MURPHY OIL CORP 10-Q

ITEM 1. FINANCIAL STATEMENTS MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Thousands of dollars, except share amounts) September 30, 2025 December 31, 2024 ASSETS Current assets Cash and cash equivalents $ 425,960 $ 423,569 Accounts receivable, net 283,744 272,530 Inventories 62,147 54,858 Prepaid expenses 35,629 34,322 Total current assets 807,480 785,279 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ 14,762,292 in 2025 and $ 13,811,539 in 2024 8,085,731 8,054,653 Operating lease assets 781,291 777,536 Deferred charges and other assets 58,260 50,011 Total assets $ 9,732,762 $ 9,667,479 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 918 $ 871 Accounts payable 429,658 472,165 Income taxes payable 20,987 19,003 Other taxes payable 31,573 31,685 Operating lease liabilities 210,769 253,208 Other accrued liabilities 117,965 117,802 Current asset retirement obligations 45,876 48,080 Total current liabilities 857,746 942,814 Long-term debt, including finance lease obligation 1,425,235 1,274,502 Asset retirement obligations 1,001,919 960,804 Deferred credits and other liabilities 249,521 274,345 Non-current operating lease liabilities 582,082 537,381 Deferred income taxes 366,607 335,790 Total liabilities $ 4,483,110 $ 4,325,636 Equity Cumulative Preferred Stock, par $ 100 , authorized 400,000 shares, none issued $ — $ — Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2025 and 195,100,628 shares at December 31, 2024 195,101 195,101 Capital in excess of par value 850,964 848,950 Retained earnings 6,725,833 6,773,289 Accumulated other comprehensive loss ( 574,931 ) ( 628,072 ) Treasury stock ( 2,075,580 ) ( 1,995,018 ) Murphy Shareholders' Equity 5,121,387 5,194,250 Noncontrolling interest 128,265 147,593 Total equity 5,249,652 5,341,843 Total liabilities and equity $ 9,732,762 $ 9,667,479 The accompanying notes are an integral part of these consolidated financial statements. 2 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) Three Months Ended September 30, Nine Months Ended September 30, (Thousands of dollars, except per share amounts) 2025 2024 2025 2024 Revenues and other income Revenue from production $ 720,966 $ 753,169 $ 2,076,761 $ 2,345,282 Sales of purchased natural gas — — — 3,742 Total revenue from sales to customers 720,966 753,169 2,076,761 2,349,024 Gain (loss) on derivative instruments 5,722 ( 1,344 ) 7,071 ( 1,344 ) Gain on sale of assets and other operating income 6,297 6,506 10,434 9,834 Total revenues and other income 732,985 758,331 2,094,266 2,357,514 Costs and expenses Lease operating expenses 184,353 222,886 604,986 716,778 Severance and ad valorem taxes 12,288 10,503 31,766 31,006 Transportation, gathering and processing 48,146 47,438 151,067 157,461 Costs of purchased natural gas — — — 3,147 Exploration expenses, including undeveloped lease amortization 32,502 31,284 57,389 118,390 Selling and general expenses 30,858 24,871 98,692 78,925 Depreciation, depletion and amortization 283,465 223,632 736,949 650,309 Accretion of asset retirement obligations 14,676 13,241 43,153 39,068 Impairment of assets 115,002 — 115,002 34,528 Other operating expense 5,902 5,450 13,364 10,497 Total costs and expenses 727,192 579,305 1,852,368 1,840,109 Operating income from continuing operations 5,793 179,026 241,898 517,405 Other income (loss) Other income (loss) 15,271 ( 3,926 ) ( 14,631 ) 33,870 Interest expense, net ( 24,726 ) ( 21,258 ) ( 73,302 ) ( 62,265 ) Total other loss ( 9,455 ) ( 25,184 ) ( 87,933 ) ( 28,395 ) Income (loss) from continuing operations before income taxes ( 3,662 ) 153,842 153,965 489,010 Income tax expense 4,157 2,122 37,911 64,855 Income (loss) from continuing operations ( 7,819 ) 151,720 116,054 424,155 Income (loss) from discontinued operations, net of income taxes ( 497 ) ( 608 ) 172 ( 2,123 ) Net income (loss) including noncontrolling interest ( 8,316 ) 151,112 116,226 422,032 Less: Net income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197 NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ ( 2,973 ) $ 139,094 $ 92,343 $ 356,835 NET INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.37 Discontinued operations — — — ( 0.01 ) Net income (loss) $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.36 NET INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.35 Discontinued operations — — — ( 0.01 ) Net income (loss) $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.34 Cash dividends per common share $ 0.325 $ 0.300 $ 0.975 $ 0.900 Average common shares outstanding (thousands) Basic 142,731 149,384 143,245 151,401 Diluted 142,731 150,353 143,976 152,437 The accompanying notes are an integral part of these consolidated financial statements. 3 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) Three Months Ended September 30, Nine Months Ended September 30, (Thousands of dollars) 2025 2024 2025 2024 Net income (loss) including noncontrolling interest $ ( 8,316 ) $ 151,112 $ 116,226 $ 422,032 Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation ( 38,027 ) 17,764 50,528 ( 34,588 ) Retirement and postretirement benefit plans 874 1,174 2,613 2,998 Other comprehensive income (loss) ( 37,153 ) 18,938 53,141 ( 31,590 ) Comprehensive income including noncontrolling interest ( 45,469 ) 170,050 169,367 390,442 Less: Comprehensive income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197 COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ ( 40,126 ) $ 158,032 $ 145,484 $ 325,245 The accompanying notes are an integral part of these consolidated financial statements. 4 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Nine Months Ended September 30, (Thousands of dollars) 2025 2024 Operating Activities Net income (loss) including noncontrolling interest $ 116,226 $ 422,032 Adjustments to reconcile net income to net cash provided by continuing operations activities Depreciation, depletion and amortization 736,949 650,309 Accretion of asset retirement obligations 43,153 39,068 Long-term non-cash compensation 28,514 30,060 Deferred income tax expense 23,305 45,136 Amortization of undeveloped leases 6,907 7,707 Unrealized (gain) loss on derivative instruments ( 3,904 ) 1,344 Unsuccessful exploration well costs and previously suspended exploration costs 83 69,548 (Income) loss from discontinued operations ( 172 ) 2,123 Impairment of assets 115,002 34,528 Other operating activities, net ( 47,428 ) ( 38,260 ) Net decrease (increase) in non-cash working capital ( 20,473 ) 31,835 Net cash provided by continuing operations activities 998,162 1,295,430 Investing Activities Property additions and dry hole costs ( 827,007 ) ( 733,289 ) Acquisition of oil and natural gas properties ( 24,405 ) — Net cash required by investing activities ( 851,412 ) ( 733,289 ) Financing Activities Borrowings on revolving credit facility 475,000 350,000 Repayment of revolving credit facility ( 325,000 ) ( 350,000 ) Retirement of debt — ( 50,000 ) Repurchase of common stock ( 102,620 ) ( 300,132 ) Cash dividends paid ( 139,799 ) ( 136,208 ) Withholding tax on stock-based incentive awards ( 7,669 ) ( 25,310 ) Distributions to noncontrolling interest ( 43,211 ) ( 96,618 ) Finance lease obligation payments ( 543 ) ( 502 ) Issue costs of revolving debt facility ( 18 ) — Net cash required by financing activities ( 143,860 ) ( 608,770 ) Effect of exchange rate changes on cash and cash equivalents ( 499 ) 778 Net increase (decrease) in cash and cash equivalents 2,391 ( 45,851 ) Cash and cash equivalents at beginning of period 423,569 317,074 Cash and cash equivalents at end of period $ 425,960 $ 271,223 The accompanying notes are an integral part of these consolidated financial statements. 5 Table of Contents MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED) Three Months Ended September 30, Nine Months Ended September 30, (Thousands of dollars except number of shares) 2025 2024 2025 2024 Common Stock Balance at beginning and end of period – par $ 1.00 , authorized 450,000,000 shares at September 30, 2025 and September 30, 2024, issued 195,100,628 shares at September 30, 2025 and September 30, 2024 $ 195,101 $ 195,101 $ 195,101 $ 195,101 Capital in Excess of Par Value Balance at beginning of period 841,833 826,861 848,950 880,297 Restricted stock transactions and other ( 241 ) ( 53 ) ( 27,977 ) ( 70,539 ) Share-based compensation 9,372 8,847 29,991 25,897 Balance at end of period 850,964 835,655 850,964 835,655 Retained Earnings Balance at beginning of period 6,775,193 6,672,275 6,773,289 6,546,079 Net income (loss) attributable to Murphy ( 2,973 ) 139,094 92,343 356,835 Cash dividends paid ( 46,387 ) ( 44,663 ) ( 139,799 ) ( 136,208 ) Balance at end of period 6,725,833 6,766,706 6,725,833 6,766,706 Accumulated Other Comprehensive Loss Balance at beginning of period ( 537,778 ) ( 571,645 ) ( 628,072 ) ( 521,117 ) Foreign currency translation, net of income taxes ( 38,027 ) 17,764 50,528 ( 34,588 ) Retirement and postretirement benefit plans, net of income taxes 874 1,174 2,613 2,998 Balance at end of period ( 574,931 ) ( 552,707 ) ( 574,931 ) ( 552,707 ) Treasury Stock Balance at beginning of period ( 2,075,823 ) ( 1,798,872 ) ( 1,995,018 ) ( 1,737,566 ) Repurchase of common stock — ( 196,187 ) ( 100,876 ) ( 302,681 ) Awarded restricted stock, net of forfeitures 243 41 20,314 45,229 Balance at end of period – 52,368,808 shares of common stock at September 30, 2025 and 49,257,269 shares of common stock at September 30, 2024, at cost ( 2,075,580 ) ( 1,995,018 ) ( 2,075,580 ) ( 1,995,018 ) Murphy Shareholders’ Equity 5,121,387 5,249,737 5,121,387 5,249,737 Noncontrolling Interest Balance at beginning of period 158,654 178,828 147,593 186,859 Net income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197 Distributions to noncontrolling interest owners ( 25,046 ) ( 35,408 ) ( 43,211 ) ( 96,618 ) Balance at end of period 128,265 155,438 128,265 155,438 Total Equity $ 5,249,652 $ 5,405,175 $ 5,249,652 $ 5,405,175 The accompanying notes are an integral part of these consolidated financial statements. 6 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report. Note A – Basis of Presentation The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at September 30, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2025 and 2024, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates. Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2024 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2025 are not necessarily indicative of future results. Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Reportable Segment Disclosures. In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures . The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. The Company adopted this standard in the fourth quarter of 2024. The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note P . Recent Accounting Pronouncements Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. Income Tax Disclosures . In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition. The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption. 7 Table of Contents 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 referred to as oil and natural gas) in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the United States (U.S.) and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil, natural gas and natural gas liquids (NGLs). For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP. U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials. Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments. Disaggregation of Revenue The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies. 8 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note C - Revenue from Contracts with Customers (Continued) The Company’s revenues and other income for the three-month and nine-month periods ended September 30, 2025 and 2024 were as follows. Three Months Ended September 30, Nine Months Ended September 30, (Thousands of dollars) 2025 2024 2025 2024 Net crude oil and condensate revenue United States - Onshore $ 209,051 $ 161,965 $ 484,610 $ 450,463 United States - Offshore 1 356,903 399,940 1,052,345 1,382,071 Canada - Onshore 18,115 20,852 45,428 54,305 Canada - Offshore 35,211 80,226 155,421 178,327 Other 88 ( 795 ) 3,036 3,414 Total crude oil and condensate revenue 619,368 662,188 1,740,840 2,068,580 Net natural gas liquids revenue United States - Onshore 13,736 8,134 32,117 23,281 United States - Offshore 1 8,353 9,812 25,913 29,523 Canada - Onshore 1,094 2,402 4,363 5,434 Total natural gas liquids revenue 23,183 20,348 62,393 58,238 Net natural gas revenue United States - Onshore 9,571 4,265 25,637 11,893 United States - Offshore 1 15,741 12,311 52,408 35,700 Canada - Onshore 53,103 54,057 195,483 170,871 Total natural gas revenue 78,415 70,633 273,528 218,464 Revenue from production 720,966 753,169 2,076,761 2,345,282 Sales of purchased natural gas 2 Canada - Onshore — — — 3,742 Total sales of purchased natural gas — — — 3,742 Total revenue from sales to customers 720,966 753,169 2,076,761 2,349,024 Gain (loss) on derivative instruments 5,722 ( 1,344 ) 7,071 ( 1,344 ) Gain on sale of assets and other operating income 6,297 6,506 10,434 9,834 Total revenues and other income $ 732,985 $ 758,331 $ 2,094,266 $ 2,357,514 1 Includes revenue attributable to noncontrolling interest in MP GOM. 2 Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and has risks and rewards of ownership. Sales of purchased natural gas are reported when the contractual performance obligations are satisfied. This occurs at the time the product is delivered to a third-party purchaser at the contractually determinable price. Contract Balances and Asset Recognition As of September 30, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 180.2 million and $ 178.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods. The Company has not entered into any revenue contracts that have financing components as of September 30, 2025. 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. 9 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note C – Revenue from Contracts with Customers (Continued) Performance Obligations The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity. For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods. The Company has entered into several long-term, fixed price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy. As of September 30, 2025, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract: Location Commodity End Date Description Approximate Volumes U.S. Natural Gas and NGLs Q2 2030 Deliveries from dedicated acreage in Eagle Ford Shale As produced Canada Natural Gas Q4 2025 Contracts to sell natural gas at USD index pricing 25 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCFD Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCFD Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCFD Canada Natural Gas Q4 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCFD Canada NGLs Q4 2026 Contracts to sell NGLs at CAD index pricing As produced The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes. Note D – Property, Plant and Equipment 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. As of September 30, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 115.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2025 and 2024. (Thousands of dollars) 2025 2024 Beginning balance at January 1 $ 72,055 $ 49,118 Additions pending the determination of proved reserves 43,091 28,452 Capitalized exploratory well costs charged to expense — ( 26,471 ) Balance at September 30 $ 115,146 $ 51,099 Capital additions of $ 43.1 million, for the nine months ended September 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well in Vietnam encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations. Capital additions also included long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) 10 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note D – Property, Plant and Equipment (Continued) exploration wells in the Gulf of America and long-lead equipment for Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire. Capital additions of $ 28.5 million, for the nine months ended September 30, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam. There were no capitalized well costs charged to dry hole expense for the nine months ended September 30, 2025. Capitalized well costs charged to dry hole expense of $ 26.5 million for the nine months ended September 30, 2024 were primarily related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America. The preceding table excludes well costs of $ 43.0 million incurred and expensed directly to dry hole for the nine months ended September 30, 2024. These costs primarily included $ 25.8 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America. The following table provides an aging of capitalized exploration well costs based on the date the drilling was completed for each individual well. September 30, 2025 2024 (Thousands of dollars) Amount No. of Wells Amount No. of Wells Aging of capitalized well costs: Zero to one year $ 17,562 5 $ 28,552 3 One to two years 75,171 3 — — Two to three years — — — — Three years or more 22,413 3 22,547 3 $ 115,146 11 $ 51,099 6 Of the $ 97.6 million of exploration well costs capitalized and classified as more than one year at September 30, 2025, $ 68.2 million was in Vietnam, $ 22.1 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. Property Additions On July 1, 2025, the Company purchased additional working interests in Eagle Ford Shale, in acreages primarily operated by Murphy, for $ 23.0 million. During the first quarter of 2025, Murphy purchased a floating production storage and offloading vessel (FPSO) from BW Offshore (UK) Limited for a gross purchase price of $ 125.0 million. An initial payment of $ 100.0 million was made in the first quarter of 2025, with the remaining balance paid during the second quarter of 2025, after certain contractual obligations were met. The FPSO will remain at its current location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited will continue to provide operations and maintenance services under a new five-year contract. Impairments There were pretax impairments of $ 115.0 million ($ 92.0 million excluding NCI) in the three and nine months ended September 30, 2025. The impairment related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions, as certain projects in the field were less competitive for capital allocation. There were no impairments in the three months ended September 30, 2024. There were pretax impairments of $ 34.5 million in the nine months ended September 30, 2024, related to the Calliope fie ld in Mississippi Canyon in the Gulf of America, in which operational issues led to a reserve reduction. 11 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note E – Financing Arrangements and Debt Revolving Credit Facility As of September 30, 2025, the Company had a $ 1.35 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on October 7, 2029. At September 30, 2025, the Company had $ 150.0 million of outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48 %. At September 30, 2025, the Company was in compliance with all covenants related to the RCF. Debt Extinguishment In May 2024, the Company paid a total of $ 50.5 million to complete the open market repurchases of $ 26.5 million aggregate principal of its 5.875 % senior notes due 2027 (2027 Notes) and $ 23.5 million aggregate principal of its 6.375 % senior notes due 2028 (2028 Notes). The cash costs of the debt extinguishment of $ 0.5 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2024. The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2027. Note F – Other Financial Information Supplemental Information to Statement of Cash Flows Nine Months Ended September 30, (Thousands of dollars) 2025 2024 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ ( 7,567 ) $ 80,603 (Increase) decrease in inventories ( 9,532 ) 1,823 (Increase) decrease in prepaid expenses 15 ( 8,131 ) Increase (decrease) in accounts payable and accrued liabilities ( 5,373 ) ( 43,231 ) Increase (decrease) in income taxes payable 1,984 771 Net decrease (increase) in non-cash working capital $ ( 20,473 ) $ 31,835 Supplementary disclosures: Net cash income taxes paid $ 9,217 $ 12,519 Interest paid, net of amounts capitalized of $ 5.3 million in 2025 and $ 10.8 million in 2024 52,426 48,708 Non-cash investing activities: Asset retirement costs capitalized $ 21,756 $ 19,949 (Increase) decrease in capital expenditure accrual 34,210 ( 2,177 ) 12 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note G – Asset Retirement Obligations The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment. A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the nine-month periods ended September 30, 2025 and 2024 are shown in the following table. (Thousands of dollars) September 30, 2025 September 30, 2024 Balance at beginning of year $ 1,008,884 $ 914,763 Accretion 43,153 39,068 Liabilities incurred 14,267 17,975 Revisions of previous estimates 7,489 2,452 Liabilities settled ( 32,145 ) ( 1,982 ) Changes due to translation of foreign currencies 6,147 ( 2,618 ) Balance at end of period 1,047,795 969,658 Current portion of liability ( 45,876 ) ( 39,693 ) Non-current portion of liability $ 1,001,919 $ 929,965 The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors. Note H – Employee and Retiree Benefit 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. 13 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note H – Employee and Retiree Benefit Plans (Continued) The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2025 and 2024. Three Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2025 2024 2025 2024 Service cost $ 1,683 $ 1,706 $ 84 $ 135 Interest cost 8,495 8,398 708 782 Expected return on plan assets ( 8,967 ) ( 8,366 ) — — Estimated defined contribution provision 62 54 — — Amortization of prior service (credit) cost 492 579 ( 133 ) ( 133 ) Recognized actuarial (gain) loss 1,918 2,363 ( 1,057 ) ( 812 ) Total net periodic benefit expense $ 3,683 $ 4,734 $ ( 398 ) $ ( 28 ) Nine Months Ended September 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2025 2024 2025 2024 Service cost $ 5,049 $ 5,118 $ 252 $ 405 Interest cost 25,375 25,182 2,124 2,346 Expected return on plan assets ( 26,791 ) ( 25,082 ) — — Estimated defined contribution provision 184 163 — — Amortization of prior service (credit) cost 1,475 1,737 ( 399 ) ( 399 ) Recognized actuarial (gain) loss 5,723 7,084 ( 3,170 ) ( 2,436 ) Total net periodic benefit expense $ 11,015 $ 14,202 $ ( 1,193 ) $ ( 84 ) The components of net periodic benefit expense, other than the service cost, are recorded in “Other income (loss)” in the Consolidated Statements of Operations. During the nine-month period ended September 30, 2025, the Company made contributions of $ 26.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 4.5 million. Note I – Incentive Plans The Company recognizes expenses for all share-based and cash-based incentive compensation in the Consolidated Statements of Operations using a fair value-based measurement method over the applicable vesting periods. The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan). All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan. The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term. Additional information on the 2025 Long-Term Plan can be found in Exhibit A to definitive proxy statement filed on March 28, 2025 . Similar to the 2020 Long-Term Plan, the 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock and stock-based awards to employees. These grants may be in the form of stock 14 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note I – Incentive Plans (Continued) options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents and other stock-based incentives. Shares issued pursuant to awards granted under the 2025 Long-Term Plan and the previous 2020 Long-Term Plan, may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Share awards that have been canceled, expired, forfeited, or otherwise not issued will not count as shares issued under both plans. During the nine months ended September 30, 2025, the Committee granted the following awards from the 2020 Long-Term Plan and the 2025 Long-Term Plan: Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Performance-based RSUs (TSR) 1 520,150 February 4, 2025 $ 22.11 Monte Carlo Performance-based RSUs (ROACE) 1 129,990 February 4, 2025 $ 25.98 Average Stock Price Time-based RSUs (Stock-Settled) 2 470,440 February 4, 2025 $ 25.98 Average Stock Price Time-based RSUs (Cash-Settled) 2 771,390 February 4, 2025 $ 25.98 Average Stock Price Performance-based RSUs (TSR) 1 6,070 August 11, 2025 $ 19.65 Monte Carlo Performance-based RSUs (ROACE) 1 1,520 August 11, 2025 $ 23.09 Average Stock Price Time-based RSUs (Stock-Settled) 2 5,060 August 11, 2025 $ 23.09 Average Stock Price 1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) and Return on Average Capital Employed (ROACE) performance goals and are scheduled to vest three years from the date of grant if performance conditions are met. 2 Time-based RSUs generally vest on the third anniversary of the date of grant. The Company also maintains a Stock Plan for Non-Employee Directors (NEDs) that permits the issuance of RSUs, 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 Stock Plan for NEDs (the 2021 NED Plan) and the 2018 Stock Plan for NEDs. All awards granted on or after May 12, 2021 were made under the 2021 NED Plan. During the nine months ended September 30, 2025, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan: Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Time-Based RSUs 1 74,970 February 5, 2025 $ 26.68 Closing Stock Price Time-Based RSUs 2 2,114 March 31, 2025 $ 28.40 Closing Stock Price Time-Based RSUs 2 2,668 June 30, 2025 $ 22.50 Closing Stock Price Time-Based RSUs 2 2,112 September 30, 2025 $ 28.41 Closing Stock Price 1 Non-Employee Directors’ time-based RSUs are scheduled to vest on the first anniversary of the date of grant. Non-Employee Directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election. These unvested time-based RSUs are included in the table above, will vest in one year , and become deferred RSUs. 2 Effective January 1, 2024, Non-Employee Directors can elect to receive their annual retainers in the form of deferred RSUs. Director fees that are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election. 15 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note I – Incentive Plans (Continued) Amounts recognized in the financial statements with respect to share-based plans are shown in the following table. Nine Months Ended September 30, (Thousands of dollars) 2025 2024 Compensation charged against income before tax benefit $ 33,884 $ 27,044 Related income tax benefit recognized in income 4,882 3,627 Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $ 1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the current tax law. Note J – Net Income (Loss) Per Common Share Net income (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income (loss) per common share for the three-month and nine-month periods ended September 30, 2025 and 2024. The following table reconciles the weighted-average shares outstanding used for these computations. Three Months Ended September 30, Nine Months Ended September 30, (Weighted-average shares) 2025 2024 2025 2024 Basic method 142,730,808 149,384,354 143,245,219 151,400,726 Dilutive restricted stock units 1 — 968,428 730,291 1,036,653 Diluted method 142,730,808 150,352,782 143,975,510 152,437,379 1 Due to a net loss recognized by the Company for the three months ended September 30, 2025, no unvested stock awards were included in the computation of the diluted net income (loss) per common share as the effect would have been antidilutive. The following table reflects the dilutive restricted stock units during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 Antidilutive restricted stock units excluded from diluted shares 908,021 — — — Note K – Income Taxes The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and nine-month periods ended September 30, 2025 and 2024, the Company’s effective income tax rates were as follows: 2025 2024 Three months ended September 30, ( 113.5 )% 1.4 % Nine months ended September 30, 24.6 % 13.3 % The effective tax rate for the three-month period ended September 30, 2025 was below the U.S. statutory tax rate of 21% due to the impact of the Company's reported pre-tax loss. Several factors affect the rate including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available, foreign currency translation adjustments, no tax benefit applied to the pretax loss of the noncontrolling interest in MP GOM, and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate. The negative impact on the effective tax rate was partially offset by the tax effect of stock-based compensation and U.S. state tax expense. 16 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note K – Income Taxes (Continued) The effective tax rate for the three-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend, which resulted in an income tax benefit of $ 33.7 million. The effective tax rate for the nine-month period ended September 30, 2025 was above the U.S. statutory tax rate of 21% primarily due to several factors including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate; U.S. state tax expense; stock-based compensation; foreign currency translation adjustments; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received. The effective tax rate for the nine-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend and no tax applied to the pretax income of the noncontrolling interest in MP GOM. 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 September 30, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. On July 4, 2025, the current U.S. Administration signed into law the legislation commonly referred to as the One Big Beautiful Bill Act (OBBBA), which includes a broad range of tax reform provisions affecting corporations. The OBBBA, among other changes, permanently reinstates the "bonus" depreciation provisions that allow for the immediate expensing of 100% of the cost of certain qualified property acquired and placed in service after January 19, 2025, permanently reinstates the elective immediate expensing of domestic research and experimental expenditures paid or incurred in tax years beginning after December 31, 2024 (with a special transition rule that allows accelerated deduction of the remaining unamortized balance of capitalized domestic research and experimental expenditures), and permanently relaxes the limitation on the deductibility of business interest effective for tax years beginning after December 31, 2024. The OBBBA also modifies certain international tax provisions effective for tax years beginning after December 31, 2025. The Company evaluated the effects of the OBBBA in accordance with ASC 740, Income Taxes, and determined that the legislation did not have a material impact on its consolidated financial statements for the period ended September 30, 2025. The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA. Note L – Financial Instruments and Risk Management Murphy, at times, uses derivative instruments 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. 17 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note L – Financial Instruments and Risk Management (Continued) 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 derivatives outstanding at September 30, 2025 and 2024. Commodity Price Risks The Company is subject to commodity price risk related to products it produces and sells. During the third quarter of 2025, the Company had the following open natural gas swap 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. At September 30, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural Gas 60 $ 3.74 10/1/2025 12/31/2025 During the nine months ended September 30, 2025 and September 30, 2024, the Company did no t have any crude oil derivative contracts. At September 30, 2024, the Company had natural gas derivative contracts outstanding for 20 MMCF/d at an average price of $ 3.20 /MCF. At September 30, 2025 and December 31, 2024, the fair value of derivative instruments not designated as hedging instruments are presented in the following table: (Thousands of dollars) Asset (Liability) Derivatives Fair Value Type of Derivative Contract Balance Sheet Location September 30, 2025 December 31, 2024 Commodity swaps Accounts receivable $ 2,197 $ — Commodity swaps Accounts payable $ — $ ( 1,707 ) For the three-month and nine-month periods ended September 30, 2025 and 2024, 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) Gain (Loss) (Thousands of dollars) Three Months Ended September 30, Nine Months Ended September 30, Type of Derivative Contract Statement of Operations Location 2025 2024 2025 2024 Commodity swaps Gain (loss) on derivative instruments $ 5,722 $ ( 1,344 ) $ 7,071 $ ( 1,344 ) 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. 18 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note L – Financial Instruments and Risk Management (Continued) The fair value measurements for these assets and liabilities at September 30, 2025 and December 31, 2024, are shown in the following table. September 30, 2025 December 31, 2024 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Commodity swaps $ — $ 2,197 $ — $ 2,197 $ — $ — $ — $ — $ — $ 2,197 $ — $ 2,197 $ — $ — $ — $ — Liabilities: Commodity swaps $ — $ — $ — $ — $ — $ 1,707 $ — $ 1,707 Nonqualified employee savings plan 21,168 — — 21,168 19,469 — — 19,469 $ 21,168 $ — $ — $ 21,168 $ 19,469 $ 1,707 $ — $ 21,176 The commodity swaps receivable as of September 30, 2025 was $ 2.2 million and recorded as “Accounts receivable” in the Consolidated Balance Sheets. The fair value of commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in the fair value of natural gas 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 offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at September 30, 2025 and December 31, 2024. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2025 and December 31, 2024. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, were minimal. September 30, 2025 December 31, 2024 (Thousands of dollars) Carrying Amount Fair Value Carrying Amount Fair Value Financial liabilities: Current and long-term debt $ 1,426,153 $ 1,366,561 $ 1,275,374 $ 1,185,961 19 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note L – Financial Instruments and Risk Management (Continued) Fair Values – Nonrecurring For the three and nine months ended September 30, 2025, an impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) was triggered for the Dalmatian field in the Gulf of America due to reserve reductions, as certain projects in the field were less competitive for capital allocation. There were no impairment expenses incurred in the three months ended September 30, 2024. In the nine months ended September 30, 2024, an impairment charge of $ 34.5 million was triggered for the Calliope field, due to operational issues that led to reserve reductions. The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region. The fair value information associated with the impaired properties is presented in the following tables. Nine Months Ended September 30, 2025 Net Book Value Prior to Impairment Total Pretax Impairment Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 Property, plant and equipment: Impaired proved properties United States - Offshore $ — $ — $ 42,397 $ 157,399 $ 115,002 Nine Months Ended September 30, 2024 Net Book Value Prior to Impairment Total Pretax Impairment Fair Value ( Thousands of dollars ) Level 1 Level 2 Level 3 Property, plant and equipment: Impaired proved properties United States - Offshore $ — $ — $ 437 $ 34,965 $ 34,528 Note M – Accumulated Other Comprehensive Loss The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2024 and September 30, 2025, and the changes during the nine-month period ended September 30, 2025, are presented net of taxes in the following table. (Thousands of dollars) Foreign Currency Translation Gains (Losses) Retirement and Postretirement Benefit Plan Adjustments Total Balance at December 31, 2024 $ ( 516,324 ) $ ( 111,748 ) $ ( 628,072 ) Components of other comprehensive income (loss): Before reclassifications to income 50,528 — 50,528 Reclassifications to income ¹ — 2,613 2,613 Net other comprehensive income (loss) 50,528 2,613 53,141 Balance at September 30, 2025 $ ( 465,796 ) $ ( 109,135 ) $ ( 574,931 ) 1 Reclassifications before taxes of $ 3.1 million are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2025. See Note H for additional information. Related income taxes of $ 0.5 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2025. 20 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note N – Environmental and Other Contingencies The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; trade policies, tariffs and other trade restrictions; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company. ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other greenhouse gas (GHG) emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased. Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this item, the Company will be using a threshold of $ 1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $ 1.0 million threshold. In recent years, there has been an increase in regulatory oversight of the oil and natural gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and natural gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the U.S. EPA. However, the U.S. EPA has since published an interim final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on 21 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note N – Environmental and Other Contingencies (Continued) or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition. There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity. LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period. Note O – Common Stock Issued and Outstanding Activity in the number of shares of common stock issued and outstanding for the nine-month periods ended September 30, 2025 and 2024 is shown below. ( Number of shares outstanding ) September 30, 2025 September 30, 2024 Beginning of period 145,845,124 152,748,642 Restricted stock awards 1 500,146 1,103,503 Treasury shares purchased ( 3,613,450 ) ( 8,008,786 ) End of period 142,731,820 145,843,359 1 Shares issued upon award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares. On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $ 1,100.0 million of its common stock. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors. During the three months ended September 30, 2025, the Company did no t repurchase any shares of its common stock. During the nine months ended September 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $ 100.0 million ($ 100.9 million including excise taxes and fees). As of September 30, 2025, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program. 22 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note P – Business Segments 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, including interest income, other gains and losses, interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia, and U.S. refining and marketing operations as discontinued operations for all periods presented. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the Chief Operating Decision Maker (CODM). “Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment. 23 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note P – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, Other, and Discontinued Operations Consolidated Total Three Months Ended September 30, 2025 Revenue from production $ 613.4 $ 107.5 $ 0.1 $ 721.0 $ — $ 721.0 Gain on sales of assets and other operating income 0.3 0.5 — 0.8 11.4 12.2 Revenues from external customers 613.7 108.0 0.1 721.8 11.4 733.2 Lease operating expenses Lease operating expenses and taxes other than income 95.6 41.2 0.4 137.2 — 137.2 Repair and maintenance 13.9 1.4 — 15.3 — 15.3 Workovers 31.8 0.1 — 31.9 — 31.9 Total lease operating expenses 141.3 42.7 0.4 184.4 — 184.4 Severance and ad valorem taxes 11.9 0.4 — 12.3 — 12.3 Transportation, gathering and processing 23.3 24.8 — 48.1 — 48.1 Selling and general expenses 1.9 5.4 2.2 9.5 21.4 30.9 Exploration Expenses Geological and geophysical 19.1 0.1 1.1 20.3 — 20.3 Dry holes and previously suspended exploration costs ( 0.1 ) — 0.9 0.8 — 0.8 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 3.5 0.1 7.8 11.4 — 11.4 Total exploration expenses 22.5 0.2 9.8 32.5 — 32.5 Depreciation, depletion and amortization 242.1 39.3 — 281.4 2.1 283.5 Impairment of assets 115.0 — — 115.0 — 115.0 Accretion of asset retirement obligations 11.8 2.6 0.2 14.6 0.1 14.7 Other operating expenses 5.7 0.1 0.2 6.0 ( 0.1 ) 5.9 Interest Income ( 0.4 ) — — ( 0.4 ) ( 2.7 ) ( 3.1 ) Interest expense, net of capitalization — 0.1 — 0.1 24.6 24.7 Income tax expense Current income tax expense (benefit) 1.0 ( 1.7 ) — ( 0.7 ) 2.8 2.1 Deferred income tax expense (benefit) 7.9 ( 0.2 ) ( 0.4 ) 7.3 ( 5.2 ) 2.1 Total income tax expense (benefit) 8.9 ( 1.9 ) ( 0.4 ) 6.6 ( 2.4 ) 4.2 Other segment costs (income) 0.8 0.4 ( 0.3 ) 0.9 ( 12.5 ) ( 11.6 ) Segment income (loss) - including NCI 1 $ 28.9 $ ( 6.1 ) $ ( 12.0 ) $ 10.8 $ ( 19.1 ) $ ( 8.3 ) Additions to property, plant, equipment $ 111.6 $ 26.0 $ 41.1 $ 178.7 $ 2.3 $ 181.0 Total assets at quarter-end 6,848.1 1,981.8 411.8 9,241.7 491.1 9,732.8 1 Includes results attributable to a noncontrolling interest in MP GOM. 24 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note P – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, Other, and Discontinued Operations Consolidated Total Three Months Ended September 30, 2024 Revenue from production $ 596.5 $ 157.6 $ ( 0.8 ) $ 753.1 $ — $ 753.1 Gain on sales of assets and other operating income 0.5 0.3 — 1.0 4.2 5.2 Revenues from external customers 597.0 157.9 ( 0.8 ) 754.1 4.2 758.3 Lease operating expenses Lease operating expenses and taxes other than income 108.0 51.7 0.3 160.0 — 160.0 Repair and maintenance 15.1 1.8 — 16.9 — 16.9 Workovers 45.7 0.3 — 46.0 — 46.0 Total lease operating expenses 168.8 53.8 0.3 222.9 — 222.9 Severance and ad valorem taxes 10.1 0.3 — 10.5 — 10.5 Transportation, gathering and processing 26.3 21.2 — 47.5 — 47.5 Selling and general expenses ( 1.7 ) 4.7 1.9 4.9 20.0 24.9 Exploration Expenses — Geological and geophysical 9.9 0.1 2.8 12.8 — 12.8 Dry holes and previously suspended exploration costs 10.8 — 0.4 11.2 — 11.2 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 2.5 0.2 4.7 7.3 — 7.3 Total exploration expenses 23.2 0.3 7.9 31.3 — 31.3 Depreciation, depletion and amortization 179.3 42.8 — 222.1 1.5 223.6 Impairment of assets — — — — — — Accretion of asset retirement obligations 10.9 2.1 0.2 13.2 — 13.2 Other operating expenses 4.8 0.1 0.5 5.4 0.1 5.5 Interest income ( 0.8 ) — — ( 0.8 ) ( 3.1 ) ( 3.9 ) Interest expense, net of capitalization 0.3 — — 0.3 21.0 21.3 Income tax expense Current income tax expense (benefit) 0.8 8.2 ( 0.1 ) 8.9 2.1 11.0 Deferred income tax expense (benefit) 34.4 0.2 ( 34.0 ) 0.6 ( 9.5 ) ( 8.9 ) Total income tax expense (benefit) 35.2 8.4 ( 34.1 ) 9.5 ( 7.4 ) 2.1 Other segment costs (income) 1.8 — 0.1 1.9 6.4 8.3 Segment income (loss) - including NCI 1 $ 138.8 $ 24.2 $ 22.4 $ 185.4 $ ( 34.3 ) $ 151.1 Additions to property, plant, equipment $ 130.2 $ 13.5 $ 20.5 $ 164.2 $ 8.0 $ 172.2 Total assets at quarter-end 7,088.3 2,043.0 266.6 9,397.9 318.5 9,716.4 1 Includes results attributable to a noncontrolling interest in MP GOM. 25 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note P – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, Other, and Discontinued Operations Consolidated Total Nine Months Ended September 30, 2025 Revenue from production $ 1,673.1 $ 400.7 $ 3.0 $ 2,076.8 $ — $ 2,076.8 Gain on sales of assets and other operating income 3.6 1.3 — 4.9 15.0 19.9 Revenues from external customers 1,676.7 402.0 3.0 2,081.7 15.0 2,096.7 Lease operating expenses Lease operating expenses and taxes other than income 295.9 133.1 1.6 430.6 — 430.6 Repair and maintenance 38.0 4.0 — 42.0 — 42.0 Workovers 131.5 0.9 — 132.4 — 132.4 Total lease operating expenses 465.4 138.0 1.6 605.0 — 605.0 Severance and ad valorem taxes 30.7 1.1 — 31.8 — 31.8 Transportation, gathering and processing 82.4 68.7 — 151.1 — 151.1 Selling and general expenses 8.7 17.1 6.7 32.5 66.2 98.7 Exploration Expenses Geological and geophysical 23.0 0.1 1.6 24.7 — 24.7 Dry holes and previously suspended exploration costs ( 0.9 ) — 1.0 0.1 — 0.1 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 9.8 0.2 22.6 32.6 — 32.6 Total exploration expenses 31.9 0.3 25.2 57.4 — 57.4 Depreciation, depletion and amortization 619.7 109.8 1.2 730.7 6.2 736.9 Impairment of assets 115.0 — — 115.0 — 115.0 Accretion of asset retirement obligations 34.8 7.7 0.6 43.1 0.1 43.2 Other operating expenses 9.7 1.8 ( 1.1 ) 10.4 3.0 13.4 Interest Income ( 1.3 ) — — ( 1.3 ) ( 8.7 ) ( 10.0 ) Interest expense, net of capitalization — 0.1 0.1 0.2 73.1 73.3 Income tax expense Current income tax expense (benefit) 2.2 12.3 0.2 14.7 ( 0.1 ) 14.6 Deferred income tax expense (benefit) 51.6 ( 1.8 ) ( 1.1 ) 48.7 ( 25.4 ) 23.3 Total income tax expense (benefit) 53.8 10.5 ( 0.9 ) 63.4 ( 25.5 ) 37.9 Other segment cost 2.6 1.1 — 3.7 23.1 26.8 Segment income (loss) - including NCI 1 $ 223.3 $ 45.8 $ ( 30.4 ) $ 238.7 $ ( 122.5 ) $ 116.2 Additions to property, plant, equipment $ 586.4 $ 127.0 $ 94.4 $ 807.8 $ 9.2 $ 817.0 Total assets at quarter-end 6,848.1 1,981.8 411.8 9,241.7 491.1 9,732.8 1 Includes results attributable to a noncontrolling interest in MP GOM. 26 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note P – Business Segments (Continued) Exploration and Production ( Millions of dollars ) United States 1 Canada Other Total E&P Corporate, Other, and Discontinued Operations Consolidated Total Nine Months Ended September 30, 2024 Revenue from production $ 1,933.0 $ 408.9 $ 3.4 $ 2,345.3 $ — $ 2,345.3 Sales of purchased natural gas — 3.7 — 3.7 — 3.7 Gain on sales of assets and other operating income 3.1 1.2 — 4.3 4.2 8.5 Revenues from external customers 1,936.1 413.8 3.4 2,353.3 4.2 2,357.5 Lease operating expenses Lease operating expenses and taxes other than income 348.6 142.1 1.0 491.7 — 491.7 Repair and maintenance 41.9 3.2 — 45.1 — 45.1 Workovers 177.2 2.8 — 180.0 — 180.0 Total lease operating expenses 567.7 148.1 1.0 716.8 — 716.8 Severance and ad valorem taxes 29.9 1.1 — 31.0 — 31.0 Transportation, gathering and processing 97.1 60.4 — 157.5 — 157.5 Costs of purchased natural gas — 3.1 — 3.1 — 3.1 Selling and general expenses ( 5.2 ) 14.2 4.9 13.9 65.0 78.9 Exploration Expenses Geological and geophysical 13.5 0.2 8.6 22.3 — 22.3 Dry holes and previously suspended exploration costs 67.9 — 1.7 69.6 — 69.6 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 9.6 0.2 16.7 26.5 — 26.5 Total exploration expenses 91.0 0.4 27.0 118.4 — 118.4 Depreciation, depletion and amortization 528.3 114.1 0.9 643.3 7.0 650.3 Impairment of assets 34.5 — — 34.5 — 34.5 Accretion of asset retirement obligations 32.0 6.4 0.6 39.0 0.1 39.1 Other operating expenses 8.0 2.1 0.6 10.7 ( 0.2 ) 10.5 Interest Income ( 21.6 ) — — ( 21.6 ) ( 8.6 ) ( 30.2 ) Interest expense, net of capitalization 0.3 0.2 0.1 0.6 61.7 62.3 Income tax expense Current income tax expense 2.9 10.5 0.2 13.6 6.2 19.8 Deferred income tax expense (benefit) 106.9 0.7 ( 33.7 ) 73.9 ( 28.8 ) 45.1 Total income tax expense (benefit) 109.8 11.2 ( 33.5 ) 87.5 ( 22.6 ) 64.9 Other segment costs (income) 5.3 — 0.3 5.6 ( 7.2 ) ( 1.6 ) Segment income (loss) - including NCI 1 $ 459.0 $ 52.5 $ 1.5 $ 513.0 $ ( 91.0 ) $ 422.0 Additions to property, plant, equipment $ 511.3 $ 122.9 $ 44.6 $ 678.8 $ 16.4 $ 695.2 Total assets at quarter-end 7,088.3 2,043.0 266.6 9,397.9 318.5 9,716.4 1 Includes results attributable to a noncontrolling interest in MP GOM. 27 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note Q – 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 natural gas field equipment. Options to extend lease terms are at the Company’s discretion. Early lease terminations are at the Company’s discretion and/or the mutual agreement between the Company and lessor. Purchase options also exist for certain leases. During the third quarter of 2025, the Company exercised an option to extend an operating lease pertaining to a drill ship used in our offshore business. This resulted in an increase of $ 167.1 million (discounted) to our right-of-use assets and operating lease liabilities at September 30, 2025. Maturity of Lease Liabilities (Thousands of dollars) Operating Leases Finance Leases Total 2025 $ 60,970 $ 319 $ 61,289 2026 248,750 1,274 250,024 2027 141,648 1,274 142,922 2028 62,259 1,275 63,534 2029 59,471 464 59,935 Remaining 419,202 958 420,160 Total future minimum lease payments 992,300 5,564 997,864 Less imputed interest ( 199,449 ) ( 1,352 ) ( 200,801 ) Present value of lease liabilities 1 $ 792,851 $ 4,212 $ 797,063 1 Includes both the current and long-term portion of the lease liabilities. Lease Term and Discount Rate September 30, 2025 December 31, 2024 Weighted average remaining lease term: Operating leases 8 years 8 years Finance leases 5 years 6 years Weighted average discount rate: Operating leases 5.5 % 5.7 % Finance leases 4.9 % 4.9 % 28 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended September 30, 2025 included under “ Item 1. Financial Statements ” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2024. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “ Forward-Looking Statements ” at the end of this section. Overview Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The Company boasts over a century of strong execution and innovative, full-cycle development capabilities, with a focus on value creation to enhance shareholder returns. The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire. The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted. Significant Company financial and operational highlights during the third quarter of 2025 were as follows: • Increased production to 206,936 barrels of oil equivalent (BOE) per day (including NCI), up from 191,273 BOE per day in the third quarter of 2024, and up from 196,315 BOE per day in the second quarter of 2025 • Paid down $50.0 million of debt under the RCF and returned $46.4 million ($0.325 per share, or $1.30 per share annualized) to shareholders through a quarterly dividend Subsequent to the third quarter, Murphy completed the installation of the LDV-A platform jacket and initiated development drilling at the Lac Da Vang (Golden Camel) development project in Vietnam. Murphy Oil Corporation’s net loss from continuing operations, including noncontrolling interest, for the three months ended September 30, 2025, was $7.8 million compared to net income of $151.7 million for the same period in 2024. The results for 2025 were impacted by higher impairment expense ($115.0 million), higher depreciation, depletion and amortization expenses (DD&A) ($59.8 million), and lower revenues from production ($32.2 million). These changes were partially offset by lower lease operating expenses ($38.5 million) and higher other income ($19.2 million). The impairment expense during the quarter related to the Dalmatian field in the Gulf of America that resulted from reserve reductions, as certain projects in the field were less competitive for capital allocation. The increase in DD&A resulted from higher total production levels and elevated rates in the Gulf of America. Lower revenues during the quarter were mainly the result of lower oil prices, partially offset by higher overall production volumes. Lower lease operating expenses were primarily due to lower workover costs and production handling fees in the Gulf of America and cost-savings initiatives in the Eagle Ford Shale, and were partially offset by higher production in the Eagle Ford Shale. Higher other income was the result of unrealized foreign exchange gains. For the three months ended September 30, 2025, total hydrocarbon production was 206,936 barrels of oil equivalent per day, an increase of 8% compared to the third quarter of 2024. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in both the U.S. and Canada. Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year at Karnes and Catarina. Higher production in Canada Onshore relates to better well performance at Tupper Montney. Lower production in the Gulf of America and Canada Offshore was due to natural decline and both planned and unplanned downtime for mechanical issues. Net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2025, was $116.1 million, a decrease of $308.1 million compared to the same period in 2024. Lower net income from continuing operations was largely driven by lower revenues from production ($268.5 29 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Overview (Continued) million), higher DD&A ($86.6 million), higher impairment expense ($80.5 million), and lower other income ($48.5 million). These changes were partially offset by lower lease operating expenses ($111.8 million), lower exploration expenses ($61.0 million), and lower income tax expenses ($26.9 million). Lower revenues were primarily due to the lower price of oil, combined with lower production in the Gulf of America, and were partially offset by higher production in the Eagle Ford Shale, and the higher price of natural gas. Higher DD&A was due to higher production in the Eagle Ford Shale and higher rates in the Gulf of America, partially offset by lower production volumes in the Gulf of America. Higher impairment expense was related to the Dalmatian field in the Gulf or America. Lower other income was primarily the result of unrealized foreign exchange losses. Lower lease operating expenses related to lower workover costs and production handling fees in the Gulf of America, combined with lower operating costs due to the acquisition of the BW Pioneer FPSO earlier this year. Cost reduction activities in the Eagle Ford Shale also contributed to overall lower lease operating expenses. Lower exploration expenses were primarily due to no dry hole expense recorded in 2025 (2024: Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America). Lower dry hole costs were partially offset by higher exploration activity in Côte d'Ivoire. Lower income tax expense was due to lower net income for the period. For the nine months ended September 30, 2025, total hydrocarbon production was 189,035 barrels of oil equivalent per day, an increase of 2% compared to the same period in 2024. Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year in Karnes and Catarina. Higher production in Canada Onshore relates to better well performance at Tupper Montney. Lower production in the Gulf of America related to planned and unplanned downtime, and was partially offset by new wells online. Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. Geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services. At September 30, 2025, the West Texas Intermediate (WTI) crude oil price was $62.37 per barrel, whereas the crude oil price at the end of October 2025 was $60.98, reflecting a 2% decrease in price. As of November 3, 2025 closing, the NYMEX WTI forward curve price for the remainder of 2025 was $61.05 per barrel. Reductions in commodity prices will reduce the Company’s future profits and operating cash flows. 30 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations Murphy’s Net income (loss) by type of business and geographic segment is presented below: Income (Loss) Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2025 2024 2025 2024 Exploration and production United States $ 28.9 $ 138.8 $ 223.3 $ 459.0 Canada (6.1) 24.2 45.8 52.5 Other (12.0) 22.4 (30.4) 1.5 Total exploration and production 10.8 185.4 238.7 513.0 Corporate and other (18.6) (33.7) (122.7) (88.9) Income (loss) from continuing operations (7.8) 151.7 116.0 424.1 Discontinued operations, net of tax 1 (0.5) (0.6) 0.2 (2.1) Net income (loss) including noncontrolling interest (8.3) 151.1 116.2 422.0 Less: Net income (loss) attributable to noncontrolling interest (5.3) 12.0 23.9 65.2 Net income (loss) attributable to Murphy $ (3.0) $ 139.1 $ 92.3 $ 356.8 1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. 31 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Exploration and Production Continuing Operations The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted. The following is a summarized statement of operations for E&P continuing operations: Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2025 2024 2025 2024 Revenues and other income Revenue from production $ 721.0 $ 753.2 $ 2,076.8 $ 2,345.3 Sales of purchased natural gas — — — 3.7 Other income 0.8 0.9 4.9 4.3 Total revenues and other income 721.8 754.1 2,081.7 2,353.3 Costs and expenses Lease operating expenses 184.4 222.9 605.0 716.8 Severance and ad valorem taxes 12.3 10.5 31.8 31.0 Transportation, gathering and processing 48.1 47.5 151.1 157.5 Costs of purchased natural gas — — — 3.1 Depreciation, depletion and amortization 281.4 222.1 730.7 643.3 Impairment of assets 115.0 — 115.0 34.5 Accretion of asset retirement obligations 14.6 13.2 43.1 39.0 Exploration expenses, including undeveloped lease amortization 32.5 31.2 57.4 118.4 Selling and general expenses 9.5 5.0 32.5 14.0 Other 6.6 6.7 13.0 (4.7) Results of operations before taxes 17.4 195.0 302.1 600.4 Income tax provisions 6.6 9.6 63.4 87.4 Results of operations (excluding Corporate segment) 1 $ 10.8 $ 185.4 $ 238.7 $ 513.0 1 Includes results attributable to a noncontrolling interest in MP GOM. 32 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Pricing The following table contains the weighted average sales prices for the three-month and nine-month periods ended September 30, 2025 and 2024: Three Months Ended September 30, Nine Months Ended September 30, (Weighted average sales prices) 2025 2024 2025 2024 Crude oil and condensate – dollars per barrel United States - Onshore $ 65.48 $ 75.49 $ 66.24 $ 77.55 United States - Offshore 1 67.00 75.65 67.81 78.42 Canada - Onshore 2 56.33 66.18 59.46 68.62 Canada - Offshore 2 69.42 80.06 70.17 82.83 Other 2 — — 72.97 78.20 Natural gas liquids – dollars per barrel United States - Onshore 18.57 19.05 19.92 19.71 United States - Offshore 1 20.18 22.50 21.85 23.20 Canada - Onshore 2 26.88 34.00 32.54 34.64 Natural gas – dollars per thousand cubic feet United States - Onshore 2.64 1.77 2.87 1.77 United States - Offshore 1 3.39 2.28 3.73 2.30 Canada - Onshore 2 1.22 1.34 1.68 1.56 1 Prices include the effect of noncontrolling interest in MP GOM. 2 U.S. dollar equivalent. The following table contains benchmark prices relevant to the Company for the three-month and nine-month periods ended September 30, 2025 and 2024: Three Months Ended September 30, Nine Months Ended September 30, (Average price for the period) 2025 2024 2025 2024 Oil and NGLs WTI ($/BBL) $ 64.93 $ 75.10 $ 66.70 $ 77.54 Natural gas NYMEX ($/MMBTU) 3.03 2.09 3.49 2.18 AECO (C$/MCF) 0.63 0.69 1.50 1.45 33 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Production Volumes The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2025 and 2024. For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 . Three Months Ended September 30, Nine Months Ended September 30, (Barrels per day unless otherwise noted) 2025 2024 2025 2024 Net crude oil and condensate United States - Onshore 34,703 23,320 26,797 21,199 United States - Offshore 1 56,071 59,282 56,835 64,042 Canada - Onshore 3,495 3,425 2,799 2,888 Canada - Offshore 5,518 7,880 6,658 7,219 Other 278 171 276 221 Total net crude oil and condensate 100,065 94,078 93,365 95,569 Net natural gas liquids United States - Onshore 8,042 4,640 5,905 4,312 United States - Offshore 1 4,500 4,739 4,344 4,644 Canada - Onshore 442 768 491 572 Total net natural gas liquids 12,984 10,147 10,740 9,528 Net natural gas – thousands of cubic feet per day United States - Onshore 39,411 26,223 32,711 24,556 United States - Offshore 1 50,477 58,747 51,528 56,565 Canada - Onshore 473,431 437,316 425,342 400,012 Total net natural gas 563,319 522,286 509,581 481,133 Total net hydrocarbons - including NCI 2,3 206,936 191,273 189,035 185,286 Noncontrolling interest Net crude oil and condensate – barrels per day (5,998) (6,188) (5,950) (6,467) Net natural gas liquids – barrels per day (228) (193) (214) (207) Net natural gas – thousands of cubic feet per day (1,963) (1,947) (1,715) (2,008) Total noncontrolling interest 2,3 (6,553) (6,706) (6,450) (7,009) Total net hydrocarbons - excluding NCI 2,3 200,383 184,567 182,585 178,277 1 Includes net volumes attributable to a noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 3 NCI – noncontrolling interest in MP GOM. 34 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Sales Volumes The following table contains hydrocarbons sold during the three-month and nine-month periods ended September 30, 2025 and 2024. For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 . Three Months Ended September 30, Nine Months Ended September 30, (Barrels per day unless otherwise noted) 2025 2024 2025 2024 Net crude oil and condensate United States - Onshore 34,703 23,320 26,797 21,199 United States - Offshore 1 57,903 57,467 56,849 64,317 Canada - Onshore 3,495 3,425 2,799 2,888 Canada - Offshore 5,513 10,892 8,114 7,857 Other — — 152 159 Total net crude oil and condensate 101,614 95,104 94,711 96,420 Net natural gas liquids United States - Onshore 8,042 4,640 5,905 4,312 United States - Offshore 1 4,500 4,739 4,344 4,644 Canada - Onshore 442 768 491 572 Total net natural gas liquids 12,984 10,147 10,740 9,528 Net natural gas – thousands of cubic feet per day United States - Onshore 39,411 26,223 32,711 24,556 United States - Offshore 1 50,477 58,747 51,528 56,565 Canada - Onshore 473,431 437,316 425,342 400,012 Total net natural gas 563,319 522,286 509,581 481,133 Total net hydrocarbons - including NCI 2,3 208,484 192,299 190,381 186,137 Noncontrolling interest Net crude oil and condensate – barrels per day (6,273) (5,920) (5,954) (6,503) Net natural gas liquids – barrels per day (228) (193) (214) (207) Net natural gas – thousands of cubic feet per day (1,963) (1,947) (1,715) (2,008) Total noncontrolling interest 2,3 (6,828) (6,438) (6,454) (7,045) Total net hydrocarbons - excluding NCI 2,3 201,656 185,861 183,927 179,092 1 Includes net volumes attributable to a noncontrolling interest in MP GOM. 2 Natural gas converted on an energy equivalent basis of 6:1. 3 NCI – noncontrolling interest in MP GOM. 35 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted. Revenues from Production The Company’s production revenues by country and product were as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2025 2024 2025 2024 Revenues from production United States - Oil $ 566.0 $ 561.9 $ 1,537.0 $ 1,832.6 United States - Natural gas liquids 22.1 17.9 58.0 52.8 United States - Natural gas 25.3 16.6 78.0 47.6 Canada - Oil 53.3 101.1 200.9 232.6 Canada - Natural gas liquids 1.1 2.4 4.4 5.4 Canada - Natural gas 53.1 54.1 195.5 170.9 Other - Oil 0.1 (0.8) 3.0 3.4 Total revenue from production $ 721.0 $ 753.2 $ 2,076.8 $ 2,345.3 Revenues from production for the three months ended September 30, 2025, decreased by $32.2 million compared to the same period in 2024. Revenues decreased primarily due to lower crude oil prices, reduced oil production in the Gulf of America from downtime relating to planned maintenance and ongoing workovers, and downtime in offshore Canada at Terra Nova and Hibernia related to well issues in the quarter. These reductions were partially offset by higher production at Karnes and Catarina in the Eagle Ford Shale related to better well performance and new wells online, and higher sales volumes at Cascade & Chinook in the Gulf of America. Revenues from production for the nine months ended September 30, 2025, decreased $268.5 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline of new wells, and downtime for maintenance at Khaleesi. These decreases were partially offset by increased production in Eagle Ford Shale due to new wells at Karnes and Catarina, as well as in the Gulf of America at Mormont and Neidermeyer. 36 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Lease Operating and Transportation, Gathering and Processing Expenses The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars) (Dollars per equivalent barrel) 2025 2024 2025 2024 2025 2024 2025 2024 Lease operating expenses United States - Onshore $ 31.9 $ 32.9 $ 7.04 $ 11.03 $ 91.2 $ 105.4 $ 8.75 $ 13.00 United States - Offshore 109.4 136.0 16.79 20.54 374.2 462.3 19.64 21.52 Canada - Onshore 30.0 35.2 3.94 4.96 95.8 101.4 4.73 5.28 Canada - Offshore 12.7 18.5 24.96 18.51 42.2 46.7 19.05 21.67 Other 0.4 0.3 — — 1.6 1.0 37.54 23.66 Total lease operating expenses $ 184.4 $ 222.9 $ 9.61 $ 12.60 $ 605.0 $ 716.8 $ 11.64 $ 14.05 Transportation, gathering and processing United States - Onshore $ 3.2 $ 2.2 $ 0.72 $ 0.73 $ 7.8 $ 7.3 $ 0.75 $ 0.89 United States - Offshore 20.1 24.1 3.08 3.64 74.6 89.8 3.91 4.18 Canada - Onshore 23.0 20.1 3.02 2.84 63.3 56.9 3.13 2.96 Canada - Offshore 1.8 1.1 3.49 1.06 5.4 3.5 2.42 1.63 Total transportation, gathering and processing $ 48.1 $ 47.5 $ 2.51 $ 2.68 $ 151.1 $ 157.5 $ 2.91 $ 3.09 For the three months ended September 30, 2025, lease operating expenses decreased by $38.5 million and transportation, gathering and processing expenses increased by $0.6 million compared to the same period in 2024. In the Gulf of America, decreases in lease operating expenses primarily related to lower production volumes and handling fees and lower operating charges as a result of the acquisition of the BW Pioneer FPSO. In addition, current quarter workover costs at Marmalard, Khaleesi and Samurai were lower than expenditures at Neidermeyer and Dalmatian in the prior year. In the Eagle Ford Shale, lower operating expenses were due to cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization throughout the year, and were largely offset by higher production. For the nine months ended September 30, 2025, lease operating expenses decreased by $111.8 million, and transportation, gathering and processing expenses decreased by $6.4 million compared to the same period in 2024. In the Gulf of America, decreases primarily related to lower workover costs due to expenditures at Neidermeyer and Dalmatian in the prior year, which were partially offset by current year workovers at Marmalard, Khaleesi and Samurai. Lower operating charges also occured as a result of the acquisition of the BW Pioneer FPSO earlier in the year. In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, were partially offset by higher volume related costs. 37 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Depreciation, Depletion and Amortization Expenses The Company’s DD&A by geographic area were as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars) (Dollars per equivalent barrel) 2025 2024 2025 2024 2025 2024 2025 2024 DD&A United States - Onshore $ 137.5 $ 88.0 $ 30.30 $ 29.60 $ 311.9 $ 237.2 $ 29.95 $ 29.25 United States - Offshore 104.6 91.3 16.06 13.78 307.8 291.1 16.16 13.55 Canada - Onshore 33.5 34.5 4.38 4.87 87.6 93.5 4.32 4.87 Canada - Offshore 5.8 8.3 11.53 8.27 22.2 20.6 10.03 9.58 Other — — — — 1.2 0.9 31.66 20.82 Total DD&A $ 281.4 $ 222.1 $ 14.67 $ 12.56 $ 730.7 $ 643.3 $ 14.06 $ 12.61 DD&A for the three months ended September 30, 2025 increased by $59.3 million compared to the same period in 2024. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America. DD&A for the nine months ended September 30, 2025 increased by $87.4 million. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America. Impairment of Assets For the three and nine months ended September 30, 2025, the Company impaired assets for $115.0 million related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions in the quarter, as certain projects in the field were less competitive for capital allocation. There were no impairments for the three months ended September 30, 2024. Impairment of assets for the nine months ended September 30, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction. Exploration Expenses The Company’s exploration expenses were as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2025 2024 2025 2024 Exploration expenses Dry holes and previously suspended exploration costs $ 0.8 $ 11.2 $ 0.1 $ 69.5 Geological and geophysical 20.3 12.7 24.7 22.3 Other exploration 8.5 5.4 25.8 18.9 Undeveloped lease amortization 2.9 1.9 6.8 7.7 Total exploration expenses, including undeveloped lease amortization $ 32.5 $ 31.2 $ 57.4 $ 118.4 Exploration expenses for the three months ended September 30, 2025 increased by $1.3 million compared to the same period in 2024 due to higher geological and geophysical costs in the Gulf of America, and were partially offset by lower dry hole costs in the current period. Dry hole costs in 2024 related to the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons. 38 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Results of Operations (Continued) Exploration expenses for the nine months ended September 30, 2025 decreased by $61.0 million compared to the same period in 2024. Lower exploration costs were primarily due to no dry holes recorded in 2025 (2024: Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America). This was partially offset by higher exploration activity in Côte d'Ivoire. Other Other expenses from E&P continuing operations for the three months ended September 30, 2025 decreased by $0.1 million compared to the same period in 2024. Other expenses for the nine months ended September 30, 2025 increased by $17.7 million compared to the same period in 2024 due to no interest income received in the current year. Income Taxes Income taxes for the three and nine months ended September 30, 2025 decreased by $3.0 million and $24.0 million, respectively, compared to the same periods in 2024. Lower income tax for each period is primarily the result of lower net income. Corporate Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge commodity price) and corporate overhead not allocated to E&P. Realized and unrealized gains and losses on derivative instruments result from changes in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price. For the three months ended September 30, 2025, the Corporate segment reported a loss of $18.6 million, a favorable variance of $15.1 million, compared to the same period in 2024. The favorable variance was primarily due to a foreign exchange gain ($18.4 million) for the period, primarily relating to our Canadian subsidiary, combined with gains on derivative instruments ($3.9 million), and partially offset by higher income tax expense of $5.1 million. The Corporate segment reported a loss of $122.7 million for the nine months ended September 30, 2025, an unfavorable variance of $33.8 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher foreign exchange losses ($31.5 million) and higher interest expense ($11.4 million) due to the timing of interest payments on long-term debt, and was partially offset by gains on derivative instruments ($8.4 million) due to fixed price sales contracts. Financial Condition The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured RCF. The Company’s liquidity requirements, both in the short-term and long-term, consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next twelve months and the foreseeable future. 39 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Financial Condition (Continued) Cash Flows The following table presents the Company’s cash flows for the periods presented: Nine Months Ended September 30, (Millions of dollars) 2025 2024 Net cash provided (required) by: Net cash provided by continuing operations activities $ 998.2 $ 1,295.4 Net cash required by investing activities (851.4) (733.3) Net cash required by financing activities (143.9) (608.8) Effect of exchange rate changes on cash and cash equivalents (0.5) 0.8 Net increase (decrease) in cash and cash equivalents $ 2.4 $ (45.9) Cash Provided by Continuing Operations Activities Net cash provided by continuing operations activities for the nine months ended September 30, 2025 was $297.3 million lower compared to the same period in 2024. The decrease in cash flows from operations activities was primarily due to lower revenue from production ($268.5 million), timing of non-cash working capital ($52.3 million) settlements, and an increase in selling and general expenses ($19.8 million), partially offset by lower lease operating expenses ($111.8 million). Cash Required by Investing Activities Net cash required by investing activities for the nine months ended September 30, 2025 was $118.1 million higher compared to the same period in 2024. The increase was primarily due to a gross payment of $125.0 million for the purchase of an FPSO in the Gulf of America and higher development drilling at Eagle Ford Shale, partially offset by lower development drilling at Gulf of America. A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows. Nine Months Ended September 30, (Millions of dollars) 2025 2024 Property additions and dry hole costs per the cash flow statements $ 827.0 $ 733.3 Acquisition of oil properties per the cash flow statements 24.4 — Geophysical and other exploration expenses 46.8 35.5 Capital expenditure accrual changes and other (30.6) 7.8 Total capital expenditures $ 867.6 $ 776.6 Total accrual basis capital expenditures are shown below. Nine Months Ended September 30, (Millions of dollars) 2025 2024 Capital Expenditures Exploration and production $ 858.4 $ 760.2 Corporate 9.2 16.4 Total capital expenditures $ 867.6 $ 776.6 Higher capital expenditures in the nine months ended September 30, 2025 compared to the same period of 2024 were primarily attributable to the FPSO purchase in the Gulf of America and higher development drilling in the Eagle Ford Shale related to new wells online. Also contributing to the increase were higher exploratory drilling and field development in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower exploration costs and development drilling 40 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Financial Condition (Continued) costs in the Gulf of America due to prior year spend on the non-operated Ocotillo #1 (Mississippi Canyon 40) and Orange #1 (Mississippi Canyon 216) exploration wells, and Khaleesi development costs, respectively. Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($257.6 million), Eagle Ford Shale ($296.4 million), Tupper Montney and Kaybob Duvernay ($113.0 million), and in Vietnam ($57.7 million). Exploration costs in 2025 were $90.9 million, primarily comprised of activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05; and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d'Ivoire related to long lead equipment purchases for the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells. Cash Required by Financing Activities Net cash required by financing activities for the nine months ended September 30, 2025 decreased by $464.9 million compared to the same period in 2024. In 2025, the cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.975 per share ($139.8 million), and distributions to the noncontrolling interest in MP GOM ($43.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($150.0 million). In 2024, cash required by financing activities was for the repurchase of common shares ($300.1 million), cash dividends to shareholders ($136.2 million), distributions to the noncontrolling interest in MP GOM ($96.6 million), debt repurchases ($50.0 million), and withholding tax on stock-based incentive awards ($25.3 million). Liquidity At September 30, 2025, the Company had approximately $1.6 billion of liquidity consisting of $426.0 million in cash and cash equivalents and $1,199.6 million available on its committed senior unsecured RCF with a major banking consortium. The Company’s $1.35 billion senior unsecured RCF expires in October 2029. As of September 30, 2025, the Company had $150.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48%. At September 30, 2025, the Company was in compliance with all covenants related to the RCF. Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $67.4 million, the majority of which was held in Canada ($28.9 million), Mexico ($8.0 million), the U.K. ($7.4 million) and Vietnam ($6.7 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S. Working Capital (Millions of dollars) September 30, 2025 December 31, 2024 Working capital Total current assets $ 807.5 $ 785.3 Total current liabilities 857.7 942.8 Net working capital liability $ (50.2) $ (157.5) As of September 30, 2025, net working capital increased by $107.3 million compared to December 31, 2024. The increase was primarily attributable to lower current operating lease obligations ($42.4 million), lower accounts payable ($42.5 million), and higher accounts receivable ($11.2 million). Lower lease obligations were due to lower day rates related to an offshore drilling rig, ongoing lease amortization and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America. 41 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Financial Condition (Continued) Higher accounts receivable were due to higher tax receivables related to increased Vietnam development and exploration expenditures. Lower cash and equivalents were due to lower net income, the BW Pioneer FPSO purchase, and returns to shareholders in the form of share repurchases and dividends. Lower accounts payable related to higher production in the Eagle Ford Shale. Capital Employed A summary of capital employed at September 30, 2025 and December 31, 2024 follows. September 30, 2025 December 31, 2024 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 1,425.2 21.8 % $ 1,274.5 19.7 % Murphy shareholders' equity 5,121.4 78.2 % 5,194.3 80.3 % Total capital employed $ 6,546.6 100.0 % $ 6,468.8 100.0 % At September 30, 2025, long-term debt of $1,425.2 million increased by $150.7 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF. The total of the fixed-rate notes had a weighted average maturity of 8.6 years and a weighted average coupon of 6.1%. Murphy shareholders’ equity decreased by $72.9 million in 2025, primarily due to dividends ($139.8 million) and shares repurchased ($100.9 million), including excise tax, partially offset by net income ($92.3 million), foreign currency translation ($50.5 million), and awarded restricted stock ($20.3 million). A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity ” on page 6 of this Form 10-Q report. Critical Accounting Estimates As of September 30, 2025, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2024. Accounting Changes and Recent Accounting Pronouncements See Note B to the Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations. 42 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Other Key Performance Metrics The Company uses other operational performance and income metrics to review operational performance. Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP. The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy. Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars, except per share amounts) 2025 2024 2025 2024 Net income (loss) attributable to Murphy (GAAP) 1 $ (3.0) $ 139.1 $ 92.3 $ 356.8 Discontinued operations (income) loss 0.5 0.6 (0.2) 2.1 Net income (loss) from continuing operations attributable to Murphy (2.5) 139.7 92.1 358.9 Adjustments: Impairment of assets 1 92.0 — 92.0 34.5 Foreign exchange (gain) loss (13.4) 5.4 20.9 (10.6) Unrealized (gain) loss on derivative instruments (2.5) 1.3 (3.9) 1.3 Write-off of previously suspended exploration well — — — 26.1 Total adjustments, before taxes 76.1 6.7 109.0 51.3 Income tax benefit related to adjustments (15.5) (1.7) (23.8) (10.5) Tax benefits on investments in foreign areas — (34.0) — (34.0) Total adjustments, after taxes 60.6 (29.0) 85.2 6.8 Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 58.1 $ 110.7 $ 177.3 $ 365.7 Net income (loss) from continuing operations per average diluted share (GAAP) $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.35 Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 0.41 $ 0.74 $ 1.23 $ 2.40 1 Excludes amounts attributable to a noncontrolling interest in MP GOM. 43 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Other Key Performance Metrics (Continued) The following table reconciles net income (loss) attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy. Three Months Ended September 30, Nine Months Ended September 30, (Millions of dollars) 2025 2024 2025 2024 Net income (loss) attributable to Murphy (GAAP) 1 $ (3.0) $ 139.1 $ 92.3 $ 356.8 Income tax expense 4.1 2.2 37.9 64.9 Interest expense, net 24.7 21.3 73.3 62.3 Depreciation, depletion and amortization expense 1 275.0 215.7 713.2 625.8 EBITDA attributable to Murphy (Non-GAAP) $ 300.8 $ 378.3 $ 916.7 $ 1,109.8 Exploration expenses 32.5 31.3 57.3 118.4 EBITDAX attributable to Murphy (Non-GAAP) $ 333.3 $ 409.6 $ 974.0 $ 1,228.2 EBITDA attributable to Murphy (Non-GAAP) $ 300.8 $ 378.3 $ 916.7 $ 1,109.8 Impairment of assets 1 92.0 — 92.0 34.5 Foreign exchange (gain) loss (13.4) 5.4 20.9 (10.6) Accretion of asset retirement obligations 1 13.2 11.7 38.6 34.9 Unrealized (gain) loss on derivative instruments (2.5) 1.3 (3.9) 1.3 Write-off of previously suspended exploration well — — — 26.1 Discontinued operations (income) loss 0.5 0.6 (0.2) 2.1 Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 390.6 $ 397.3 $ 1,064.1 $ 1,198.1 Other exploration expenses 2 32.5 31.3 57.3 92.3 Adjusted EBITDAX attributable to Murphy (Non-GAAP) $ 423.1 $ 428.6 $ 1,121.4 $ 1,290.4 1 Excludes amounts attributable to a noncontrolling interest in MP GOM. 2 Other exploration expenses consist of exploration expenses as reported in the consolidated statement of operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above. 44 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) Other Key Performance Metrics (Continued) Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and Adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP. The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF. Nine Months Ended September 30, (Millions of dollars) 2025 2024 Net cash provided by continuing operations activities (GAAP) $ 998.2 $ 1,295.4 Exclude: (decrease) increase in non-cash working capital 20.5 (31.8) Operating cash flow excluding working capital adjustments 1,018.7 1,263.6 Less: property additions and dry hole costs 1 (827.0) (733.3) Free cash flow (Non-GAAP) $ 191.7 $ 530.3 Less: cash dividends paid (139.8) (136.2) Less: distributions to noncontrolling interest (43.2) (96.6) Less: withholding tax on stock-based incentive awards (7.7) (25.3) Less: acquisition of oil and natural gas properties (24.4) — Adjusted free cash flow (Non-GAAP) $ (23.4) $ 272.2 1 Property additions for the 2025 period include a payment of $125.0 million for the purchase of a floating production, storage, and offloading vessel in the U.S Offshore, including amounts attributable to a noncontrolling interest in MP GOM. 45 Table of Contents