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) June 30, 2026 December 31, 2025 ASSETS Current assets Cash and cash equivalents $ 483,875 $ 377,196 Accounts receivable, net 443,120 346,759 Inventories 62,011 57,284 Prepaid expenses 37,836 35,473 Total current assets 1,026,842 816,712 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ 15,470,662 in 2026 and $ 15,068,149 in 2025 8,434,791 8,136,346 Operating lease assets 702,528 805,464 Deferred charges and other assets 113,973 74,104 Total assets $ 10,278,134 $ 9,832,626 LIABILITIES AND EQUITY Current liabilities Current maturities of long-term debt, finance lease $ 2,578 $ 2,514 Accounts payable 671,238 572,183 Income taxes payable 32,330 18,209 Other taxes payable 36,388 28,295 Operating lease liabilities 280,162 278,834 Other accrued liabilities 120,438 120,755 Current asset retirement obligations 59,231 41,959 Total current liabilities 1,202,365 1,062,749 Long-term debt, including finance lease obligation 1,547,864 1,382,566 Asset retirement obligations 981,355 970,908 Deferred credits and other liabilities 245,770 263,596 Non-current operating lease liabilities 433,128 537,773 Deferred income taxes 464,462 378,337 Total liabilities $ 4,874,944 $ 4,595,929 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 June 30, 2026 and 195,100,628 shares at December 31, 2025 195,101 195,101 Capital in excess of par value 844,653 859,633 Retained earnings 6,876,135 6,691,318 Accumulated other comprehensive loss ( 606,066 ) ( 554,227 ) Treasury stock ( 2,050,809 ) ( 2,073,445 ) Murphy Shareholders' Equity 5,259,014 5,118,380 Noncontrolling interest 144,176 118,317 Total equity 5,403,190 5,236,697 Total liabilities and equity $ 10,278,134 $ 9,832,626 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 June 30, Six Months Ended June 30, (Thousands of dollars, except per share amounts) 2026 2025 2026 2025 Revenues and other income Revenue from production $ 926,332 $ 683,065 $ 1,658,686 $ 1,355,795 Total revenue from sales to customers 926,332 683,065 1,658,686 1,355,795 Gain on derivative instruments — 10,808 — 1,349 Gain on sale of assets and other operating income 1,975 1,697 3,173 4,137 Total revenues and other income 928,307 695,570 1,661,859 1,361,281 Costs and expenses Lease operating expenses 143,719 215,554 287,183 420,633 Severance and ad valorem taxes 14,991 10,828 28,737 19,478 Transportation, gathering and processing 45,274 54,070 92,335 102,921 Exploration expenses, including undeveloped lease amortization 39,303 10,399 122,118 24,887 Selling and general expenses 38,670 36,919 73,540 67,834 Depreciation, depletion and amortization 262,106 259,324 516,482 453,484 Accretion of asset retirement obligations 14,870 14,432 29,384 28,477 Other operating expense 14,706 1,833 19,147 7,462 Total costs and expenses 573,639 603,359 1,168,926 1,125,176 Operating income from continuing operations 354,668 92,211 492,933 236,105 Other income (loss) Other income (loss) 11,247 ( 32,304 ) 21,099 ( 29,902 ) Interest expense, net ( 24,917 ) ( 25,053 ) ( 53,894 ) ( 48,576 ) Total other loss ( 13,670 ) ( 57,357 ) ( 32,795 ) ( 78,478 ) Income from continuing operations before income taxes 340,998 34,854 460,138 157,627 Income tax expense 77,030 1,032 126,975 33,754 Income from continuing operations 263,968 33,822 333,163 123,873 Income (loss) from discontinued operations, net of income taxes ( 437 ) 1,302 ( 979 ) 669 Net income including noncontrolling interest 263,531 35,124 332,184 124,542 Less: Net income attributable to noncontrolling interest 31,356 12,844 47,023 29,226 NET INCOME ATTRIBUTABLE TO MURPHY $ 232,175 $ 22,280 $ 285,161 $ 95,316 NET INCOME (LOSS) PER COMMON SHARE – BASIC Continuing operations $ 1.62 $ 0.15 $ 2.00 $ 0.66 Discontinued operations — 0.01 ( 0.01 ) — Net income $ 1.62 $ 0.16 $ 1.99 $ 0.66 NET INCOME (LOSS) PER COMMON SHARE – DILUTED Continuing operations $ 1.59 $ 0.15 $ 1.96 $ 0.66 Discontinued operations — 0.01 ( 0.01 ) — Net income $ 1.59 $ 0.16 $ 1.95 $ 0.66 Cash dividends per common share $ 0.350 $ 0.325 $ 0.700 $ 0.650 Average common shares outstanding (thousands) Basic 143,351 142,721 143,216 143,502 Diluted 146,149 143,216 145,894 144,144 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 June 30, Six Months Ended June 30, (Thousands of dollars) 2026 2025 2026 2025 Net income including noncontrolling interest $ 263,531 $ 35,124 $ 332,184 $ 124,542 Other comprehensive income (loss), net of tax Net gain (loss) from foreign currency translation ( 30,895 ) 90,222 ( 54,641 ) 88,555 Retirement and postretirement benefit plans 1,401 875 2,802 1,739 Other comprehensive income (loss) ( 29,494 ) 91,097 ( 51,839 ) 90,294 Comprehensive income including noncontrolling interest 234,037 126,221 280,345 214,836 Less: Comprehensive income attributable to noncontrolling interest 31,356 12,844 47,023 29,226 COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ 202,681 $ 113,377 $ 233,322 $ 185,610 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) Six Months Ended June 30, (Thousands of dollars) 2026 2025 Operating Activities Net income including noncontrolling interest $ 332,184 $ 124,542 Adjustments to reconcile net income to net cash provided by continuing operations activities Depreciation, depletion and amortization 516,482 453,484 Unsuccessful exploration well costs and previously suspended exploration costs 80,585 ( 776 ) Deferred income tax expense 92,549 21,216 Accretion of asset retirement obligations 29,384 28,477 Long-term non-cash compensation 25,693 22,016 Amortization of undeveloped leases 4,835 3,909 (Income) loss from discontinued operations 979 ( 669 ) Unrealized gain on derivative instruments — ( 1,371 ) Other operating activities, net ( 65,121 ) ( 2 ) Net (increase) decrease in non-cash working capital ( 40,477 ) 7,905 Net cash provided by continuing operations activities 977,093 658,731 Investing Activities Property additions and dry hole costs ( 866,159 ) ( 678,043 ) Acquisition of oil and natural gas properties ( 23,513 ) ( 1,383 ) Net cash required by investing activities ( 889,672 ) ( 679,426 ) Financing Activities Retirement of debt ( 227,489 ) — Early redemption of debt cost ( 2,369 ) — Debt issuance 500,000 — Debt issuance cost ( 7,819 ) — Borrowings on revolving credit facility 425,000 350,000 Repayment of revolving credit facility ( 525,000 ) ( 150,000 ) Issue costs of revolving credit facility ( 12,274 ) ( 18 ) Repurchase of common stock, including excise tax ( 777 ) ( 102,620 ) Cash dividends paid ( 100,344 ) ( 93,412 ) Distributions to noncontrolling interest ( 21,164 ) ( 18,165 ) Withholding tax on stock-based incentive awards ( 7,849 ) ( 7,654 ) Finance lease obligation payments ( 870 ) ( 486 ) Net cash provided (required) by financing activities 19,045 ( 22,355 ) Effect of exchange rate changes on cash and cash equivalents 213 ( 888 ) Net increase (decrease) in cash and cash equivalents 106,679 ( 43,938 ) Cash and cash equivalents at beginning of period 377,196 423,569 Cash and cash equivalents at end of period $ 483,875 $ 379,631 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 June 30, Six Months Ended June 30, (Thousands of dollars except number of shares) 2026 2025 2026 2025 Common Stock Balance at beginning and end of period – par $ 1.00 , authorized 450,000,000 shares at June 30, 2026 and June 30, 2025, issued 195,100,628 shares at June 30, 2026 and June 30, 2025 $ 195,101 $ 195,101 $ 195,101 $ 195,101 Capital in Excess of Par Value Balance at beginning of period 837,327 830,945 859,633 848,950 Restricted stock transactions and other ( 282 ) ( 398 ) ( 30,467 ) ( 27,736 ) Share-based compensation 7,608 11,286 15,487 20,619 Balance at end of period 844,653 841,833 844,653 841,833 Retained Earnings Balance at beginning of period 6,694,131 6,799,299 6,691,318 6,773,289 Net income attributable to Murphy 232,175 22,280 285,161 95,316 Cash dividends paid ( 50,171 ) ( 46,386 ) ( 100,344 ) ( 93,412 ) Balance at end of period 6,876,135 6,775,193 6,876,135 6,775,193 Accumulated Other Comprehensive Loss Balance at beginning of period ( 576,572 ) ( 628,875 ) ( 554,227 ) ( 628,072 ) Foreign currency translation, net of income taxes ( 30,895 ) 90,222 ( 54,641 ) 88,555 Retirement and postretirement benefit plans, net of income taxes 1,401 875 2,802 1,739 Balance at end of period ( 606,066 ) ( 537,778 ) ( 606,066 ) ( 537,778 ) Treasury Stock Balance at beginning of period ( 2,051,091 ) ( 2,076,211 ) ( 2,073,445 ) ( 1,995,018 ) Repurchase of common stock — – — ( 100,876 ) Awarded restricted stock, net of forfeitures 282 388 22,636 20,071 Balance at end of period – 51,744,796 shares of common stock at June 30, 2026 and 52,374,883 shares of common stock at June 30, 2025, at cost ( 2,050,809 ) ( 2,075,823 ) ( 2,050,809 ) ( 2,075,823 ) Murphy Shareholders’ Equity 5,259,014 5,198,526 5,259,014 5,198,526 Noncontrolling Interest Balance at beginning of period 133,984 157,020 118,317 147,593 Net income attributable to noncontrolling interest 31,356 12,844 47,023 29,226 Distributions to noncontrolling interest owners ( 21,164 ) ( 11,210 ) ( 21,164 ) ( 18,165 ) Balance at end of period 144,176 158,654 144,176 158,654 Total Equity $ 5,403,190 $ 5,357,180 $ 5,403,190 $ 5,357,180 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 June 30, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2026 and 2025, 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 2025 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three and six months ended June 30, 2026 are not necessarily indicative of future results. Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Income Tax Disclosures . In December 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. The Company adopted this standard in the fourth quarter of 2025. Interim period disclosures are largely unaffected by this update. The adoption did not affect the calculation of income tax expense. Recent Accounting Pronouncements Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impact on our results of operations, cash flows and financial condition. The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption. Note C – Revenue from Contracts with Customers Nature of Goods and Services The Company explores for and produces oil and natural gas in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the 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 7 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note C – Revenue from Contracts with Customers (Continued) 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. The Company’s revenues and other income for the three and six months ended June 30, 2026 and 2025 were as follows. Three Months Ended June 30, Six Months Ended June 30, (Thousands of dollars) 2026 2025 2026 2025 Net crude oil and condensate revenue United States - Onshore $ 243,270 $ 166,101 $ 431,619 $ 275,559 United States - Offshore 1 455,332 343,080 788,773 695,442 Canada - Onshore 37,142 12,583 54,533 27,313 Canada - Offshore 96,431 45,741 149,766 120,210 Other — 2,948 2,909 2,948 Total crude oil and condensate revenue 832,175 570,453 1,427,600 1,121,472 Net natural gas liquids revenue United States - Onshore 14,219 9,893 23,495 18,380 United States - Offshore 1 7,836 8,311 14,199 17,560 Canada - Onshore 1,787 1,523 3,104 3,270 Total natural gas liquids revenue 23,842 19,727 40,798 39,210 Net natural gas revenue United States - Onshore 7,214 8,099 18,341 16,066 United States - Offshore 1 15,115 16,726 41,264 36,667 Canada - Onshore 47,986 68,060 130,683 142,380 Total natural gas revenue 70,315 92,885 190,288 195,113 Total revenue from sales to customers 926,332 683,065 1,658,686 1,355,795 Gain on derivative instruments — 10,808 — 1,349 Gain on sale of assets and other operating income 1,975 1,697 3,173 4,137 Total revenues and other income $ 928,307 $ 695,570 $ 1,661,859 $ 1,361,281 1 Includes revenue attributable to the noncontrolling interest in MP GOM. Contract Balances and Asset Recognition As of June 30, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 213.3 million and $ 165.3 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 8 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note C – Revenue from Contracts with Customers (Continued) 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 June 30, 2026. 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. 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 June 30, 2026, 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 Q1 2031 Deliveries from dedicated acreage in Eagle Ford Shale As produced Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCF/D Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCF/D Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 20 MMCF/D Canada Natural Gas Q4 2029 Contracts to sell natural gas at USD index pricing 25 MMCF/D Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCF/D Canada Natural Gas Q4 2027 Contracts to sell natural gas at CAD fixed pricing 9 MMCF/D Canada NGLs Q4 2026 Contracts to sell NGLs at CAD index pricing As produced The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes. Note D – Property, Plant and Equipment 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 June 30, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 371.6 million. The following table reflects the net changes in capitalized exploratory well costs during the six months ended June 30, 2026 and 2025. 9 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note D – Property, Plant and Equipment (Continued) (Thousands of dollars) 2026 2025 Beginning balance at January 1 $ 191,821 $ 72,055 Additions pending the determination of proved reserves 190,427 38,469 Capitalized exploratory well costs charged to expense ( 10,627 ) — Balance at June 30 $ 371,621 $ 110,524 Capital additions of $ 190.4 million, for the six months ended June 30, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire; the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America; and the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in Vietnam. In the second quarter of 2026, Murphy announced a discovery at the Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire, with the well encountering 100 feet of net pay across two reservoirs. In addition, Murphy concluded the Hai Su Vang (Golden Sea Lion) appraisal program for Hai Su Vang-2X (Block 15-2/17), Hai Su Vang-3X (Block 15-1/05) and Hai Su Vang-4X (Block 15-2/17) appraisal wells in Vietnam. Subsequent to the second quarter of 2026, Murphy spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d’Ivoire and Lac Da Trang North-1X (White Camel) exploration well in Block 15-1/05 offshore Vietnam. In the first quarter of 2026, Murphy announced the successful discoveries of the Banjo #1 and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, which encountered 50 feet and 30 feet of net pay, respectively. In addition, the Company announced a successful appraisal well Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, in the Cuu Long Basin, located approximately 40 miles offshore of Vietnam. Capital additions of $ 38.5 million, for the six months ended June 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 and long-lead equipment for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America. Capitalized well costs charged to dry hole expense of $ 10.6 million, for the six months ended June 30, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. There were no capitalized well costs charged to dry hole expense for the six months ended June 30, 2025. The preceding table excludes well costs of $ 70.0 million incurred and expensed directly to dry hole for the six months ended June 30, 2026. In 2026, these costs primarily related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, which encountered non-commercial hydrocarbons, the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion), Block 15-2/17 appraisal well in Vietnam. The following table provides an aging of capitalized exploration costs based on the date the drilling operations were initiated for each individual project. June 30, 2026 2025 (Thousands of dollars) Amount No. of Projects Amount No. of Projects Aging of capitalized well costs: Zero to one year $ — — $ 16,002 5 One to two years 228,318 3 72,004 3 Two to three years 120,979 3 — — Three years or more 22,324 3 22,518 3 $ 371,621 9 $ 110,524 11 10 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note D – Property, Plant and Equipment (Continued) Of the $ 371.6 million of exploration well costs capitalized and classified as more than one year at June 30, 2026, $ 150.3 million was in Côte d’Ivoire, $ 114.0 million was in Vietnam, $ 100.1 million was in the Gulf of America, $ 4.5 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 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. The Pioneer FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a five-year contract that began in 2025. Impairments There were no impairments in the three and six months ended June 30, 2026 and 2025. Note E – Financing Arrangements and Debt Revolving Credit Facility In the first quarter of 2026, the Company entered into an amended credit agreement governing a $ 2.0 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. All terms of the Amended RCF are substantially similar to the previous senior unsecured guaranteed revolving credit facility (RCF) credit agreement, with an exception for the following: The “Adjusted Term Secured Overnight Financing Rate (SOFR)” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero . The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero . The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $ 12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF. At June 30, 2026, the Company had no outstanding borrowings under the Amended RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At June 30, 2026, the interest rate in effect on borrowings under the Amended RCF was 5.90 %. At June 30, 2026, the Company was in compliance with all covenants related to the Amended RCF. 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. Debt Offering In the first quarter of 2026, the Company closed a public offering of $ 500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.50 % per annum and mature on February 15, 2034. The Company has incurred transaction costs of $ 8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $ 500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes. Debt Extinguishment In the first quarter of 2026, the Company redeemed the remaining $ 78.9 million principal amount outstanding of its 5.875 % senior notes due 2027 (2027 Notes) and the remaining $ 148.6 million principal amount outstanding of its 6.375 % senior notes due 2028 (2028 Notes), for an aggregate $ 227.5 million. The total cost of the debt extinguishment of $ 3.5 million consisted of cash costs of $ 2.5 million and non-cash costs of $ 1.0 million. 11 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note F – Other Financial Information Supplemental Information to Statement of Cash Flows Six Months Ended June 30, (Thousands of dollars) 2026 2025 Net (increase) decrease in operating working capital, excluding cash and cash equivalents: (Increase) decrease in accounts receivable $ ( 96,506 ) $ ( 976 ) (Increase) decrease in inventories ( 6,464 ) ( 9,040 ) (Increase) decrease in prepaid expenses ( 3,897 ) ( 11,009 ) Increase (decrease) in accounts payable and accrued liabilities 52,269 24,141 Increase (decrease) in income taxes payable 14,121 4,789 Net (increase) decrease in non-cash working capital $ ( 40,477 ) $ 7,905 Supplementary disclosures: Interest paid, net of amounts capitalized of $ 8.8 million in 2026 and $ 2.9 million in 2025 $ 35,442 $ 44,577 Non-cash investing activities: Asset retirement costs capitalized $ 8,918 $ 9,427 (Increase) decrease in capital expenditure accrual ( 52,007 ) 22,748 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 six months ended June 30, 2026 and 2025 are shown in the following table. (Thousands of dollars) June 30, 2026 June 30, 2025 Balance at beginning of year $ 1,012,867 $ 1,008,884 Accretion 29,384 28,477 Liabilities incurred 12,256 5,428 Revisions of previous estimates — 3,999 Liabilities settled ( 8,265 ) ( 6,359 ) Changes due to translation of foreign currencies ( 5,656 ) 9,784 Balance at end of period 1,040,586 1,050,213 Current portion of liability ( 59,231 ) ( 70,104 ) Non-current portion of liability $ 981,355 $ 980,109 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 12 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note H – Employee and Retiree Benefit Plans (Continued) 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. The table that follows provides the components of net periodic benefit expense for the three and six months ended June 30, 2026 and 2025. Three Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2026 2025 2026 2025 Service cost $ 1,865 $ 1,683 $ 102 $ 84 Interest cost 7,752 8,482 750 708 Expected return on plan assets ( 8,792 ) ( 8,953 ) — — Estimated defined contribution provision 70 62 — — Amortization of prior service cost (credit) 432 492 ( 133 ) ( 133 ) Recognized actuarial (gain) loss 1,644 1,914 ( 387 ) ( 1,057 ) Total net periodic benefit cost (credit) $ 2,971 $ 3,680 $ 332 $ ( 398 ) Six Months Ended June 30, Pension Benefits Other Postretirement Benefits (Thousands of dollars) 2026 2025 2026 2025 Service cost $ 3,730 $ 3,366 $ 204 $ 168 Interest cost 15,504 16,880 1,500 1,416 Expected return on plan assets ( 17,584 ) ( 17,824 ) — — Estimated defined contribution provision 140 122 — — Amortization of prior service cost (credit) 864 983 ( 266 ) ( 266 ) Recognized actuarial (gain) loss 3,288 3,805 ( 774 ) ( 2,113 ) Total net periodic benefit cost (credit) $ 5,942 $ 7,332 $ 664 $ ( 795 ) 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 six months ended June 30, 2026, the Company made contributions of $ 15.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2026 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 15.1 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. The 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) authorizes the Committee to grant shares of the Company’s common stock and stock-based awards to employees. These awards may be in the form of stock 13 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. The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term. Shares issued pursuant to awards granted under the 2025 Long-Term Plan may be shares that are authorized but unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Shares underlying awards that have been canceled, expired, are forfeited, or otherwise not issued under an award shall not count as shares issued under the Plan. During the six months ended June 30, 2026, the Committee granted the following awards from the 2025 Long-Term Plan: Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Performance-based RSUs 1 412,560 February 3, 2026 $ 32.67 Monte Carlo Time-based RSUs (Stock-Settled) 2 811,620 February 3, 2026 $ 30.05 Average Stock Price Time-based RSUs (Cash-Settled) 2 661,960 February 3, 2026 $ 30.05 Average Stock Price 1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) performance goals, measured over a three-year performance period based on (i) the Company’s TSR relative to a peer group and (ii) the Company’s absolute TSR performance, and are scheduled to vest at the end of the period subject to achievement of these conditions. 2 Time-based RSUs generally vest on the third anniversary of the date of grant. In May 2026, the Company’s shareholders approved the 2026 Stock Plan for Non-Employee Directors (the 2026 NED Plan) to replace the 2021 Stock Plan for Non-Employee Directors (the 2021 NED Plan). All awards granted on or after May 13, 2026, will be made under the 2026 NED Plan. The 2026 NED Plan will expire in 2036 and authorizes the issuance of up to 900,000 shares of common stock over its term. Additional information on the 2026 NED Plan can be found in Exhibit A to the definitive proxy statement filed on March 27, 2026. Similar to the 2021 NED Plan, the 2026 NED Plan permits the issuance of restricted stock, RSUs and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to directors under the 2026, 2021 and 2018 Stock Plans for Non-Employee Directors. During the six months ended June 30, 2026, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan (before May 13, 2026) and the 2026 NED Plan (after May 13, 2026): Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology Time-Based RSUs 1 56,844 February 4, 2026 $ 31.67 Closing Stock Price Time-Based RSUs 2 2,150 March 31, 2026 $ 41.25 Closing Stock Price Time-Based RSUs 2 2,723 June 30, 2026 $ 32.56 Closing Stock Price 1 Non-Employee Directors’ time-based RSUs generally 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. 2 Non-Employee Directors may elect to receive all or a portion of their annual cash 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. 14 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. Six Months Ended June 30, (Thousands of dollars) 2026 2025 Compensation charged against income before tax benefit $ 22,772 $ 20,758 Related income tax benefit recognized in income 3,476 2,832 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 Per Common Share Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three and six months ended June 30, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations. Three Months Ended June 30, Six Months Ended June 30, (Weighted-average shares, except per share amounts) 2026 2025 2026 2025 Basic method 143,350,677 142,720,904 143,216,239 143,502,425 Dilutive restricted stock units 2,797,833 494,710 2,677,629 641,426 Diluted method 146,148,510 143,215,614 145,893,868 144,143,851 NET INCOME PER COMMON SHARE – BASIC $ 1.62 $ 0.16 $ 1.99 $ 0.66 NET INCOME PER COMMON SHARE – DILUTED $ 1.59 $ 0.16 $ 1.95 $ 0.66 Note K – Income Taxes The Company’s effective income tax rate is calculated as the amount of income tax expense divided by income from continuing operations before income taxes. For the three and six months ended June 30, 2026 and 2025, the Company’s effective income tax rates were as follows: 2026 2025 Three months ended June 30, 22.6 % 3.0 % Six months ended June 30, 27.6 % 21.4 % The effective tax rate for the three months ended June 30, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; 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 impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM. The effective tax rate for the three months ended June 30, 2025 was below the U.S. statutory tax rate of 21% primarily due to 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 six months ended June 30, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; and the effects of income generated in foreign tax jurisdictions, certain of which have income tax 15 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note K – Income Taxes (Continued) rates higher than the U.S. federal rate. The impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM. The effective tax rate for the six months ended June 30, 2025 was above the U.S. statutory tax rate of 21% 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; 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. For the six months ended June 30, 2026, the Company paid $ 5.9 million in net cash income tax payments, compared to $ 0.4 million in net cash income tax payments for the six months ended June 30, 2025. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of June 30, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2021. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. 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. 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 derivative instruments outstanding at June 30, 2026 and 2025. Commodity Price Risks The Company is subject to commodity price risk related to products it produces and sells. During the three and six months ended June 30, 2026, the Company did no t have any crude oil or natural gas derivative contracts. During the second quarter of 2025, the Company held 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 June 30, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows: NYMEX Henry Hub Area Commodity Volumes MMCF/d Price/MCF Start Date End Date Fixed price derivative swap United States Natural Gas 60 $ 3.65 7/1/2025 9/30/2025 Fixed price derivative swap United States Natural Gas 60 $ 3.74 10/1/2025 12/31/2025 16 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note L – Financial Instruments and Risk Management (Continued) For the three and six months ended June 30, 2026 and 2025, 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: (Thousands of dollars) Three Months Ended June 30, Six Months Ended June 30, Type of Derivative Contract Statement of Operations Location 2026 2025 2026 2025 Commodity swaps Gain on derivative instruments $ — $ 10,808 $ — $ 1,349 Fair Values – Recurring The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. The fair value measurements for these assets and liabilities at June 30, 2026 and December 31, 2025, are shown in the following table. June 30, 2026 December 31, 2025 (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Liabilities: Nonqualified employee savings plan $ 23,641 $ — $ — $ 23,641 $ 22,205 $ — $ — $ 22,205 $ 23,641 $ — $ — $ 23,641 $ 22,205 $ — $ — $ 22,205 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 June 30, 2026 and December 31, 2025. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at June 30, 2026 and December 31, 2025. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was minimal. June 30, 2026 December 31, 2025 (Thousands of dollars) Carrying Amount Fair Value Carrying Amount Fair Value Financial liabilities: Current and long-term debt $ 1,550,442 $ 1,512,574 $ 1,385,080 $ 1,326,101 Fair Values – Nonrecurring There were no impairment charges incurred in the three and six months ended June 30, 2026 and 2025. 17 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note M – Accumulated Other Comprehensive Loss The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and June 30, 2026, and the changes during the six months ended June 30, 2026, 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, 2025 $ ( 442,331 ) $ ( 111,896 ) $ ( 554,227 ) Components of other comprehensive income (loss): Before reclassifications to income ( 54,641 ) — ( 54,641 ) Reclassifications to income ¹ — 2,802 2,802 Net other comprehensive income (loss) ( 54,641 ) 2,802 ( 51,839 ) Balance at June 30, 2026 $ ( 496,972 ) $ ( 109,094 ) $ ( 606,066 ) 1 Reclassifications before taxes of $ 3.3 million are included in the computation of net periodic benefit expense for the six months ended June 30, 2026. 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 six months ended June 30, 2026. 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 18 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note N – Environmental and Other Contingencies (Continued) item, the Company will be using a threshold of $ 1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $ 1.0 million threshold. In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the One Big Beautiful Bill Act (OBBBA) passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions. The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change 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 19 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Note N – Environmental and Other Contingencies (Continued) 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 six months ended June 30, 2026 and 2025 is shown below. ( Number of shares outstanding ) June 30, 2026 June 30, 2025 Beginning of period 142,785,152 145,845,124 Restricted stock awards 1 570,680 494,071 Treasury shares purchased — ( 3,613,450 ) End of period 143,355,832 142,725,745 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 six months ended June 30, 2026, the Company did no t repurchase any shares of its common stock. During the six months ended June 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 June 30, 2026, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program. 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 includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. 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 attributed to the Canada segment. 20 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 and Discontinued Operations Consolidated Total Three Months Ended June 30, 2026 Revenue from production $ 743.0 $ 183.3 $ — $ 926.3 $ — $ 926.3 Gain on sale of assets and other operating income 1.0 0.3 — 1.3 0.7 2.0 Total revenues and other income 744.0 183.6 — 927.6 0.7 928.3 Lease operating expenses Lease operating expenses and taxes other than income 69.7 45.3 0.3 115.3 — 115.3 Repair and maintenance 17.8 0.7 — 18.5 — 18.5 Workovers 6.0 3.9 — 9.9 — 9.9 Total lease operating expenses 93.5 49.9 0.3 143.7 — 143.7 Severance and ad valorem taxes 14.1 0.9 — 15.0 — 15.0 Transportation, gathering and processing 24.6 20.7 — 45.3 — 45.3 Selling and general expenses 7.6 7.0 2.7 17.3 21.4 38.7 Exploration Expenses Geological and geophysical 10.2 — 1.0 11.2 — 11.2 Dry holes and previously suspended exploration costs ( 0.4 ) — 13.9 13.5 — 13.5 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 5.0 — 9.6 14.6 — 14.6 Total exploration expenses 14.8 — 24.5 39.3 — 39.3 Depreciation, depletion and amortization 220.5 39.2 — 259.7 2.4 262.1 Accretion of asset retirement obligations 11.9 2.7 0.2 14.8 0.1 14.9 Other operating expenses 16.4 — 0.3 16.7 ( 2.0 ) 14.7 Interest Income ( 0.6 ) — — ( 0.6 ) ( 2.3 ) ( 2.9 ) Interest expense, net of capitalization 0.1 ( 0.1 ) 0.1 0.1 24.8 24.9 Income tax expense Current income tax expense 1.9 14.5 — 16.4 4.9 21.3 Deferred income tax expense (benefit) 64.1 ( 3.2 ) 1.7 62.6 ( 6.9 ) 55.7 Total income tax expense (benefit) 66.0 11.3 1.7 79.0 ( 2.0 ) 77.0 Other segment costs (income) 0.9 0.1 0.4 1.4 ( 9.3 ) ( 7.9 ) Segment income (loss) - including NCI 1 $ 274.2 $ 51.9 $ ( 30.2 ) $ 295.9 $ ( 32.4 ) $ 263.5 Additions to property, plant, equipment $ 263.2 $ 64.3 $ 128.8 $ 456.3 $ 7.1 $ 463.4 Total assets at quarter-end 6,919.3 1,979.5 801.3 9,700.1 578.0 10,278.1 1 Includes results attributable to a noncontrolling interest in MP GOM. 21 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 and Discontinued Operations Consolidated Total Three Months Ended June 30, 2025 Revenue from production $ 552.2 $ 127.9 $ 2.9 $ 683.0 $ — $ 683.0 Gain on sale of assets and other operating income 1.3 0.4 — 1.7 13.1 14.8 Total revenues and other income 553.5 128.3 2.9 684.7 13.1 697.8 Lease operating expenses Lease operating expenses and taxes other than income 100.0 46.6 0.9 147.5 — 147.5 Repair and maintenance 13.9 1.1 — 15.0 — 15.0 Workovers 52.6 0.5 — 53.1 — 53.1 Total lease operating expenses 166.5 48.2 0.9 215.6 — 215.6 Severance and ad valorem taxes 10.5 0.3 — 10.8 — 10.8 Transportation, gathering and processing 30.3 23.8 — 54.1 — 54.1 Selling and general expenses 4.8 5.7 2.6 13.1 23.8 36.9 Exploration Expenses Geological and geophysical 0.7 — 0.2 0.9 — 0.9 Dry holes and previously suspended exploration costs ( 1.0 ) — 0.1 ( 0.9 ) — ( 0.9 ) Other exploratory costs, including undeveloped lease amortization and delay lease rentals 3.6 — 6.8 10.4 — 10.4 Total exploration expenses 3.3 — 7.1 10.4 — 10.4 Depreciation, depletion and amortization 218.3 38.1 1.2 257.6 1.7 259.3 Accretion of asset retirement obligations 11.6 2.6 0.2 14.4 — 14.4 Other operating expenses 1.3 0.7 ( 1.4 ) 0.6 1.2 1.8 Interest income ( 0.5 ) — — ( 0.5 ) ( 2.7 ) ( 3.2 ) Interest expense, net of capitalization — 0.2 — 0.2 24.9 25.1 Income tax expense Current income tax expense (benefit) 0.7 0.3 0.2 1.2 ( 5.0 ) ( 3.8 ) Deferred income tax expense (benefit) 19.2 ( 2.2 ) ( 0.7 ) 16.3 ( 11.5 ) 4.8 Total income tax expense (benefit) 19.9 ( 1.9 ) ( 0.5 ) 17.5 ( 16.5 ) 1.0 Other segment costs 1.0 0.1 0.1 1.2 35.3 36.5 Segment income (loss) - including NCI 1 $ 86.5 $ 10.5 $ ( 7.3 ) $ 89.7 $ ( 54.6 ) $ 35.1 Additions to property, plant, equipment $ 176.2 $ 45.7 $ 20.8 $ 242.6 $ 2.7 $ 245.4 Total assets at quarter-end 6,984.9 2,038.6 364.4 9,387.9 451.6 9,839.5 1 Includes results attributable to a noncontrolling interest in MP GOM. 22 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 and Discontinued Operations Consolidated Total Six Months Ended June 30, 2026 Revenue from production $ 1,317.7 $ 338.1 $ 2.9 $ 1,658.7 $ — $ 1,658.7 Gain on sale of assets and other operating income 1.8 0.7 — 2.5 0.7 3.2 Total revenues and other income 1,319.5 338.8 2.9 1,661.2 0.7 1,661.9 Lease operating expenses Lease operating expenses and taxes other than income 150.5 87.1 1.1 238.7 — 238.7 Repair and maintenance 30.1 1.4 — 31.5 — 31.5 Workovers 10.7 6.3 — 17.0 — 17.0 Total lease operating expenses 191.3 94.8 1.1 287.2 — 287.2 Severance and ad valorem taxes 27.0 1.7 — 28.7 — 28.7 Transportation, gathering and processing 49.7 42.6 — 92.3 — 92.3 Selling and general expenses 13.1 14.5 4.7 32.3 41.2 73.5 Exploration Expenses Geological and geophysical 11.0 — 1.8 12.8 — 12.8 Dry holes and previously suspended exploration costs ( 0.4 ) — 81.0 80.6 — 80.6 Other exploratory costs, including undeveloped lease amortization and delay lease rentals 9.9 — 18.8 28.7 — 28.7 Total exploration expenses 20.5 — 101.6 122.1 — 122.1 Depreciation, depletion and amortization 437.4 73.2 1.1 511.7 4.8 516.5 Accretion of asset retirement obligations 23.5 5.3 0.4 29.2 0.2 29.4 Other operating expenses 20.4 0.1 0.6 21.1 ( 2.0 ) 19.1 Interest Income ( 0.8 ) — — ( 0.8 ) ( 4.6 ) ( 5.4 ) Interest expense, net of capitalization 0.2 — 0.1 0.3 53.6 53.9 Income tax expense Current income tax expense 2.9 24.2 0.3 27.4 7.1 34.5 Deferred income tax expense (benefit) 101.4 ( 1.6 ) 5.1 104.9 ( 12.4 ) 92.5 Total income tax expense (benefit) 104.3 22.6 5.4 132.3 ( 5.3 ) 127.0 Other segment costs (income) 2.0 0.5 0.7 3.2 ( 17.8 ) ( 14.6 ) Segment income (loss) - including NCI 1 $ 430.9 $ 83.5 $ ( 112.8 ) $ 401.6 $ ( 69.4 ) $ 332.2 Additions to property, plant, equipment $ 518.0 $ 126.4 $ 200.1 $ 844.5 $ 16.4 $ 860.9 Total assets at quarter-end 6,919.3 1,979.5 801.3 9,700.1 578.0 10,278.1 1 Includes results attributable to a noncontrolling interest in MP GOM. 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 and Discontinued Operations Consolidated Total Six Months Ended June 30, 2025 Revenue from production $ 1,059.7 $ 293.2 $ 2.9 $ 1,355.8 $ — $ 1,355.8 Gain on sale of assets and other operating income 3.3 0.8 — 4.1 3.6 7.7 Total revenues and other income 1,063.0 294.0 2.9 1,359.9 3.6 1,363.5 Lease operating expenses Lease operating expenses and taxes other than income 200.3 91.9 1.2 293.4 — 293.4 Repair and maintenance 24.1 2.6 — 26.7 — 26.7 Workovers 99.7 0.8 — 100.5 — 100.5 Total lease operating expenses 324.1 95.3 1.2 420.6 — 420.6 Severance and ad valorem taxes 18.8 0.7 — 19.5 — 19.5 Transportation, gathering and processing 59.0 43.9 — 102.9 — 102.9 Selling and general expenses 6.8 11.7 4.5 23.0 44.8 67.8 Exploration Expenses Geological and geophysical 3.9 — 0.5 4.4 — 4.4 Dry holes and previously suspended exploration costs ( 0.8 ) — 0.1 ( 0.7 ) — ( 0.7 ) Other exploratory costs, including undeveloped lease amortization and delay lease rentals 6.3 0.1 14.8 21.2 — 21.2 Total exploration expenses 9.4 0.1 15.4 24.9 — 24.9 Depreciation, depletion and amortization 377.6 70.5 1.3 449.4 4.1 453.5 Accretion of asset retirement obligations 23.0 5.1 0.4 28.5 — 28.5 Other operating expenses 4.0 1.7 ( 1.3 ) 4.4 3.1 7.5 Interest Income ( 0.9 ) — — ( 0.9 ) ( 6.0 ) ( 6.9 ) Interest expense, net of capitalization — — 0.1 0.1 48.5 48.6 Income tax expense Current income tax expense (benefit) 1.3 14.0 0.2 15.5 ( 2.9 ) 12.6 Deferred income tax expense (benefit) 43.7 ( 1.6 ) ( 0.7 ) 41.4 ( 20.2 ) 21.2 Total income tax expense (benefit) 45.0 12.4 ( 0.5 ) 56.9 ( 23.1 ) 33.8 Other segment costs 1.8 0.6 0.3 2.7 35.6 38.3 Segment income (loss) - including NCI 1 $ 194.4 $ 52.0 $ ( 18.5 ) $ 227.9 $ ( 103.4 ) $ 124.5 Additions to property, plant, equipment $ 493.2 $ 101.1 $ 56.1 $ 650.4 $ 7.0 $ 657.4 Total assets at quarter-end 6,984.9 2,038.6 364.4 9,387.9 451.6 9,839.5 1 Includes results attributable to a noncontrolling interest in MP GOM. 24 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 period ended June 30, 2026 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, 2025. 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 execu t ion 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 the noncontrolling interest in MP GOM, unless otherwise noted. Significant Company financial and operational highlights during the second quarter of 2026 were as follows: • Production was 175,013 barrels of oil equivalent (BOE) per day (including NCI), a decrease from 196,315 BOE per day in the second quarter of 2025; • Drilled an oil discovery at Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire; • Concluded the Hai Su Vang (Golden Sea Lion) appraisal program with the completion of Hai Su Vang-4X (Block 15-2/17) appraisal well, which was expensed as a dry hole; • Completed drilling operations and initiated completion activities at the Chinook #8 (Walker Ridge 425) development well in the Gulf of America; • Finalized pipeline installation and launched the FSO (Floating Storage and Offloading vessel) at the Lac Da Vang development project in Vietnam; and • Brought online six Eagle Ford Shale wells and four Kaybob Duvernay wells. Subsequent to the second quarter: • Spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d'Ivoire; • Spud the Lac Da Trang (White Camel) North-1X exploration well in Block 15-1/05 in Vietnam; and • Completed installation of topsides and mobilized FSO to final location for Lac Da Vang development project. Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2026 was $264.0 million compared to net income of $33.8 million for the same period in 2025. The increase in 2026 was primarily driven by higher revenues from production ($243.3 million), lower lease operating expenses ($71.8 million), higher other income ($43.6 million), and lower transportation, gathering and processing expenses ($8.8 million). These favorable items were partially offset by higher income tax expense ($76.0 million), higher exploration expense ($28.9 million), and higher other operating expenses ($12.9 million). Higher revenues were primarily driven by higher realized crude oil prices in the United States, partially offset by lower oil sales volumes in the Gulf of America. Canada oil revenues also increased, driven by higher oil prices and increased production and sales at Terra Nova and Hibernia, as well as new wells at Kaybob; these items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Khaleesi, Marmalard and Samurai and 25 Table of Contents