900 ) 52.61 Outstanding at December 31, 2021 1,319,500 37.77 Exercisable at December 31, 2018 3,182,345 $ 49.10 Exercisable at December 31, 2019 2,694,410 43.51 Exercisable at December 31, 2020 2,048,400 37.88 Exercisable at December 31, 2021 1,319,500 34.25 Additional information about stock options outstanding at December 31, 2021 is shown below. Options Outstanding Options Exercisable Range of Exercise Prices per Option No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value $ 17.00 to $ 30.99 773,500 1.6 $ 3,097,563 773,500 1.6 $ 3,097,563 $ 31.00 to $ 50.99 546,000 0.1 — 546,000 0.1 — 1,319,500 1.0 $ 3,097,563 1,319,500 1.0 $ 3,097,563 90 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note J – Incentive Plans (Contd.) The total intrinsic value of options exercised during 2021 was $ 1.2 million. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock. Cash-Settled Awards The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SARs), Performance-based restricted stock units (CPSUs), Time-based restricted stock units (CRSUs) and Phantom units. SAR awards have terms similar to stock options. CPSU terms are similar to other performance-based restricted stock awards (PSUs). CRSUs generally settle on the third anniversary of the date of grant. Phantom units generally settle three to five years from date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares. Total pre-tax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $ 18.2 million in 2021, $ 1.5 million in 2020 and $ 16.9 million in 2019. 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 $ 29.0 million, $ 9.8 million and $ 34.1 million was recorded in 2021, 2020 and 2019, respectively, for these plans. Note K – 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. downstream 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 sheet and to recognize changes in that funded status between periods through Accumulated other comprehensive loss. In 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision and the subsequent restructuring activities, a pension remeasurement was triggered and the Company incurred pension curtailment and special termination benefit charges as a result of the associated reduction in force in 2020. The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2021 and 2020 and a statement of the funded status as of December 31, 2021 and 2020. 91 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2021 2020 2021 2020 Change in benefit obligation Obligation at January 1 $ 981,467 883,269 108,378 108,401 Service cost 8,199 7,967 1,295 1,373 Interest cost 14,784 21,127 2,071 2,626 Participant contributions — — 2,648 2,225 Actuarial loss (gain) ( 24,440 ) 107,258 ( 9,519 ) 3,758 Medicare Part D subsidy — — 300 243 Exchange rate changes ( 1,764 ) 7,074 3 13 Benefits paid ( 38,866 ) ( 46,066 ) ( 4,041 ) ( 4,238 ) Curtailments — ( 7,596 ) — ( 6,023 ) Special termination benefits — 8,434 — — Plan amendments — — ( 5,002 ) — Obligation at December 31 939,380 981,467 96,133 108,378 Change in plan assets Fair value of plan assets at January 1 586,720 547,484 — — Actual return on plan assets 33,687 48,115 — — Employer contributions 31,607 30,178 1,093 1,770 Participant contributions — — 2,648 2,225 Medicare Part D subsidy — — 300 243 Exchange rate changes ( 1,846 ) 7,009 — — Benefits paid ( 38,866 ) ( 46,066 ) ( 4,041 ) ( 4,238 ) Fair value of plan assets at December 31 611,302 586,720 — — Funded status and amounts recognized in the Consolidated Balance Sheets at December 31 Deferred charges and other assets 5,535 4,572 — — Other accrued liabilities ( 10,144 ) ( 9,468 ) ( 4,867 ) ( 5,298 ) Deferred credits and other liabilities ( 323,469 ) ( 389,851 ) ( 91,266 ) ( 103,080 ) Fund Status and net plan liability recognized at December 31 $ ( 328,078 ) ( 394,747 ) ( 96,133 ) ( 108,378 ) At December 31, 2021, amounts included in Accumulated other comprehensive loss (AOCL) 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) $ ( 280,462 ) 13,233 Prior service cost ( 2,920 ) 5,002 $ ( 283,382 ) 18,235 92 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) 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 ) 2021 2020 2021 2020 2021 2020 Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 734,375 762,134 723,887 753,475 589,529 564,238 Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets 188,713 201,372 188,530 198,792 — — Unfunded other postretirement plans 96,133 108,378 96,133 108,378 — — The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2021. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2021 2020 2019 2021 2020 2019 Service cost $ 8,199 7,967 7,964 1,295 1,373 1,559 Interest cost 14,784 21,127 27,835 2,071 2,626 3,864 Expected return on plan assets ( 19,222 ) ( 24,316 ) ( 25,719 ) — — — Amortization of prior service cost (credit) 591 640 964 — — — Recognized actuarial (gain) loss 20,565 22,828 14,106 ( 29 ) ( 31 ) ( 193 ) Net periodic benefit expense 24,917 28,246 25,150 3,337 3,968 5,230 Termination benefits expense — 8,434 — — — — Curtailment expense — 586 — — ( 1,825 ) — Total net periodic benefit expense $ 24,917 37,266 25,150 3,337 2,143 5,230 The preceding tables in this note include the following amounts related to foreign benefit plans. Pension Benefits Other Postretirement Benefits ( Thousands of dollars ) 2021 2020 2021 2020 Benefit obligation at December 31 $ 225,117 230,101 526 492 Fair value of plan assets at December 31 218,746 221,463 — — Net plan liabilities recognized ( 6,371 ) ( 8,638 ) ( 526 ) ( 492 ) Net periodic benefit expense (benefit) 598 437 64 46 The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2021 and 2020 and net periodic benefit expense for 2021 and 2020. 93 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) Benefit Obligations Net Periodic Benefit Expense Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits December 31, December 31, Year Year 2021 2020 2021 2020 2021 2020 2021 2020 Discount rate 2.54 % 2.25 % 2.86 % 2.50 % 2.24 % 2.75 % 2.51 % 3.16 % Expected return on plan assets 4.25 % 4.43 % — — 4.25 % 4.43 % — — Rate of compensation increase 3.04 % 3.04 % — — 3.04 % 3.28 % — — The discount rates used for determining the plan obligations and expense are based on the universe of 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. 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 2022 $ 45,619 4,867 2023 45,714 4,886 2024 46,581 4,876 2025 46,259 4,835 2026 46,830 4,843 2027-2031 240,308 24,295 For purposes of measuring postretirement benefit obligations at December 31, 2021, the future annual rates of increase in the cost of health care were assumed to be 5.9 % for 2021 decreasing each year to an ultimate rate of 3.8 % in 2038 and thereafter. During 2021, the Company made contributions of $ 31.2 million to its domestic defined benefit pension plans and $ 1.1 million to its domestic postretirement benefits plan. During 2022, the Company currently expects to make contributions of $ 35.0 million to its domestic defined benefit pension plans, $ 3.2 million to its foreign defined benefit pension plans and $ 4.9 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 issues 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 - 70 % equity securities, 30 - 60 % fixed income securities, 0 - 15 % alternatives and 0 - 15 % 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. 94 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2021 and 2020 are presented in the following table. December 31, 2021 2020 Equity securities 60.9 % 58.1 % Fixed income securities 21.7 24.0 Alternatives 13.5 13.2 Cash equivalents 3.9 4.7 100.0 % 100.0 % The Company’s weighted average expected return on plan assets was 4.0 % in 2021, 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 4.0 % expected return was based on a weighted average expected future equity securities return of 3.4 % and a fixed income securities return of 0.6 %. There is also an average expected investment expense of 0.5 %. Over the last 10 years, the return on funded retirement plan assets has averaged 8.2 %. At December 31, 2021, 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, 2021 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 $ 108,422 108,422 — — U.S. small/midcap 73,222 73,222 — — Other alternative strategies 47,248 — — 47,248 International equity 47,546 47,546 — — Emerging market equity 14,937 14,937 — — Fixed income securities: U.S. fixed income 92,231 36,888 55,343 — Cash and equivalents 8,951 8,951 — — Total Domestic Plans 392,557 289,966 55,343 47,248 Foreign Plans Equity securities funds 73,642 — 73,642 — Fixed income securities funds 40,610 — 40,610 — Diversified pooled fund 54,317 — 54,317 — Other 35,606 — — 35,606 Cash and equivalents 14,570 — 14,570 — Total Foreign Plans 218,745 — 183,139 35,606 Total $ 611,302 289,966 238,482 82,854 95 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) At December 31, 2020, 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, 2020 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 $ 67,326 67,326 — — U.S. small/midcap 28,953 28,953 — — Hedged funds and other alternative strategies 42,040 — — 42,040 International commingled trust fund 76,095 987 55,433 19,675 Emerging market commingled equity fund 32,058 10,480 21,578 — Fixed income securities: U.S. fixed income 92,668 — 92,668 — International commingled trust fund 9,456 — 9,456 — Cash and equivalents 16,661 16,661 — — Total Domestic Plans 365,257 124,407 179,135 61,715 Foreign Plans Equity securities funds 74,393 — 74,393 — Fixed income securities funds 45,240 — 45,240 — Diversified pooled fund 54,871 — 54,871 — Other 35,970 — — 35,970 Cash and equivalents 10,989 — 10,989 — Total Foreign Plans 221,463 — 185,493 35,970 Total $ 586,720 124,407 364,628 97,685 The definition of levels within the fair value hierarchy in the tables above is included in Note P – Assets and Liabilities Measured at Fair Value . For domestic plans, U.S. core, small/midcap, international, emerging market equity securities and U.S. treasury securities are 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 three investments. One of these investments is valued quarterly based on net asset value and permits withdrawals after a 45 -day notice, another investment is valued annually based on net asset value and permits withdrawals semi-annually after a 90 -day notice, and the third investment is also valued quarterly based on net asset values and has a two-year lock-up period and a 95 -day notice following the lock-up period. 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. 96 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note K – Employee and Retiree Benefit Plans (Contd.) 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, 2019 $ 111,586 Actual return on plan assets: Relating to assets held at the reporting date 5,694 Purchases, sales and settlements ( 19,595 ) Total at December 31, 2020 97,685 Actual return on plan assets: Relating to assets held at the reporting date 5,206 Purchases, sales and settlements ( 20,037 ) Total at December 31, 2021 $ 82,854 THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift 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 %. Amounts charged to expense for the Company’s match to these plans were $ 5.4 million in 2021, $ 6.6 million in 2020 and $ 8.4 million in 2019. Note L – 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 New York Mercantile Exchange (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. Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL and amortized to Interest expense over time. In 2021, the Company redeemed all of the remaining notes due 2022, which were associated with the interest rate derivative contracts, and expensed the remainder of the previously deferred loss on the interest rate swap of $ 2.1 million to Interest expense in the Consolidated Statement of Operations. Commodity Price Risks The Company has entered into crude oil swaps and collar contracts. Under the swaps 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. Under the collar contracts, which also mature monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties. Upon maturity, collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price. At December 31, 2021, volumes per day associated with outstanding crude oil derivative contracts and the weighted average prices for these contracts are as follows: 97 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note L – Financial Instruments and Risk Management (Contd.) 2022 NYMEX WTI swap contracts: Volume per day (Bbl): 20,000 Price per Bbl: $ 44.88 NYMEX WTI collar contracts: Volume per day (Bbl): 25,000 Price per Bbl: Average Ceiling: $ 75.20 Average Floor: 63.24 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, 2021 and 2020. At December 31, 2021 and 2020, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. See also Note P . ( Thousands of dollars ) Asset (Liability) Derivatives Fair Value at December 31, Type of Derivative Contract Balance Sheet Location 2021 2020 Commodity swaps Accounts receivable $ — 13,050 Accounts payable ( 239,882 ) ( 89,842 ) Deferred credits and other liabilities — ( 12,833 ) Commodity collars Accounts receivable 4,280 — Accounts payable ( 19,533 ) — For the years ended December 31, 2021, 2020, and 2019, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table. Gain (Loss) ( Thousands of dollars ) Year Ended December 31, Type of Derivative Contract Statement of Operations Locations 2021 2020 2019 Commodity swaps (Loss) gain on derivative instruments $ ( 510,596 ) 202,661 ( 856 ) Commodity collars (Loss) gain on derivative instruments ( 15,254 ) — — Credit Risks The Company’s primary credit risks are 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 to 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. 98 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note M – Earnings Per Share Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2021 . The following table reconciles the weighted-average shares outstanding used for these computations. ( Weighted-average shares ) 2021 2020 2019 Basic method 154,290,741 153,507,109 163,992,427 Dilutive stock options 1 — — 820,001 Diluted method 154,290,741 153,507,109 164,812,428 1 Due to a net loss recognized by the Company for the year ended December 31, 2021 and 2020, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive. The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2021 but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive. 2021 2020 2019 Antidilutive stock options excluded from diluted shares 1,420,992 2,246,532 2,947,401 Weighted average price of these options $ 35.30 $ 39.67 $ 45.26 Note N – 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 $ 1.0 million in 2021, $( 0.9 ) million in 2020 and $( 6.0 ) million in 2019. Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2021 as shown in the following table. ( Thousands of dollars ) 2021 2020 2019 Net decrease (increase) in operating working capital, excluding cash and cash equivalents: Decrease (increase) in accounts receivable ¹ $ 8,056 164,613 ( 232,037 ) Decrease in inventories 12,809 5,953 10,258 Decrease in prepaid expenses 2,003 7,178 4,650 Increase (decrease) in accounts payable and accrued liabilities ¹ 95,166 ( 208,740 ) 196,773 Increase (decrease) in income taxes payable 423 ( 1,031 ) 3,469 Net decrease (increase) in noncash operating working capital $ 118,457 ( 32,027 ) ( 16,887 ) Supplementary disclosures: Cash income taxes paid, net of refunds $ 2,138 ( 44,175 ) ( 6,645 ) Interest paid, net of amounts capitalized of $ 16.1 million in 2021, $ 8.0 million in 2020 and $ 1.8 million in 2019 165,699 191,561 179,722 Non-cash investing activities: Asset retirement costs capitalized $ 54,439 14,736 33,874 (Increase) decrease in capital expenditure accrual 9,788 84,645 ( 73,426 ) 1 Excludes receivable/payable balances relating to mark-to-market of crude contracts. 99 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note O – Accumulated Other Comprehensive Loss The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2021 and December 31, 2020 and the changes during 2021 and 2020 are presented net of taxes in the following table. ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) Retirement and Postretirement Benefit Plan Adjustments Deferred Loss on Interest Rate Derivative Hedges Total Balance at December 31, 2019 ( 353,252 ) ( 218,015 ) ( 2,894 ) ( 574,161 ) 2020 components of other comprehensive income (loss): Before reclassifications to income 29,241 ( 70,815 ) — ( 41,574 ) Reclassifications to income — 13,198 ¹ 1,204 ² 14,402 Net other comprehensive income 29,241 ( 57,617 ) 1,204 ( 27,172 ) Balance at December 31, 2020 ( 324,011 ) ( 275,632 ) ( 1,690 ) ( 601,333 ) 2021 components of other comprehensive income (loss): Before reclassifications to income 12,116 40,095 — 52,211 Reclassifications to income — 19,721 ¹ 1,690 ² 21,411 Net other comprehensive income (loss) 12,116 59,816 1,690 73,622 Balance at December 31, 2021 $ ( 311,895 ) ( 215,816 ) — ( 527,711 ) 1 Reclassifications before taxes of $ 23,503 and $ 17,694 are included in the computation of net periodic benefit expense in 2021 and 2020, respectively. See Note K for additional information. Related income taxes of $ 3,782 and $ 4,496 are included in income tax expense in 2021 and 2020, respectively. 2 Reclassifications before taxes of $ 2,140 and $ 1,525 are included in Interest expense in 2021 and 2020, respectively. Related income taxes of $ 450 and $ 321 are included in income tax expense in 2021 and 2020, respectively. See Note L for additional information. Note P – 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 at December 31, 2021 and 2020 are presented in the following table. 100 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note P – Assets and Liabilities Measured at Fair Value (Contd.) December 31, 2021 December 31, 2020 ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity collars $ — 4,280 — 4,280 — — — — Commodity swaps — — — — — 13,050 — 13,050 $ — 4,280 — 4,280 — 13,050 — 13,050 Liabilities: Nonqualified employee savings plan $ 16,962 — — 16,962 14,988 — — 14,988 Commodity collars — 19,533 — 19,533 — — — — Contingent consideration — — 196,151 196,151 — — 133,004 133,004 Commodity swaps — 239,882 — 239,882 — 102,675 — 102,675 $ 16,962 259,415 196,151 472,528 14,988 102,675 133,004 250,667 The fair value of the commodity (WTI crude oil) swaps in 2021 and 2020 was based on active market quotes for WTI crude oil. The fair value of commodity (WTI crude oil) collars in 2021 was determined using an option pricing model based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contract. The before tax income effect of changes in fair value of crude oil derivative contracts is recorded in Gain (loss) on derivative instruments in the Consolidated Statements of Operations. 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 Company’s contingent consideration liabilities with PAI and LLOG are measured at fair value on a recurring basis and are categorized as Level 3 in the fair value hierarchy. The contingent consideration liabilities are valued using a Monte Carlo simulation model, which used the following assumptions as of December 31, 2021: (i) the remaining expected life of 1 year for LLOG and 4 years for PAI, (ii) West Texas Intermediate forward strip pricing with historical volatility of 9.9 %, and (iii) a risk-free interest rate of 1.49 %. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense 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, 2021 and 2020. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2021 and 2020. 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. 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. December 31, 2021 2020 ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value Financial assets (liabilities): Current and long-term debt $ ( 2,466,068 ) ( 2,666,773 ) ( 2,988,067 ) ( 2,948,171 ) 101 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note P – Assets and Liabilities Measured at Fair Value (Contd.) Fair Values – Nonrecurring An impairment charge of $ 171.3 million was triggered when the operator at Terra Nova provided notice of abandonment in the first quarter of 2021, before a commercial resolution in the third quarter of 2021 led Murphy to acquire an additional 7.525 % in a commercial settlement with the other partners. The commercial resolution would have meant the Terra Nova impairment charge was not required. In the fourth quarter of 2021, a further impairment charge of $ 25.0 million was recorded on non-core assets. In 2020, declines in future oil and natural gas prices (principally driven by reduced demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties. The Company recorded pretax noncash impairment charges of $ 1,206.3 million to reduce the carrying values to their estimated fair values at select properties. 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 these impaired properties is presented in the following table Years Ended December 31, Net Book Value Prior to Impairment Total Pretax Impairment Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 2021 Assets: Impaired proved properties CA Offshore $ — — 156,185 327,481 171,296 Other Foreign — — 25,739 43,739 18,000 Corporate — — 36,994 43,994 7,000 2020 Assets: Impaired proved properties U.S. Offshore $ — — 2,618,001 3,770,516 1,152,515 Other Foreign — — 42,980 82,689 39,709 Corporate — — 58,199 72,259 14,060 Note Q – Commitments The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada. The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2045, while the Western Canada processing contracts call for minimum monthly payments through 2051. In the U.S. and Western Canada, future required minimum annual payments for the next five years are $ 221.4 million in 2022, $ 168.1 million in 2023, $ 114.4 million in 2024, $ 89.8 million in 2025 and $ 82.4 million in 2026. 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 $ 151.8 million in 2021, $ 107.6 million in 2020, and $ 117.7 million in 2019. Commitments for capital expenditures were approximately $ 520.1 million at December 31, 2021, including $ 392.4 million for costs to develop deepwater U.S. Gulf of Mexico fields including fields acquired as part of the MP GOM and LLOG transactions, $ 84.7 million for Canada, $ 24.9 million for Other Foreign, and $ 18.1 million for work at Eagle Ford Shale. 102 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note R – 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 and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions 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. Violation of federal or state environmental 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 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. 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. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. 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, 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. 103 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note S – Common Stock Issued and Outstanding Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2021 is shown below. ( Number of shares outstanding ) 2021 2020 2019 Beginning of year 153,598,625 152,935,361 173,058,829 Stock options exercised 1 32,554 11,359 12,345 Restricted stock awards 1 831,871 651,905 561,729 Treasury shares purchased — — ( 20,697,542 ) End of year 154,463,050 153,598,625 152,935,361 1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares. Note T – 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 United States, Canada and all other countries. Each of these segments derives revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense. The Company has several customers that purchase a significant portion of its oil and natural gas production. During the years 2021, 2020 and 2019, sales to Chevron represented approximately 30 %, 24 %, and 25 % of the Company’s total sales revenue. During the years 2020 and 2019, sales to Phillips 66 represented approximately 18 %, and 17 % of the Company’s total sales revenue. 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. Assets held for sale as of December 31, 2021 include the net property, plant and equipment of the CA-2 project in Brunei and the Company’s office building in El Dorado, Arkansas (see Note 2). The U.K. and Malaysian operations have been reported as Discontinued operations for all periods presented in these consolidated financial statements. The Company completed the sale of its Malaysian assets in 2019. 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 contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the table on the following page, certain long-lived assets at December 31, exclude investments, noncurrent receivables, deferred tax assets, and other intangible assets. 104 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued Note T - Business Segments (Contd.) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate and Other Discontinued Operations Consolidated Total Year ended December 31, 2021 Segment income (loss) - including NCI 1 $ 766.3 ( 16.1 ) ( 33.5 ) 716.7 $ ( 668.0 ) ( 1.2 ) 47.5 Revenues from external customers 2,337.5 476.3 4.9 2,818.7 ( 519.4 ) — 2,299.3 Interest and other income (loss) ( 11.6 ) ( 1.9 ) 3.2 ( 10.3 ) ( 6.5 ) — ( 16.8 ) Interest expense, net of capitalization — — ( 0.2 ) ( 0.2 ) ( 221.6 ) — ( 221.8 ) Income tax expense (benefit) 183.9 ( 1.7 ) ( 9.5 ) 172.7 ( 178.6 ) — ( 5.9 ) Significant noncash charges (credits) Impairment of assets — 171.3 18.0 189.3 7.0 — 196.3 Depreciation, depletion and amortization 616.5 163.8 1.8 782.1 13.0 — 795.1 Accretion of asset retirement obligations 36.9 9.7 — 46.6 — — 46.6 Amortization of undeveloped leases 11.1 0.2 7.6 18.9 — — 18.9 Deferred and noncurrent income taxes 176.3 ( 1.9 ) ( 8.0 ) 166.4 ( 170.5 ) — ( 4.1 ) Additions to property, plant, equipment 519.5 52.7 13.1 585.3 — — 585.3 Total assets at year-end 6,591.6 2,231.9 259.8 9,083.3 1,220.8 0.8 10,304.9 Year ended December 31, 2020 Segment income (loss) - including NCI 1 $ ( 1,014.3 ) ( 35.0 ) ( 85.6 ) ( 1,134.9 ) $ ( 120.3 ) ( 7.2 ) ( 1,262.4 ) Revenues from external customers 1,411.8 345.8 1.8 1,759.4 207.9 — 1,967.3 Interest and other income (loss) ( 9.9 ) 0.8 0.8 ( 8.2 ) ( 9.1 ) — ( 17.3 ) Interest expense, net of capitalization — ( 0.5 ) ( 0.4 ) ( 0.9 ) ( 168.5 ) — ( 169.4 ) Income tax expense (benefit) ( 244.2 ) ( 21.4 ) 2.1 ( 263.5 ) ( 30.2 ) — ( 293.7 ) Significant noncash charges (credits) Impairment of assets 1,152.5 — 39.7 1,192.2 14.1 — 1,206.3 Depreciation, depletion and amortization 749.4 213.2 2.3 964.9 22.3 — 987.2 Accretion of asset retirement obligations 36.6 5.5 — 42.1 — — 42.1 Amortization of undeveloped leases 17.2 0.4 9.1 26.7 — — 26.7 Deferred and noncurrent income taxes ( 244.2 ) ( 10.6 ) 1.9 ( 252.9 ) ( 25.1 ) — ( 278.0 ) Additions to property, plant, equipment 623.1 118.3 15.2 756.6 — — 756.6 Total assets at year-end 6,915.5 2,404.1 267.7 9,587.3 1,032.9 0.7 10,620.9 105 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued Note T - Business Segments (Contd.) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate and Other Discontinued Operations Consolidated Total Year ended December 31, 2019 Segment income (loss) - including NCI 1 $ 518.4 ( 4.3 ) ( 53.5 ) 460.6 $ ( 271.8 ) 1,064.5 1,253.3 Revenues from external customers 2,367.0 447.0 11.6 2,825.6 3.5 — 2,829.1 Interest and other income (loss) ( 13.4 ) ( 1.5 ) ( 0.9 ) ( 15.8 ) ( 6.7 ) — ( 22.5 ) Interest expense, net of capitalization — ( 0.1 ) ( 0.4 ) ( 0.5 ) ( 218.8 ) — ( 219.3 ) Income tax expense (benefit) 115.6 ( 2.9 ) ( 12.4 ) 100.3 ( 85.6 ) — 14.7 Significant noncash charges (credits) Depreciation, depletion and amortization 878.7 243.0 3.5 1,125.2 22.6 — 1,147.8 Accretion of asset retirement obligations 34.4 6.1 — 40.5 — — 40.5 Amortization of undeveloped leases 23.1 1.3 3.6 28.0 — — 28.0 Deferred and noncurrent income taxes 111.8 14.0 ( 13.4 ) 112.4 ( 83.9 ) — 28.5 Additions to property, plant, equipment 2,193.3 284.1 69.8 2,547.2 13.6 — 2,560.8 Total assets at year-end 8,043.3 2,303.7 308.6 10,655.6 1,046.2 16.7 11,718.5 1 Includes results attributable to a noncontrolling interest in MP GOM. Geographic Information Certain Long-Lived Assets at December 31 ( Millions of dollars ) United States Canada Other Total 2021 $ 6,371.4 1,566.9 189.6 8,127.9 2020 6,395.7 1,702.5 170.8 8,269.0 2019 8,003.9 1,761.2 204.6 9,969.7 Note U – Leases Nature of Leases The Company has entered into various operating 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 gas field equipment. Remaining lease terms range from 1 year to 19 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 both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases. 106 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note U – Leases (Contd.) 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 2021 2020 Operating lease 1,2 Lease operating expenses $ 198,189 $ 208,104 Operating lease 2 Transportation, gathering and processing 39,396 39,121 Operating lease 2 Selling and general expense 9,019 10,638 Operating lease 2 Other operating expense 7,480 9,524 Operating lease 2 Exploration Expenses 902 994 Operating lease Impairment of assets — 6,565 Operating lease 2 Property, plant and equipment 81,924 40,227 Operating lease 2 Asset retirement obligations 11,103 — Finance lease Amortization of asset Depreciation, depletion and amortization 1,173 — Interest on lease liabilities Interest expense, net 228 372 Sublease income Other income ( 2,482 ) ( 1,118 ) Net lease expense $ 346,932 $ 314,427 1 Variable lease expenses. For the year ended December 31, 2021 and 2020, includes variable lease expenses of $ 25.8 million and $ 21.8 million, 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, 2021, includes $ 56.9 million in Lease operating expense, $ 30.2 million for Transportation, gathering and processing, $ 2.1 million in Selling and general expense, $ 0.2 million in Other operating expense, $ 28.9 million in Property, plant and equipment, net and $ 11.1 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. For the year ended December 31, 2020, includes $ 73.9 million in Lease operating expense, $ 22.9 million in Transportation, gathering, and processing, $ 3.3 million in Selling general expense, $ 2.5 million in Other operating expense, and $ 25.0 million in Property, plant and equipment, net relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment. Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2022 $ 184,854 1,068 185,922 2023 137,767 1,069 138,836 2024 132,568 1,069 133,637 2025 82,063 1,069 83,132 2026 64,660 1,069 65,729 Remaining 648,805 2,404 651,209 Total future minimum lease payments 1,250,717 7,748 1,258,465 Less imputed interest ( 350,128 ) ( 2,259 ) ( 352,387 ) Present value of lease liabilities 1 $ 900,589 5,489 906,078 1 Includes both the current and long-term portion of the lease liabilities. 107 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note U – Leases (Contd.) Lease Term and Discount Rate December 31, 2021 December 31, 2020 Weighted average remaining lease term: Operating leases 12 years 12 years Finance leases 7 years 8 years Weighted average discount rate: Operating leases 5.7 % 5.8 % Finance leases 4.7 % 4.7 % Other Information Year Ended December 31, (Thousands of dollars) 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 194,412 $ 160,385 Operating cash flows from finance leases 228 372 Financing cash flows from finance leases 803 695 Right-of-use assets obtained in exchange for lease liabilities: Operating leases ¹ $ 95,500 $ 453,719 1 For the year ended December 31, 2021, includes $ 90.3 million related to an offshore drilling rig with a lease term of 16 months. December 31, 2020, includes $ 268.8 million related to a 5 -year lease for the Cascade/Chinook FPSO in the U.S. Gulf of Mexico and $ 168.4 million related to a 20-year lease for a gas plant expansion in Canada. 108 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued Note V – Restructuring Charges In 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result of this decision, certain directly attributable costs and charges have been recognized and reported as Restructuring charges as part of net loss during the year ended December 31, 2020. These costs include severance, relocation, IT costs, pension curtailment charges and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado is classified as held for sale as of December 31, 2020 and 2021. Restructuring charges are primarily reported in the Corporate segment. The following table presents a summary of the restructuring charges included in Operating (loss) income from continuing operations for the year ended December 31, 2020: (Thousands of dollars) Year Ended December 31, 2020 Severance $ 25,088 Contract exit costs and other 13,993 Pension and termination benefit charges 10,913 Restructuring charges $ 49,994 The following table represents a reconciliation of the liability associated with the Company’s restructuring activities at December 31, 2020 and 2021, which is reflected in Other accrued liabilities on the Consolidated Balance Sheet: (Thousands of dollars) Restructuring accruals $ 32,430 2020 Utilizations ( 25,500 ) Liability at December 31, 2020 6,930 2021 Utilizations ( 4,757 ) Liability at December 31, 2021 $ 2,173 109 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural 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, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions 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 2021 were $ 66.56 per barrel for NYMEX crude oil (WTI), and $ 3.60 per Mcf for natural gas (Henry Hub). The average prices used for 2020 were $ 39.57 per barrel for NYMEX crude oil (WTI), and $ 1.98 per Mcf for natural gas (Henry Hub). The average prices used for 2019 were $ 55.69 per barrel for NYMEX crude oil (WTI), and $ 2.57 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 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 natural gas liquids. All crude oil, natural gas liquid reserves and natural gas 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. SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL 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. 110 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued 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, 2021. 111 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2018 – 2021 Equivalents ( Millions of barrels of oil equivalent ) Total United States Canada Malaysia and Other Proved developed and undeveloped reserves: December 31, 2018 844.0 425.6 288.6 129.7 Revisions of previous estimates 28.4 ( 17.9 ) 46.1 0.3 Extensions and discoveries 73.3 62.2 11.1 — Purchases of properties 76.2 76.2 — — Sales of properties ( 121.5 ) ( 0.1 ) — ( 121.4 ) Production ( 75.4 ) ( 45.9 ) ( 21.7 ) ( 7.8 ) December 31, 2019 825.0 500.1 324.1 0.8 Revisions of previous estimates ( 194.7 ) ( 146.6 ) ( 47.3 ) ( 0.8 ) Extensions and discoveries 150.3 19.5 130.7 — Sales of properties ( 1.7 ) ( 1.7 ) — — Production ( 63.9 ) ( 42.8 ) ( 21.1 ) — December 31, 2020 714.9 328.5 386.4 — Revisions of previous estimates ( 52.9 ) 35.6 ( 89.3 ) 0.8 Extensions and discoveries 109.4 18.2 91.3 — Purchases of properties 7.4 1.6 5.8 — Sales of properties ( 0.7 ) — ( 0.7 ) — Production ( 61.1 ) ( 40.4 ) ( 20.6 ) ( 0.1 ) December 31, 2021 ¹ 716.9 343.4 372.8 0.7 Proved developed reserves: December 31, 2018 430.2 247.0 124.2 59.1 December 31, 2019 472.3 273.4 198.1 0.8 December 31, 2020 410.8 230.3 180.5 — December 31, 2021 ² 419.2 241.9 176.8 0.6 Proved undeveloped reserves: December 31, 2018 413.8 178.7 164.5 70.7 December 31, 2019 352.7 226.7 126.0 — December 31, 2020 304.1 98.2 205.9 — December 31, 2021 ³ 297.7 101.6 196.0 0.1 1 Includes proved reserves of 18.4 MMBOE, consisting of 16.6 MMBBL oil, 0.7 MMBBL NGLs, and 6.1 BCF natural gas attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 16.2 MMBOE, consisting of 14.6 MMBBL oil, 0.6 MMBBL NGLs, and 5.4 BCF natural gas attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 2.2 MMBOE, consisting of 2.0 MMBBL oil, 0.1 MMBBL NGLs, and 0.7 BCF natural gas attributable to the noncontrolling interest in MP GOM. 112 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 1 – Summary of Total Proved Equivalent Reserves Based on Average Prices for 2018 – 2021 – Continued 2021 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The equivalent reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney. These negative revisions were partially offset by positive revisions in the U.S. from higher commodity prices, which partially reversed the 2020 capital allocation reduction, and improved well performance in the U.S. Gulf of Mexico. Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale and the Gulf of Mexico. Purchases and sales of properties - In 2021, the Company acquired incremental working interest in Terra Nova offshore Canada and in the U.S. Gulf of Mexico. 2020 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The negative reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative equivalents revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale, and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative equivalents revisions in the U.S offshore and Canada offshore. Extensions and discoveries - In 2020, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico. 2019 Comments for Proved Equivalent Reserves Changes Revisions of previous estimates - The positive Canadian equivalents reserves revisions in 2019 resulted from improved performance in the Tupper Montney asset which offset reserves reductions from deferrals of capital expenditures at Kaybob Duvernay. The 2019 negative equivalents revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily the Tilden area. Extensions and discoveries - In 2019, proved equivalent reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties - In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico and partial ownership in the Jagus East field in Brunei (which is now held for sale). The Company’s Malaysia assets were divested in 2019. 113 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2018 – 2021 ( Millions of barrels ) Total United States Canada Malaysia and Other Proved developed and undeveloped crude oil reserves: December 31, 2018 432.5 326.5 55.0 51.0 Revisions of previous estimates ( 31.0 ) ( 17.1 ) ( 14.0 ) 0.1 Extensions and discoveries 58.2 49.2 9.0 — Purchases of properties 56.3 56.3 — — Sales of properties ( 45.8 ) ( 0.1 ) — ( 45.7 ) Production ( 46.3 ) ( 37.0 ) ( 4.7 ) ( 4.6 ) December 31, 2019 423.9 377.8 45.3 0.8 Revisions of previous estimates ( 137.4 ) ( 116.8 ) ( 19.8 ) ( 0.8 ) Extensions and discoveries 19.6 14.5 5.1 — Production ( 38.1 ) ( 33.4 ) ( 4.7 ) — December 31, 2020 266.5 240.6 25.9 — Revisions of previous estimates 39.3 31.1 7.5 0.7 Extensions and discoveries 14.1 13.5 0.6 — Purchases of properties 6.4 1.3 5.2 — Production ( 34.9 ) ( 31.5 ) ( 3.3 ) ( 0.1 ) December 31, 2021 ¹ 291.5 255.0 35.9 0.6 Proved developed crude oil reserves: December 31, 2018 249.3 189.0 23.3 37.0 December 31, 2019 230.9 205.0 25.1 0.8 December 31, 2020 179.8 161.4 18.4 — December 31, 2021 ² 191.5 174.9 16.0 0.5 Proved undeveloped crude oil reserves: December 31, 2018 183.2 137.5 31.7 14.0 December 31, 2019 193.0 172.8 20.2 — December 31, 2020 86.7 79.2 7.5 — December 31, 2021 ³ 99.9 80.0 19.8 0.1 1 Includes total proved reserves of 16.6 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 14.6 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 2.0 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM. 114 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 2 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2018 – 2021 – Continued 2021 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The positive crude oil reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices in the U.S., which partially reversed the 2020 capital allocation reductions, and improved well performance in the U.S. Gulf of Mexico. Extensions and discoveries - In 2021, proved oil reserves were added for drilling and expansion activities predominantly in the U.S. at the Eagle Ford Shale and the Gulf of Mexico. Purchases and sales of properties - In 2021, the Company acquired incremental working interest in Terra Nova offshore Canada and in the U.S. Gulf of Mexico. 2020 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates - The negative crude oil reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative oil revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale, and the negative revision in Canada was primarily attributable to the Kaybob Duvernay. Lower commodity prices also resulted in negative oil reserves revisions in the U.S offshore and Canada offshore. Extensions and discoveries - In 2020, proved oil reserves were added for drilling activities predominantly in the U.S. offshore and the Eagle Ford Shale. Proved oil reserves were also added for drilling activities in Canada offshore. Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico. 2019 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimates – The 2019 negative crude oil revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily in the Tilden area. The negative Canadian oil reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay. Extensions and discoveries – In 2019, proved oil reserves were added in the U.S. for drilling activities both in the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved oil reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 115 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 3 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2018 – 2021 ( Millions of barrels ) Total United States Canada Malaysia and Other Proved developed and undeveloped NGL reserves: December 31, 2018 54.2 47.6 5.9 0.7 Revisions of previous estimates ( 5.0 ) ( 2.5 ) ( 2.5 ) — Extensions and discoveries 6.8 6.4 0.4 — Purchase of properties 5.2 5.2 — — Production ( 4.5 ) ( 3.9 ) ( 0.5 ) ( 0.1 ) December 31, 2019 56.1 52.8 3.3 — Revisions of previous estimates ( 16.4 ) ( 17.1 ) 0.7 — Extensions and discoveries 2.8 2.7 0.1 — Production ( 4.2 ) ( 3.7 ) ( 0.5 ) — December 31, 2020 38.2 34.6 3.6 — Revisions of previous estimates 1.4 1.4 — — Extensions and discoveries 2.5 2.4 0.1 — Purchases of properties 0.1 0.1 — — Production ( 3.8 ) ( 3.4 ) ( 0.4 ) — December 31, 2021 ¹ 38.4 35.1 3.3 — Proved developed NGL reserves: December 31, 2018 27.3 24.9 1.7 0.7 December 31, 2019 28.1 26.2 1.9 — December 31, 2020 28.7 25.5 3.2 — December 31, 2021 ² 28.4 25.6 2.8 — Proved undeveloped NGL reserves: December 31, 2018 26.9 22.7 4.2 — December 31, 2019 28.0 26.6 1.4 — December 31, 2020 9.5 9.1 0.4 — December 31, 2021 ³ 10.0 9.5 0.5 — 1 Includes total proved reserves of 0.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 0.6 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 0.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM. 116 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 3 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2018 – 2021 – Continued 2021 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The positive NGL reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices, which partially reversed the 2020 capital allocation reductions, and improved well performance in the U.S. Gulf of Mexico. Extensions and discoveries - In 2021, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S. Eagle Ford Shale. Purchases and sales of properties - In 2021, the Company acquired incremental working interest in the U.S. Gulf of Mexico. 2020 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates - The negative NGL reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative NGL revision in the U.S. was primarily attributable to lower capital allowance in the Eagle Ford Shale. The positive revision in Canada was primarily attributable to higher yields at the Kaybob Duvernay due to improved plant recoveries. Extensions and discoveries - In 2020, proved NGL reserves were added for drilling activities predominantly in the U.S. at the Eagle Ford Shale. Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico. 2019 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The negative 2019 NGL proved reserves revision in the U.S. was primarily due to midstream elections in the Eagle Ford Shale resulting in lower NGL yields. The negative Canadian NGL reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay. Extensions and discoveries – In 2019, proved NGL reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay area in onshore Canada. Proved NGL reserves were also added for drilling activities in the U.S. offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 117 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2018 – 2021 ( Billions of cubic feet ) Total United States Canada Malaysia and Other Proved developed and undeveloped natural gas reserves: December 31, 2018 2,143.6 309.0 1,366.4 468.2 Revisions of previous estimates 386.5 10.3 375.3 0.9 Extensions and discoveries 49.8 39.5 10.3 — Purchases of properties 88.3 88.3 — — Sales of properties ( 450.7 ) ( 0.1 ) — ( 450.6 ) Production ( 147.8 ) ( 30.2 ) ( 99.1 ) ( 18.5 ) December 31, 2019 2,069.7 416.8 1,652.9 — Revisions of previous estimates ( 245.4 ) ( 76.2 ) ( 169.2 ) — Extensions and discoveries 767.2 14.0 753.2 — Production ( 129.8 ) ( 34.4 ) ( 95.4 ) — December 31, 2020 2,461.0 319.5 2,141.5 — Revisions of previous estimates ( 562.2 ) 18.7 ( 581.0 ) 0.2 Extensions and discoveries 556.7 13.5 543.2 — Purchases of properties 5.4 1.5 3.9 — Sales of properties ( 4.4 ) — ( 4.4 ) — Production ( 134.2 ) ( 32.8 ) ( 101.4 ) — December 31, 2021 1,4 2,322.3 320.3 2,001.8 0.2 Proved developed natural gas reserves: December 31, 2018 921.6 198.3 595.0 128.3 December 31, 2019 1,279.8 253.1 1,026.7 — December 31, 2020 1,213.8 260.2 953.6 — December 31, 2021 ² 1,196.0 248.1 947.7 0.2 Proved undeveloped natural gas reserves: December 31, 2018 1,222.0 110.7 771.4 339.9 December 31, 2019 789.9 163.7 626.2 — December 31, 2020 1,247.2 59.3 1,187.9 — December 31, 2021 ³ 1,126.4 72.2 1,054.1 — 1 Includes total proved reserves of 6.1 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 2 Includes proved developed reserves of 5.4 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 3 Includes proved undeveloped reserves of 0.7 BCF for Total and United States attributable to the noncontrolling interest in MP GOM. 4 Includes proved natural gas reserves to be consumed in operations as fuel of 78.7 BCF and 74.0 BCF for the U.S. and Canada, respectively, with 1.7 BCF attributable to the noncontrolling interest in MP GOM. 118 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2018 – 2021 – Continued 2021 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices at Tupper Montney. Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale and the Gulf of Mexico. Purchases and sales of properties - In 2021, the Company acquired incremental working interest at Terra Nova offshore Canada and in the U.S. Gulf of Mexico. 2020 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates - The negative natural gas reserves revisions in 2020 resulted predominantly from lower crude oil prices and lower capital allocation to Onshore shale properties over the next 5 years causing the removal of numerous proved undeveloped locations, partially offset by improved well performance in the Gulf of Mexico. The 2020 negative natural gas revision in the U.S. was primarily attributable to lower capital allocation in the Eagle Ford Shale which offset positive natural gas revisions in the Gulf of Mexico. The negative revision in Canada was primarily attributable to the Kaybob Duvernay. Extensions and discoveries - In 2020, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S. at the Eagle Ford Shale. Purchases and sales of properties - In 2020, the Company divested partial working interest in an undeveloped well in the Gulf of Mexico. 2019 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – In 2019, the positive natural gas revisions in Canada resulted from improved performance in the Tupper Montney asset and adjustments relating to royalties. The positive revision for natural gas reserves in the Eagle Ford Shale was primarily attributable to producing well performance. Extensions and discoveries – In 2019, proved natural gas reserves were added in the U.S. for development drilling activities in both the Eagle Ford Shale and in Canada at Tupper Montney and Kaybob Duvernay. Proved natural gas reserves were also added for drilling activities in both the U.S. offshore and Canada offshore. Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019. 119 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 5 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities ( Millions of dollars ) United States Canada 1 Other Total Year ended December 31, 2021 Property acquisition costs Unproved $ 8.8 — — 8.8 Proved 19.9 ( 20.4 ) — ( 0.5 ) Total acquisition costs 28.7 ( 20.4 ) — 8.3 Exploration costs 2 31.7 0.4 30.1 62.2 Development costs 2 513.2 102.4 3.7 619.3 Total costs incurred 573.6 82.4 33.8 689.8 Charged to expense Dry hole expense 17.3 — — 17.3 Geophysical and other costs 13.1 0.4 19.3 32.8 Total charged to expense 30.4 0.4 19.3 50.1 Property additions $ 543.2 82.0 14.5 639.7 Year ended December 31, 2020 Property acquisition costs Unproved $ 6.5 0.5 7.3 14.3 Proved 0.2 — — 0.2 Total acquisition costs 6.7 0.5 7.3 14.5 Exploration costs 2 34.3 ( 0.4 ) 24.7 58.6 Development costs 2 609.2 120.8 6.8 736.8 Total costs incurred 650.2 120.9 38.8 809.9 Charged to expense Geophysical and other costs 14.3 0.7 23.6 38.6 Total charged to expense 14.3 0.7 23.6 38.6 Property additions $ 635.9 120.2 15.2 771.3 Year ended December 31, 2019 Property acquisition costs Unproved $ 533.8 0.2 13.0 547.0 Proved 733.1 — — 733.1 Total acquisition costs 1,266.9 0.2 13.0 1,280.1 Exploration costs 2 44.8 6.4 67.4 118.6 Development costs 2 979.0 281.8 21.6 1,282.4 Total costs incurred 2,290.7 288.4 102.0 2,681.1 Charged to expense Geophysical and other costs 21.6 0.5 32.2 54.3 Total charged to expense 21.6 0.5 32.2 54.3 Property additions $ 2,269.1 287.9 69.8 2,626.8 1 2021 Canada proved property acquisitions represents cash received from divesting partners on acquisition of an additional 7.525 % working interest at Terra Nova as part of the sanction of an asset life extension project. 120 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 5 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities – Continued 2 Includes noncash asset retirement costs as follows: 2021 Exploration costs $ — — — — Development costs 23.7 29.3 1.4 54.4 $ 23.7 29.3 1.4 54.4 2020 Exploration costs $ — — — — Development costs 12.8 1.9 — 14.7 $ 12.8 1.9 — 14.7 2019 Exploration costs $ — — — — Development costs 75.8 3.8 — 79.6 $ 75.8 3.8 — 79.6 121 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities 1 ( Millions of dollars ) United States Canada Other Total Year ended December 31, 2021 Revenues Crude oil and natural gas liquids sales $ 2,199.7 228.9 4.9 2,433.5 Natural gas sales 121.8 245.9 — 367.7 Total oil and natural gas revenues 2,321.5 474.8 4.9 2,801.2 Other operating revenues 16.0 1.5 — 17.5 Total revenues 2,337.5 476.3 4.9 2,818.7 Costs and expenses Lease operating expenses 406.4 136.3 ( 3.2 ) 539.5 Severance and ad valorem taxes 39.6 1.6 — 41.2 Transportation, gathering and processing 126.5 60.5 — 187.0 Exploration costs charged to expense 30.4 0.4 19.3 50.1 Undeveloped lease amortization 11.1 0.2 7.6 18.9 Depreciation, depletion and amortization 616.5 163.8 1.8 782.1 Accretion of asset retirement obligations 36.9 9.7 — 46.6 Impairment of assets — 171.3 18.0 189.3 Selling and general expenses 20.5 16.5 6.6 43.6 Other expenses (benefits) 99.4 ( 66.2 ) ( 2.2 ) 31.0 Total costs and expenses 1,387.3 494.1 47.9 1,929.3 Results of operations before taxes 950.2 ( 17.8 ) ( 43.0 ) 889.4 Income tax expense (benefit) 183.9 ( 1.7 ) ( 9.5 ) 172.7 Results of operations $ 766.3 ( 16.1 ) ( 33.5 ) 716.7 Year ended December 31, 2020 Revenues Crude oil and natural gas liquids sales $ 1,335.8 174.0 1.8 1,511.6 Natural gas sales 69.4 170.6 — 240.1 Total oil and natural gas revenues 1,405.3 344.6 1.8 1,751.7 Other operating revenues 6.5 1.2 — 7.7 Total revenues 1,411.8 345.8 1.8 1,759.4 Costs and expenses Lease operating expenses 476.9 121.6 1.6 600.1 Severance and ad valorem taxes 27.2 1.3 — 28.5 Transportation, gathering and processing 127.7 44.7 — 172.4 Restructuring expenses 1.2 — — 1.2 Exploration costs charged to expense 35.5 0.6 23.6 59.7 Undeveloped lease amortization 17.2 0.4 9.2 26.8 Depreciation, depletion and amortization 749.4 213.2 2.3 964.9 Accretion of asset retirement obligations 36.6 5.6 — 42.2 Impairment of assets 1,152.5 — 39.7 1,192.2 Selling and general expenses 24.6 17.1 7.1 48.8 Other expenses 21.5 ( 2.3 ) 1.8 21.0 Total costs and expenses 2,670.3 402.2 85.3 3,157.8 Results of operations before taxes ( 1,258.5 ) ( 56.4 ) ( 83.5 ) ( 1,398.4 ) Income tax expense (benefit) ( 244.2 ) ( 21.4 ) 2.1 ( 263.5 ) Results of operations $ ( 1,014.3 ) ( 35.0 ) ( 85.6 ) ( 1,134.9 ) 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. 122 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL 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, 2019 Revenues Crude oil and natural gas liquids sales $ 2,285.8 287.4 11.6 2,584.8 Natural gas sales 73.9 158.4 — 232.3 Total oil and natural gas revenues 2,359.7 445.8 11.6 2,817.1 Other operating revenues 7.3 1.2 — 8.5 Total revenues 2,367.0 447.0 11.6 2,825.6 Costs and expenses Lease operating expenses 461.5 142.4 1.3 605.2 Severance and ad valorem taxes 46.6 1.4 — 48.0 Transportation, gathering and processing 140.8 35.5 — 176.3 Exploration costs charged to expense 21.4 0.6 45.3 67.3 Undeveloped lease amortization 23.1 1.3 3.6 28.0 Depreciation, depletion and amortization 878.7 243.0 3.5 1,125.2 Accretion of asset retirement obligations 34.4 6.1 — 40.5 Selling and general expenses 74.3 30.0 22.5 126.8 Other expenses 52.2 ( 6.1 ) 1.3 47.4 Total costs and expenses 1,733.0 454.2 77.5 2,264.7 Results of operations before taxes 634.0 ( 7.2 ) ( 65.9 ) 560.9 Income tax expense (benefit) 115.6 ( 2.9 ) ( 12.4 ) 100.3 Results of operations $ 518.4 ( 4.3 ) ( 53.5 ) 460.6 1 Results exclude corporate overhead, interest and discontinued operations. Results include noncontrolling interest in MP GOM. 123 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves 1 ( Millions of dollars ) United States Canada Malaysia & Other Total December 31, 2021 Future cash inflows $ 18,449.1 7,203.5 44.0 25,696.7 Future development costs ( 1,164.3 ) ( 521.1 ) ( 1.5 ) ( 1,686.8 ) Future production costs ( 7,140.6 ) ( 3,525.8 ) ( 9.1 ) ( 10,675.4 ) Future income taxes ( 1,024.4 ) ( 565.4 ) ( 3.0 ) ( 1,592.8 ) Future net cash flows 9,119.9 2,591.3 30.4 11,741.6 10% annual discount for estimated timing of cash flows ( 3,264.9 ) ( 1,169.3 ) ( 8.5 ) ( 4,442.7 ) Standardized measure of discounted future net cash flows $ 5,855.1 1,422.0 21.9 7,299.0 December 31, 2020 Future cash inflows $ 9,976.7 4,617.5 — 14,594.2 Future development costs ( 1,289.8 ) ( 404.3 ) — ( 1,694.1 ) Future production costs ( 5,777.5 ) ( 2,634.6 ) — ( 8,412.1 ) Future income taxes — ( 166.8 ) — ( 166.8 ) Future net cash flows 2,909.4 1,411.8 — 4,321.2 10% annual discount for estimated timing of cash flows ( 1,079.2 ) ( 623.4 ) — ( 1,702.6 ) Standardized measure of discounted future net cash flows $ 1,830.2 788.4 — 2,618.6 December 31, 2019 Future cash inflows $ 23,565.6 4,912.1 55.7 28,533.4 Future development costs ( 4,137.8 ) ( 723.7 ) ( 0.3 ) ( 4,861.8 ) Future production costs ( 8,986.2 ) ( 2,549.9 ) ( 29.9 ) ( 11,566.0 ) Future income taxes ( 1,709.3 ) ( 414.5 ) ( 14.1 ) ( 2,137.9 ) Future net cash flows 8,732.3 1,224.0 11.4 9,967.7 10% annual discount for estimated timing of cash flows ( 3,633.1 ) ( 504.0 ) ( 3.0 ) ( 4,140.1 ) Standardized measure of discounted future net cash flows $ 5,099.2 720.0 8.4 5,827.6 1 Includes noncontrolling interest in MP GOM. 2 Totals within the table may not add as a result of rounding. 124 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves – Continued 1 Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown. ( Millions of dollars ) 2021 2020 2019 Net changes in prices and production costs 2 $ 5,962.1 ( 5,942.1 ) ( 2,993.9 ) Net changes in development costs ( 503.6 ) 2,215.1 ( 675.7 ) Sales and transfers of oil and natural gas produced, net of production costs ( 2,220.5 ) ( 1,123.1 ) ( 2,163.8 ) Net change due to extensions and discoveries 908.5 568.5 1,221.9 Net change due to purchases and sales of proved reserves 63.1 ( 14.6 ) ( 628.1 ) Development costs incurred 619.3 736.8 1,282.4 Accretion of discount 267.2 699.3 1,002.0 Revisions of previous quantity estimates 277.1 ( 1,461.3 ) ( 71.2 ) Net change in income taxes ( 692.8 ) 1,112.4 574.1 Net increase (decrease) 4,680.4 ( 3,209.0 ) ( 2,452.3 ) Standardized measure at January 1 2,618.6 5,827.6 8,279.9 Standardized measure at December 31 $ 7,299.0 2,618.6 5,827.6 1 Includes noncontrolling interest in MP GOM. 2 The average prices used for 2021 were $ 66.56 per barrel for NYMEX crude oil (WTI), and $ 3.60 per Mcf for natural gas (Henry Hub).The average prices used for 2020 were $ 39.57 per barrel for NYMEX crude oil (WTI), and $ 1.98 per Mcf for natural gas (Henry Hub). The average prices used for 2019 were $ 55.69 per barrel for NYMEX crude oil (WTI), and $ 2.57 per Mcf for natural gas (Henry Hub). 125 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued Schedule 8 – Capitalized Costs Relating to Oil and Natural Gas Producing Activities ( Millions of dollars ) United States Canada Other Total December 31, 2021 Unproved oil and natural gas properties $ 602.8 17.7 141.7 762.2 Proved oil and natural gas properties 14,690.7 4,865.1 100.0 19,655.8 Gross capitalized costs 15,293.5 4,882.8 241.7 20,418.0 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties ( 109.1 ) — ( 22.0 ) ( 131.1 ) Proved oil and natural gas properties ( 8,821.5 ) ( 3,320.5 ) ( 69.0 ) ( 12,211.0 ) Net capitalized costs $ 6,362.9 1,562.3 150.7 8,075.9 December 31, 2020 Unproved oil and natural gas properties $ 646.0 22.2 137.5 805.7 Proved oil and natural gas properties 14,011.4 4,619.4 23.8 18,654.6 Gross capitalized costs 14,657.4 4,641.6 161.3 19,460.3 Accumulated depreciation, depletion and amortization Unproved oil and natural gas properties ( 105.0 ) — ( 14.5 ) ( 119.5 ) Proved oil and natural gas properties ( 8,166.5 ) ( 2,944.3 ) ( 20.7 ) ( 11,131.5 ) Net capitalized costs $ 6,385.9 1,697.3 126.1 8,209.3 Note: Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation. 126 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year 1,2 Year ended December 31, 2021 Revenue from contracts with customers $ 592.5 758.8 687.6 762.3 2,801.2 Income (loss) from continuing operations before income taxes ( 355.2 ) ( 38.1 ) 174.9 261.3 42.9 Income (loss) from continuing operations ( 267.0 ) ( 26.9 ) 138.0 204.7 48.8 Net income (loss) including noncontrolling interest ( 266.8 ) ( 27.0 ) 137.3 204.0 47.5 Net income (loss) attributable to Murphy ( 287.4 ) ( 63.1 ) 108.4 168.4 ( 73.7 ) Income (loss) from continuing operations per Common share Basic ( 1.87 ) ( 0.41 ) 0.70 1.09 ( 0.47 ) Diluted ( 1.87 ) ( 0.41 ) 0.70 1.08 ( 0.47 ) Net income (loss) per Common share ³ Basic ( 1.87 ) ( 0.41 ) 0.70 1.09 ( 0.48 ) Diluted ( 1.87 ) ( 0.41 ) 0.70 1.09 ( 0.48 ) Cash dividend per Common share 0.125 0.125 0.125 0.125 0.50 Year ended December 31, 2020 Revenue from contracts with customers $ 600.6 285.7 425.3 440.1 1,751.7 Income (loss) from continuing operations before income taxes ( 595.4 ) ( 417.9 ) ( 328.4 ) ( 207.3 ) ( 1,549.0 ) Income (loss) from continuing operations ( 503.8 ) ( 323.1 ) ( 265.9 ) ( 162.5 ) ( 1,255.3 ) Net income including noncontrolling interest ( 508.7 ) ( 324.4 ) ( 266.6 ) ( 162.7 ) ( 1,262.4 ) Net income attributable to Murphy ( 416.1 ) ( 317.2 ) ( 243.5 ) ( 171.9 ) ( 1,148.8 ) Income (loss) from continuing operations per Common share Basic ( 2.68 ) ( 2.05 ) ( 1.58 ) ( 1.11 ) ( 7.43 ) Diluted ( 2.68 ) ( 2.05 ) ( 1.58 ) ( 1.11 ) ( 7.43 ) Net income (loss) per Common share Basic ( 2.71 ) ( 2.06 ) ( 1.59 ) ( 1.11 ) ( 7.48 ) Diluted ( 2.71 ) ( 2.06 ) ( 1.59 ) ( 1.11 ) ( 7.48 ) Cash dividend per Common share 0.25 0.125 0.125 0.125 0.625 1 Revenue from contracts with customers, Income (loss) from continuing operations before income taxes, Income (loss) from continuing operations and Net income (loss) including noncontrolling interest include results attributable to the noncontrolling interest in MP GOM. 2 2020 results include impairment charges of $ 1,206.3 million as a result of declines in future oil and natural gas prices at the time of impairment (principally driven by reduced demand in response to the COVID-19 pandemic - see Risk Factors). 3 The sum of quarterly net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding. 127 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SCHEDULE II - VALUATION ACCOUNTS AND RESERVES ( Millions of dollars ) Balance at January 1 Charged to Expense Deductions Other 1 Balance at December 31 2021 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 — — — 1.6 Deferred tax asset valuation allowance 106.4 4.8 — — 111.2 2020 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 — — — 1.6 Deferred tax asset valuation allowance 103.1 3.3 — — 106.4 2019 Deducted from asset accounts: Allowance for doubtful accounts $ 1.6 — — — 1.6 Deferred tax asset valuation allowance 166.9 10.9 — ( 74.7 ) 103.1 1 The amount in 2019 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carryforwards. 128 GLOSSARY ABBREVIATIONS 3D seismic three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons deepwater offshore location in greater than 1,000 feet of water downstream refining and marketing operations dry hole an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense exploratory wildcat and delineation, e.g., exploratory wells hydrocarbons organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products operator the company serving as the manager and often the decision-maker of a drilling or production project production sharing contract agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recovered unitization combining of multiple mineral or leasehold interests to be able to produce from a common reservoir upstream oil and natural gas exploration and production operations, including synthetic oil operation working interest right to drill and produce oil and gas on the leased acreage, as well as the obligation to pay costs ARO - Asset Retirement Obligation ASU - Accounting Standards Update BCF - Billion cubic feet BOEPD - Barrel of oil equivalent per day FASB - Financial Accounting Standards Board GAAP - U.S. Generally Accepted Accounting Principles GK - Gumusut/Kakap MCF - Thousand cubic feet MMBOE - Million barrels of oil equivalent MMCF - Million cubic feet MMCFD – Million cubic feet per day MOCL - Murphy Oil Company Ltd. NCI - Noncontrolling interest NYMEX - New York Mercantile Exchange OSHA - Occupational Safety and Health Act PAI – Petrobras Americas Inc., a subsidiary of Petróleo Brasileiro S.A. QRE - Qualified Reserve Estimators SEC - U.S. Securities and Exchange Commission WTI - West Texas Intermediate 129