What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2026-02-25 compared with 2025-02-27 · 568 added, 507 removed, 2060 unchanged (34% of the section changed)

15 unchanged sentences

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance tab at ir.murphyoilcorp.com.

Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Corporate Secretary at 9805 Katy Fwy, Suite G-200, Houston, TX 77024.

Stockholders may also obtain, free of charge, a copy of the Code of Ethical Conduct for Executive Management by writing to the Corporate Secretary at 9805 Katy Freeway, Suite G-200, Houston, TX 77024.

Any future amendments to or waivers of the Code of Ethical Conduct for Executive Management will be posted on the Company’s Website.

Murphy Oil has also adopted an insider trading policy governing the purchase, sale, and/or other dispositions of our securities by our directors, officers, employees and contractors and consultants who have access to material nonpublic information, as well as the Company itself, that we believe is reasonably designed to promote compliance with insider trading laws, rules and regulations, and the exchange listing standards applicable to us.

A copy of our insider trading policy, including any amendments thereto, is filed as Exhibit 19.

1 to this Form 10-K.

A copy of our insider trading policy, including any amendments thereto, is filed as Exhibit 19.1 to this Form 10-K.

EXECUTIVE COMPENSATION

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Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 13, 2026 under the caption “Election of Directors”.

PRINCIPAL ACCOUNTING FEES AND SERVICES

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Houston, TX, Auditor Firm ID:

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Supplemental Quarterly Information (unaudited)

Financial Statement Schedules

Schedule II – Valuation Accounts and Reserves

All other financial statement schedules are omitted because either they are not applicable, or the required information is included in the consolidated financial statements or notes thereto.

Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference.

Financial Statement Schedules – All financial statement schedules are omitted because either they are not applicable, or the required information is included in the consolidated financial statements or notes thereto.

Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed as indicated by double asterisks (**), or that are incorporated by reference.

Exhibits other than those listed have been omitted since they either are not required or are not applicable.

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Exhibit 3.2 to Form 10-Q filed August 6, 2020

4.1 Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee

Exhibit 4.2 to Form 10-K filed March 16, 2005

4.1 Supplemental Indenture dated as of May 4, 1999 between Murphy Oil Corporation and SunTrust Bank, Nashville, N.A., as trustee, relating to 7.05% Notes due 2029

14 unchanged sentences

Exhibit 4.2 to Form 8-K filed March 5, 2021

4.8 S eventh Sup plemental Indenture date d as of October 3, 2024 ,between Murphy Oil Corporation and R egions Bank, as trustee, rela t ing to 6.000% Note s due 2032

4.7 Seventh Supplemental Indenture dat ed as of October 3, 2024,between Murphy Oil Corporation and Regions Bank, as trustee, relating to 6.000% Notes due 2032

Exhibit 4.2 to Form 8-K filed October 3, 2024

4.8 Eighth Supplemental Indenture, dated as of January 23, 2026, between Murphy Oil Corporation and Regions Bank, as trustee (including the Form of 6.500% Notes due 2034)

Exhibit 4.2 to Form 8-K filed January 23, 2026

10.1 Murphy Oil Corporation Annual Incentive Plan

1 unchanged sentence

10.2 Murphy Oil Corporation 2020 Long-Term Incentive Plan

Exhibit B to definitive proxy statement filed March 23, 2018

Amendment to the Murphy Oil Corporation 2018 Long-Term Incentive Plan

Exhibit 10.15 to Form 10-K filed February 27, 2020

Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Incentive Plan)

Exhibit 10.14 to Form 10-K filed February 27, 2019

Form of employee performance-based restricted stock unit – stock settled grant agreement (2018 Long-Term Incentive Plan)

Exhibit 10.17 to Form 10-K filed February 27, 2020

Form of employee time-based restricted stock unit – stock settled 3-year grant agreement (2018 Long-Term Incentive Plan)

Exhibit 10.15 to Form 10-K filed February 27, 2019

Form of employee time-based restricted stock unit – stock settled 5-year grant agreement (2018 Long-Term Incentive Plan)

Exhibit 10.16 to Form 10-K filed February 27, 2019

10.8 Murphy Oil Corporation 2020 Long-Term Incentive Plan

Exhibit A to definitive proxy statement filed March 30, 2020

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Form of employee performance-based restricted stock unit (2020 LTI Plan)

Exhibit 10.30 to Form 10-K filed February 23, 2024

Exhibit 10.23 to Form 10-Q filed May 7, 2025

Form of employee time-based restricted stock unit – A (2020 LTI Plan)

Exhibit 10.31 to Form 10-K filed February 23, 2024

Exhibit 10.24 to Form 10-Q filed May 7, 2025

Form of employee time-based restricted stock unit – B (2020 LTI Plan)

Exhibit 10.32 to Form 10-K filed February 23, 2024

Exhibit 10.25 to Form 10-Q filed May 7, 2025

Form of employee time-based restricted stock unit – C (2020 LTI Plan)

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Form of Severance Protection Agreement

Exhibit 10.32 to Form 10-K filed February 27, 2025

First Amendment to the New Credit Agreement dated as of February 6, 2025 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party hereto

Exhibit 10.33 to Form 10-K filed February 27, 2025

Murphy Oil Corporation 2025 Long-Term Incentive Plan

Exhibit A to definitive proxy statement filed on March 28, 2025

Form of employee performance-based restricted stock unit (2025 LTI Plan)

Exhibit 10.35 to Form 10-Q filed November 5, 2025

Form of employee time-based restricted stock unit – A (2025 LTI Plan)

Exhibit 10.36 to Form 10-Q filed November 5, 2025

Second Amendment to the Credit Agreement dated as of January 2, 2026 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd.

as borrowers, Murphy Exploration & Production Company and Murphy Exploration & Production Company – USA, as guarantors, JP Morgan Chase Bank, N.A.

as administrative agent, and each of the lenders party thereto

Exhibit 10.1 to Form 8-K filed January 6, 2026

Form of e mplo yee performance-based re s tr icted stock u nit — B (2025 LTI Plan)

Form of employee time-based restricted stock unit — B (2025 LTI Plan)

Form of employee tim e-based restricted stock unit — C (2025 LTI Plan)

Form of employee tim e-based restricted stock unit — D (2025 LTI Plan)

Murphy Oil Corporation Insider Trading Policy

Exhibit 19.1 to Form 10-K filed February 27, 2025

*21.1 Subsidiaries of Murphy Oil Corporation

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*23.3 Consent of McDaniel & Associates Consultants Ltd.

Consent of Ne therland , S ewell & Associates , Inc.

Consent of Netherland, Sewell & Associates, Inc.

C onsent of GLJ Petro leum Consultants Ltd.

*31.1 Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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Exhibit 10.29 to Form 10-K filed February 23, 2024

Ryder Scott independ ent reserves audit report for MP GOM JV

McDaniel independent reserves audit report for Canada Onshore proved crude oil and natural gas reserves

*99.1 Ryder Scott independent reserves audit report for MP GOM JV

R yder Scott independ ent reserves au dit report for U .S.

McDaniel independent reserves audit report for Canada Onshore

Netherland, Sewell & Associates, Inc.

independent reserves audit report U.S.

Gulf of Mexico

Gulf of America

GLJ independent reserves au dit for Canada Offshore

101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

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/s/ CLAIBORNE P.

DEMING /s/ JAMES V.

Deming, Chairman and Director James V.

Kelley, Director

MADISON MURPHY

DEMING /s/ JEFFREY W.

Deming, Chairman and Director Jeffrey W.

Nolan, Director

/s/ ROBERT N.

Hambly, President and

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(Principal Executive Officer)

Madison Murphy, Director

/s/ LAWRENCE R.

DICKERSON /s/ JEFFREY W.

Dickerson, Director Jeffrey W.

Nolan, Director

/s/ MICHELLE A.

EARLEY /s/ ROBERT N.

Earley, Director Robert N.

Ryan, Jr., Director

/s/ ELISABETH W.

KELLER /s/ LAURA A.

Keller, Director Laura A.

/s/ LAWRENCE R.

DICKERSON /s/ LAURA A.

Dickerson, Director Laura A.

Sugg, Director

/s/ ROBERT B.

/s/ THOMAS J.

/s/ MICHELLE A.

EARLEY /s/ ROBERT B.

Earley, Director Robert B.

Tudor, III, Director

/s/ ELISABETH W.

KELLER /s/ THOMAS J.

Keller, Director Thomas J.

Mireles, Executive Vice President

1 unchanged sentence

(Principal Financial Officer)

MADISON MURPHY /s/ PAUL D.

Madison Murphy, Director Paul D.

Vice President and Controller

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Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2024, and the related notes and financial statement schedule II (collectively, the consolidated financial statements).

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S.

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We compared the forecasted operating costs to historical results.

We also evaluated the forecasted nature and timing of future development costs by obtaining an understanding of the development projects and comparing the development projects with the available development plans.

We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices and recalculated the relevant market differentials.

We also evaluated the forecasted nature and timing of future development costs by obtaining an understanding of the development projects.

We assessed the oil and gas prices utilized by the internal petroleum reserve engineers by comparing them to publicly available prices.

In addition, we read and considered the report of the Company’s third-party petroleum reserve specialists in connection with our evaluation of the Company’s proved oil and gas reserve estimates.

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In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2024, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 27, 2025 expressed an unqualified opinion on those consolidated financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

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805,464 777,536

Deferred income taxes Note H

Deferred charges and other assets 74,104 50,011

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Current maturities of long-term debt, finance lease Note F

$ 2,514 $ 871

Accounts payable 572,183 472,165

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Other accrued liabilities 120,755 117,802

Current asset retirement obligations 1

Current asset retirement obligations Note G

41,959 48,080

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Cumulative Preferred Stock, par $ 100 , authorized 400,000 shares, none issued

Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares in 2024 and 195,100,628 shares in 2023

Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at December 31, 2025 and 195,100,628 shares at December 31, 2024

195,101 195,101

8 unchanged sentences

Total liabilities and equity $ 9,832,626 $ 9,667,479

1 The prior-period amount has been reclassified to conform to the current period presentation.

The accompanying notes are an integral part of these consolidated financial statements.

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Total revenue from sales to customers 2,689,845 3,018,598 3,448,854

(Loss) on derivative instruments ( 1,707 ) — ( 320,410 )

Gain (loss) on derivative instruments 5,927 ( 1,707 ) —

Gain on sale of assets and other operating income 23,051 11,583 11,293

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Income from continuing operations 138,314 489,297 725,148

Loss from discontinued operations, net of income taxes ( 2,812 ) ( 1,467 ) ( 2,078 )

Income (loss) from discontinued operations, net of income taxes 485 ( 2,812 ) ( 1,467 )

Net income including noncontrolling interest 138,799 486,485 723,681

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Other comprehensive income (loss), net of tax

Net (loss) gain from foreign currency translation

Net gain (loss) from foreign currency translation

73,993 ( 134,692 ) 36,598

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Amortization of undeveloped leases 11,634 9,587 10,925

Loss from discontinued operations 2,812 1,467 2,078

Mark-to-market loss (gain) on derivative instruments

1,707 — ( 214,788 )

Contingent consideration payment

(Income) loss from discontinued operations

( 485 ) 2,812 1,467

Mark-to-market loss on contingent consideration

Unrealized (gain) loss on derivative instruments

( 1,706 ) 1,707 —

Gain from sale of assets

Contingent consideration payment

— — ( 139,574 )

Unrealized loss on contingent consideration

Other operating activities, net ( 86,763 ) ( 18,349 ) ( 74,728 )

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( 264,065 ) ( 716,541 ) ( 923,718 )

Net cash required by discontinued operations

— — ( 14,500 )

Effect of exchange rate changes on cash and cash equivalents ( 1,190 ) 2,210 ( 1,246 )

3 unchanged sentences

Cash and cash equivalents at end of period $ 377,196 $ 423,569 $ 317,074

1 Prior period amounts have been reclassified to conform to current period presentation.

The accompanying notes are an integral part of these consolidated financial statements.

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Balance at beginning of year ( 628,072 ) ( 521,117 ) ( 534,686 )

Foreign currency translation (loss) gain, net of income taxes

Foreign currency translation gain (loss), net of income taxes

73,993 ( 134,692 ) 36,598

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Total Equity $ 5,236,697 $ 5,341,843 $ 5,549,653

1 Prior-period amounts have been aggregated to conform to the current period presentation.

The accompanying notes are an integral part of these consolidated financial statements.

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Actual results may differ from the estimates.

REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas and NGLs are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer;

REVENUE RECOGNITION – Revenues from sales of oil and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer;

the amount of revenue recognized reflects the consideration expected in exchange for those commodities.

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Development costs, including unsuccessful development wells, are capitalized.

Interest is capitalized on significant development projects that are expected to take one year or more to complete.

Oil and natural gas properties are evaluated by field for potential impairment.

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Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.

LEASES – At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842, “Leases”.

LEASES – At inception, contracts are assessed for the presence of a lease according to the criteria of ASC 842, “Leases”.

If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease.

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Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.

Operating leases are expensed according to their nature and recognized in “Lease operating expenses”, “Selling and general expenses” or capitalized in the consolidated financial statements.

Finance leases are depreciated with the relevant expenses recognized in “Depreciation, depletion and amortization” and “Interest expense, net” on the Consolidated Statement of Operations.

Operating leases are expensed according to their nature and recognized in “Lease operating expenses”, “Selling and general expenses”, “Transportation, gathering and processing”, “Exploration expenses”, “Other operating expenses” or capitalized in the consolidated financial statements.

Finance leases are depreciated with the relevant expenses recognized in “Depreciation, depletion and amortization” and “Interest expense, net” on the Consolidated Statements of Operations.

ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists, and the cost can be reasonably estimated.

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Gains or losses from translating foreign functional currencies into U.S.

dollars are included in “Accumulated Other Comprehensive Loss” in Consolidated Statements of Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets.

dollars are included in “Accumulated Other Comprehensive Loss” in the Consolidated Statements of Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Consolidated Balance Sheets.

Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or it may decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings.

Sale and purchase contracts in the normal course of business are not designated as hedges for accounting purposes.

Certain physical delivery sale and purchase contracts are entered into in the normal course of business and qualify for, and are designated under, the normal purchase and normal sale scope exception provided by ASC 815, “Derivatives and Hedging”.

Accordingly, these contracts are not accounted for as derivative instruments or recorded at fair value in the Consolidated Balance Sheets.

Revenues and expenses associated with these contracts are recognized in net income (loss) when the underlying physical transactions occur.

The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its risk management objectives and strategy.

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The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item.

The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in “Accumulated other comprehensive loss” in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings.

If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in “Accumulated other comprehensive loss” is recognized immediately in earnings.

The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note A – Significant Accounting Policies (Continued)

commodity price derivatives for the periods provided are not designated as cash flow or fair value hedges and therefore changes in fair value are recognized in earnings.

“Accumulated other comprehensive loss” in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings.

All commodity price derivatives for the periods provided are not designated as cash flow or fair value hedges and therefore changes in fair value are recognized in earnings.

FAIR VALUE MEASUREMENTS – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets.

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PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets.

Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in “Accumulated other comprehensive loss”.

Changes in the funded status which have not yet been recognized in the Consolidated Statements of Operations are recorded net of tax in “Accumulated other comprehensive loss”.

The remaining amounts in “Accumulated other comprehensive loss” include net actuarial losses and prior service (cost) credit.

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Accounting Principles Adopted

Reportable Segment Disclosures.

In November 2023, the FASB issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280):

Improvements to Reportable Segment Disclosures .

The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods.

Income Tax Disclosures.

In December 2023, the FASB issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740):

Improvements to Income Tax Disclosures.

The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction.

The Company adopted this standard in the fourth quarter of

The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements.

These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements.

Refer to Note S .

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note B - New Accounting Principles and Recent Accounting Pronouncements (Continued)

The adoption did not affect the calculation of income tax expense.

These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements.

Refer to Note H .

Recent Accounting Pronouncements

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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.

We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

We are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption.

We expect this ASU to only impact our disclosures with no impacts on our results of operations, cash flows and financial condition.

The Company evaluates the applicability and impact of all ASUs.

ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and NGLs (collectively referred to as oil and natural gas) in select basins around the world.

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:

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Sales of purchased natural gas 2

United States - Offshore

Canada - Onshore

2 unchanged sentences

Total revenue from sales to customers 2,689,845 3,018,598 3,448,854

(Loss) on derivative instruments ( 1,707 ) — ( 320,410 )

Gain (loss) on derivative instruments 5,927 ( 1,707 ) —

Gain on sale of assets and other operating income 23,051 11,583 11,293

1 unchanged sentence

$ 2,718,823 $ 3,028,474 $ 3,460,147

1 Includes revenue attributable to noncontrolling interest in MP GOM.

1 Includes revenue attributable to the noncontrolling interest in MP GOM.

2 Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and has risks and rewards of ownership.

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As of December 31, 2025, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract.

Long-Term Contracts Outstanding at December 31, 2024

Location Commodity End Date Description Approximate Volumes

Natural Gas and NGLs Q2 2030 Deliveries from dedicated acreage in Eagle Ford As produced

Canada Natural Gas Q4 2025 Contracts to sell natural gas at USD index pricing 25 MMCFD

Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCFD

Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCFD

Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCFD

Canada Natural Gas Q4 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD

Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCFD

Canada NGLs Q2 2025 Contracts to sell NGLs at CAD index pricing As produced

Natural Gas and NGLs Q2 2030 Deliveries from dedicated acreage in Eagle Ford Shale As produced

Canada Natural Gas Q4 2026 Contracts to sell natural gas at USD index pricing 49 MMCF/D

Canada Natural Gas Q4 2027 Contracts to sell natural gas at USD index pricing 30 MMCF/D

Canada Natural Gas Q4 2028 Contracts to sell natural gas at USD index pricing 10 MMCF/D

Canada Natural Gas Q4 2026

Contracts to sell natural gas at CAD fixed pricing 50 MMCF/D

Canada Natural Gas Q4 2027

Contracts to sell natural gas at CAD fixed pricing 9 MMCF/D

Canada NGLs Q4 2026

Contracts to sell NGLs at CAD index pricing As produced

The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes.

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2 Includes $ 12,050 in 2025 and $ 13,335 in 2024 related to administrative assets and support equipment.

On September 15, 2023, the Company completed the previously announced divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash proceeds of C$ 139.0 million.

No gain or loss was recorded related to this transaction, and the effective date of the transaction was March 1, 2023.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Property, Plant and Equipment (Continued)

During the third quarter of 2022, the Company completed the disposition of its 62.5 % working interest of the Thunder Hawk field for a purchase price of $ 20.0 million less closing adjustments of $ 23.1 million, resulting in a total net payment to the buyer of $ 3.1 million.

Additionally, the buyer assumed the ARO liabilities of approximately $ 47.9 million.

A $ 17.9 million gain on sale was recorded in the period related to the sale.

In September 2022, the Company completed the disposition of its working interests in Block CA-2 in Brunei for contingent consideration valued at approximately $ 8.7 million.

No gain or loss was recorded related to this sale.

In August 2022, the Company acquired an additional working interest of 3.37 % in the non-operated Lucius field for a purchase price of $ 78.5 million, net of closing adjustments.

In June 2022, the Company acquired an additional working interest of 11.0 % in the non-operated Kodiak field for a purchase price of $ 50.0 million, net of closing adjustments.

In 2024, the Company recorded a pretax impairment charge of $ 62.9 million.

In the first quarter of 2024, the Company recorded an impairment charge of $ 34.5 million related to the Calliope field, and in the fourth quarter of 2024, the Company recorded an impairment charge of $ 28.4 million related to the Nearly Headless Nick field.

Both of the impairments were the result of operational issues that led to reserve reductions.

There were no impairments recognized in 2023 and 2022.

The following table reflects the recognized before tax impairments for each of the three years presented.

(Thousands of dollars) 2024 2023 2022

United States - Offshore

$ 62,909 $ — $ —

Exploratory Wells

2 unchanged sentences

The following table reflects the net changes in capitalized exploratory well costs for each of the three years presented.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Property, Plant and Equipment (Continued)

( Thousands of dollars )

3 unchanged sentences

Reclassifications to proved properties based on the determination of proved reserves — — ( 82,185 )

— — ( 7,915 )

Capitalized exploration well costs charged to expense — ( 26,471 ) ( 40,605 )

Ending balance at December 31 $ 191,821 $ 72,055 $ 49,118

Capital additions of $ 49.4 million, for the year ended December 31, 2024, are mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam.

Capitalized well costs charged to dry hole expense of $ 26.5 million, for the year ended December 31, 2024, related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well.

The preceding table excludes well costs of $ 46.7 million and $ 129.2 million incurred and expensed directly to dry hole during the year ended December 31, 2024 and 2023, respectively.

In 2024, these costs primarily include $ 27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 26.1 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America.

In 2023, the amount primarily includes $ 82.0 million for the Chinook #7 (Walker Ridge 425) and $ 47.2 million for the non-operated Oso #1 (Atwater Valley 138) exploration wells in the Gulf of America.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Property, Plant and Equipment (Continued)

Capital additions of $ 119.8 million, for the year ended December 31, 2025, were mainly for the Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam.

The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well, in Vietnam, encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations.

Capital additions also included Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and Bubale-1X (Block CI-709) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire.

Subsequent to year end, Murphy announced the successful discoveries of the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) exploration wells, which encountered 50 feet and 30 feet of net pay, respectively.

The Company also announced the results of two exploration wells in Côte d’Ivoire at the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and at the Caracal-1X (Block CI-102) exploration well, which will be plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows.

A portion of the Civette-1X dry hole charge was recorded in 2025.

The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026.

Capital additions of $ 49.4 million, for the year ended December 31, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration well in Vietnam.

Reclassifications to proved properties of $ 82.2 million, for the year ended December 31, 2023, were primarily related to Lac Da Vang-4X (Golden Camel), Block 15-1/05 exploration well in Vietnam.

Capitalized well costs charged to dry hole expense were $ 26.5 million and $ 40.6 million for the years ended 2024 and 2023, respectively.

In 2024, costs related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well.

In 2023, costs related to the Cholula-1EXP well offshore Mexico and the Oso #1 (Atwater Valley 138) and Chinook #7 (Walker Ridge 425) exploration wells in the Gulf of America.

The preceding table excludes well costs of $ 30.1 million, $ 46.7 million, and $ 129.2 million incurred and expensed directly to dry hole during the years ended 2025, 2024 and 2023, respectively.

In 2025, these costs primarily included $ 30.0 million for the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire.

In 2024, these costs primarily included $ 27.6 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 13.4 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America.

In 2023, the amount primarily included $ 82.0 million for the Chinook #7 (Walker Ridge 425) and $ 47.2 million for the non-operated Oso #1 (Atwater Valley 138) exploration wells in the Gulf of America.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well.

9 unchanged sentences

$ 191,821 11 $ 72,055 8 $ 49,118 4

Of the $ 22.3 million of exploratory well costs capitalized more than one year at December 31, 2024, $ 15.1 million was in Vietnam, $ 4.4 million was in Canada and $ 2.7 million was in Brunei.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note D – Property, Plant and Equipment (Continued)

Of the $ 163.4 million of exploratory well costs capitalized more than one year at December 31, 2025, $ 91.5 million was in Vietnam, $ 64.6 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei.

In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

On July 1, 2025, the Company purchased additional working interests in the Eagle Ford Shale, in acreages primarily operated by Murphy, for $ 23.0 million.

During the first quarter of 2025, Murphy purchased the Pioneer FPSO from BW Offshore (UK) Limited for a gross purchase price of $ 125.0 million.

The FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America.

BW Offshore (UK) Limited continues to provide operations and maintenance services under a new five-year contract.

In the fourth quarter of 2025, Murphy received a $ 12.5 million payment for achieving the first milestone related to the contingent sale of Brunei CA-2 in 2022, which resulted in a $ 4.0 million gain on sale of assets .

In addition, the revaluation of the final milestone (anticipated in 2031) resulted in a $ 6.0 million gain on sale of assets.

In September 2025, Murphy executed a purchase and sale agreement, which closed in October 2025, for the sale of leases in the Ralph and Saylee area of Tilden West for an adjusted sales price of $ 8.2 million.

No gain or loss was recorded for this sale.

In 2025, the Company recognized a pretax impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) related to the partial write-down of the Dalmatian field, in the Gulf of America, due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

In 2024, the Company recorded a pretax impairment charge of $ 62.9 million.

Both of the impairments were the result of operational issues that led to reserve reductions.

There were no impairments recognized in 2023.

Note E – Inventories

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6.000 % notes, due October 2032

600,000 600,000

5.875 % notes, due December 2042 ¹

5 unchanged sentences

Total debt including current maturities 1,285,080 1,275,373

Senior Unsecured Revolving Credit Facility 100,000 —

Current maturities ( 2,514 ) ( 871 )

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The amounts of long-term principal repayable over each of the next five years and thereafter are as follows:

nil in 2025, nil in 2026, $ 78.9 million in 2027, $ 148.6 million in 2028, $ 117.6 million in 2029 and $ 939.8 million thereafter.

nil in 2026, $ 78.9 million in 2027, $ 148.6 million in 2028, $ 217.6 million in 2029, nil in 2030 and $ 939.8 million thereafter.

The Company also has a shelf registration statement on file with the SEC that permits the offer and sale of debt and/or equity securities through October 15, 2027.

Revolving Credit Facility

During the fourth quarter of 2024, the Company entered into a credit agreement governing a $ 1.35 billion senior unsecured guaranteed RCF with a maturity date of October 7, 2029.

The RCF extends the borrowing term and increases the borrowing capacity of the previous RCF.

On the date the Company achieves certain credit ratings (Investment Grade Ratings Date), certain covenants will be modified as set forth in the RCF.

In addition, prior to Investment Grade Ratings Date, the Company will be required to comply with a maximum consolidated leverage ratio of 3.25 x and a minimum consolidated interest coverage ratio of 2.50 x.

As of December 31, 2025, the Company had a $ 1.35 billion senior unsecured guaranteed RCF, with a maturity date of October 7, 2029.

At December 31, 2025, the Company had $ 100.0 million outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduced the borrowing capacity of the RCF.

At December 31, 2025, the interest rate in effect on borrowings under the facility was 6.04 %.

At December 31, 2025, the Company was in compliance with all covenants related to the RCF.

On the date the Company achieved certain credit ratings (Investment Grade Ratings Date), certain covenants would have been modified as set forth in the RCF.

In addition, prior to Investment Grade Ratings Date, the Company would have been required to comply with a maximum consolidated leverage ratio of 3.25 x and a minimum consolidated interest coverage ratio of 2.50 x.

From and after the Investment Grade Ratings Date, the Company will be required to comply with a maximum ratio of consolidated total debt to consolidated total capitalization of 60 %.

Borrowings under the RCF bear interest at rates based on either the “Alternate Base Rate”, the “Adjusted Term Secured Overnight Financing Rate (SOFR) Rate”, or the “Adjusted Daily Simple SOFR Rate”, respectively, plus the “Applicable Rate”.

The “Alternate Base Rate” of interest is the highest of (a) the Wall Street Journal prime rate in effect on such day, (b) the New York Federal Reserve Bank Rate in effect on such day plus ½ of 1% and (c) the Adjusted Term SOFR Rate for a one month interest period as published two U.S.

Borrowings under the RCF bore interest at rates based on either the “Alternate Base Rate”, the “Adjusted Term Secured Overnight Financing Rate (SOFR) Rate”, or the “Adjusted Daily Simple SOFR Rate”, respectively, plus the “Applicable Rate”.

The “Alternate Base Rate” of interest was the highest of (a) the Wall Street Journal prime rate in effect on such day, (b) the New York Federal Reserve Bank Rate in effect on such day plus ½ of 1% and (c) the Adjusted Term SOFR Rate for a one month interest period as published two U.S.

Government Securities Business Days prior to such day (or if such day is not a U.S.

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Government Securities Business Day) plus 1 %.

The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10 %.

The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) 0.10 %.

The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc.

and Standard and Poor’s Rating Services, respectively.

The Company incurred $ 14.7 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the RCF.

At December 31, 2024, the Company had no outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF.

At December 31, 2024, the interest rate in effect on borrowings under the facility would have been 6.68 %.

At December 31, 2024, the Company was in compliance with all covenants related to the RCF.

The “Adjusted Term SOFR Rate” of interest was equal to (a) the Term SOFR Rate for such Interest Period, plus (b) 0.10 %.

The “Adjusted Daily Simple SOFR Rate” of interest was equal to (a) the Daily Simple SOFR, plus (b) 0.10 %.

The “Applicable Rate” of interest meant, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc.

and Standard and Poor’s Rating Services.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Note F - Financing Arrangements and Debt (Continued)

Subsequent Event - Revolving Credit Facility

On January 2, 2026, the Company entered into an amended credit agreement governing a $ 2.00 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031.

The Amended RCF, which is effective January 2026, extends the borrowing term and increases the borrowing capacity of the previous RCF.

All terms of the Amended RCF are substantially similar to the existing credit agreement, with an exception for the following:

The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero .

The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero .

The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc.

and Standard and Poor’s Rating Services, respectively.

The Company incurred $ 12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF.

Debt Offering

On October 3, 2024, the Company closed the public offering of $ 600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000 % per annum and mature on October 1, 2032.

The Company has incurred transaction costs of $ 10.1 million on the issuance of these new notes.

The Company will pay interest semi-annually on April 1 and October 1 of each year, beginning April 1, 2025.

On October 3, 2024, the Company closed the public offering of $ 600.0 million aggregate principal amount of senior notes that bear interest at a rate of 6.000 % per annum and mature on October 1, 2032.

The Company incurred transaction costs of $ 10.1 million on the issuance of these notes.

The Company pays interest semi-annually on April 1 and October 1 of each year.

The proceeds of the $ 600.0 million notes were used to fund the repurchase and repayment of debt during the fourth quarter of 2024 to achieve a debt-neutral transaction.

Subsequent Event - Debt Offering

On January 23, 2026, the Company closed a public offering of $ 500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.500 % per annum and mature on February 15, 2034.

The Company has incurred transaction costs of $ 8.3 million on the issuance of these new notes.

The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026.

The proceeds of the $ 500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes.

Debt Extinguishment

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The total cost of debt extinguishment of $ 0.9 million, consisting of cash costs of $ 0.5 million and non-cash costs of $ 0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024.

In November 2023, the Company tendered a total of $ 249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $ 250.0 million in aggregate principal.

The cost of debt extinguishment of $ 1.3 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023.

There were no additional cash costs related to the November 2023 debt extinguishment on the 2027 Notes, 2028 Notes and 2029 Notes for the year ended December 31, 2023.

In September 2023, the Company redeemed the remaining $ 248.7 million principal outstanding of the 2025 Notes.

The non-cash costs of debt extinguishment of $ 0.9 million were included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2023.

Subsequent Event - Debt Extinguishment

On January 23, 2026, the Company redeemed the remaining $ 78.9 million principal amount outstanding of its 2027 Notes and $ 148.6 million of its 2028 Notes, for an aggregate $ 227.5 million.

The total cost of the debt extinguishment of $ 3.5 million consisted of cash costs of $ 2.5 million and non-cash costs of $ 1.0 million.

Note G – Asset Retirement Obligations

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A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the respective periods presented is shown in the following table.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note G - Asset Retirement Obligations (Continued)

(Thousands of dollars) 2025 2024

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Non-current portion of liability $ 970,908 $ 960,804

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note G - Asset Retirement Obligations (Continued)

The estimation of future ARO is based on a number of assumptions requiring professional judgment.

9 unchanged sentences

Total $ 182,866 $ 567,569 $ 921,069

Income tax expense (benefit)

Federal – Current $ — $ — $ —

– Deferred 55,377 170,115 234,749

Federal 55,377 170,115 234,749

State ( 4,488 ) 6,622 9,010

Foreign – Current 4,685 13,182 18,134

– Deferred 22,698 6,002 47,571

Total Foreign 27,383 19,184 65,705

Total $ 78,272 $ 195,921 $ 309,464

Income tax expense

Current tax expense

State and Local

$ 468 $ 1,153 $ 2,916

9,411 4,685 13,182

Total current tax expense

9,879 5,838 16,098

Deferred tax expense

37,825 55,377 170,115

State and Local

( 1,214 ) ( 5,641 ) 3,706

( 1,938 ) 22,698 6,002

Total deferred tax expense

34,673 72,434 179,823

Total income tax expense

37,825 55,377 170,115

State and Local

( 746 ) ( 4,488 ) 6,622

7,473 27,383 19,184

Total income tax expense

$ 44,552 $ 78,272 $ 195,921

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note H – Income Taxes (Continued)

The following table reconciles income taxes based on the U.S.

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2025 2024 2023

Amount Percent Amount Percent Amount Percent

Income tax expense based on the U.S.

statutory tax rate $ 38,402 21.0 % $ 119,190 21.0 % $ 193,424 21.0 %

$ 119,190 $ 193,424 $ 304,555

Foreign income subject to foreign tax rates different than the U.S.

statutory rate

12,119 7,597 10,823

State income taxes, net of federal benefit ( 3,568 ) 4,725 7,118

Domestic Federal

Research and development tax credits 2,521 1.4 ( 6,841 ) ( 1.2 ) ( 8,805 ) ( 1.0 )

Nontaxable or Nondeductible Items

Tax effect on income attributable to NCI ( 7,259 ) ( 4.0 ) ( 16,656 ) ( 2.9 ) ( 13,046 ) ( 1.4 )

tax benefit on certain foreign upstream investments — — ( 33,677 ) ( 5.9 ) — —

Change in deferred tax asset valuation allowance related to other foreign exploration expenditures 2,636 10,853 24,748

Tax effect on income attributable to noncontrolling interest ( 16,656 ) ( 13,046 ) ( 36,471 )

Other, net ( 1,772 ) ( 7,632 ) ( 1,309 )

Total $ 78,272 $ 195,921 $ 309,464

Other ( 397 ) ( 0.2 ) 2,398 0.4 ( 293 ) —

Share-based payment awards 5,595 3.1 2,340 0.4 2,636 0.3

State and Local Income Taxes, Net of Federal Income Tax Effect 1

( 589 ) ( 0.3 ) ( 3,546 ) ( 0.6 ) 4,725 0.5

Foreign Tax Effects

Statutory tax rate differential 2,629 1.4 5,428 1.0 3,732 0.4

Research and development tax credits ( 3,875 ) ( 2.1 ) ( 3,547 ) ( 0.6 ) ( 3,982 ) ( 0.4 )

Other Foreign jurisdictions

Statutory tax rate differential 4,960 2.7 9,127 1.6 2,844 0.3

Changes in valuation allowances

Côte d’Ivoire 13,140 7.2 — — — —

Other Foreign Jurisdictions ( 2,922 ) ( 1.6 ) 2,636 0.5 10,853 1.2

Other ( 5,825 ) ( 3.2 ) ( 532 ) ( 0.2 ) 1,377 0.1

Worldwide Changes in Unrecognized Tax Benefits ( 1,828 ) ( 1.0 ) 1,952 0.3 2,456 0.3

Effective Tax Rate $ 44,552 24.4 % $ 78,272 13.8 % $ 195,921 21.3 %

1 State taxes primarily include Texas and Louisiana.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note H – Income Taxes (Continued)

The following table displays cash taxes paid, net of refunds, for each of the three years presented.

( Thousands of dollars )

2025 2024 2023

State and Local

Alabama $ ( 1,868 ) $ — $ 4,838

Texas 1,500 2,300 1,079

Other 50 — 51

State and Local ( 318 ) 2,300 5,968

Canada 2,929 6,480 3,553

Canada - Alberta 2,809 3,269 1,756

Brunei 681 599 1,079

Total Foreign 6,419 10,348 6,388

Total $ 6,101 $ 12,648 $ 12,356

An analysis of the Company’s deferred tax assets and deferred tax liabilities for the respective periods presented showing the tax effects of significant temporary differences follows.

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Other deferred tax assets 1

97,660 100,352

Total gross deferred tax assets 685,092 727,433

Valuation allowance ( 157,807 ) ( 149,498 )

( 149,498 ) ( 146,861 )

Net deferred tax assets 527,285 577,935

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Other deferred tax liabilities 1

( 87,895 ) ( 97,547 )

Total gross deferred tax liabilities ( 905,622 ) ( 913,725 )

Net deferred tax (liabilities) assets $ ( 378,337 ) $ ( 335,790 )

1 Other deferred tax assets and other deferred tax liabilities are primarily comprised of the deferred tax benefit and obligation associated with operating lease liabilities and the associated right of use assets, respectively.

In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income.

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The Company believes the U.S.

net operating loss being carried forward will more likely than not be utilized in future periods prior to expirations in 2036 and 2037.

net operating loss being carried forward will more likely than not be utilized in future periods prior to expirations in 2037.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note H – Income Taxes (Continued)

Other Information

7 unchanged sentences

A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note H – Income Taxes (Continued)

( Thousands of dollars )

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Additions for tax positions related to prior year — 1,952 2,456

Reductions for tax positions related to prior year ( 882 ) — —

Settlements with taxing authorities ( 946 ) — —

Balance at December 31 $ 8,151 $ 9,979 $ 6,384

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In 2026, the Company currently does not expect to add to the provision for uncertain tax positions.

Although existing liabilities could be reduced by settlement with taxing authorities or due to statute of limitations closing, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2025.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.

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Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.

The Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) and the 2020 Long-Term Incentive Plan (2020 Long-Term Plan).

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note I – Incentive Plans (Continued)

In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan).

All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan.

Additional information on the 2025 Long-Term Plan can be found in the Company’s Definitive Proxy Statement (Definitive 14A) dated March 28, 2025.

The Company currently has outstanding incentive awards issued to certain employees under the Annual Incentive Plan (AIP), the 2020 Long-Term Plan, and the 2025 Long-Term Plan.

The AIP authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees.

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The 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock to employees.

These grants may be in the form of stock options (nonqualified or incentive), SARs, restricted stock, RSUs, performance units, performance shares, dividend equivalents and other stock-based incentives.

The 2020 Long-Term Plan expires in 2030.

A total of 5 million shares are issuable during the life of the 2020 Long-Term Plan.

These grants may be in the form of stock options (nonqualified or incentive), Stock Appreciation Rights (SARs), restricted stock, RSUs, performance units, performance shares, dividend equivalents and other stock-based incentives.

The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term.

Shares issued pursuant to awards granted under this Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market.

1 unchanged sentence

Based on awards made to date, 3.872 million shares are available for grant under the 2025 Long-Term Plan at December 31, 2025.

The Company also has a Stock Plan for Non-Employee Directors (NEDs) that permits the issuance of RSUs and stock options or a combination thereof to the Company’s NEDs.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note I – Incentive Plans (Continued)

The Company also has a stock plan that permits the issuance of RSUs, stock options, or a combination thereof, to non-employee directors (NEDs).

The Company currently has outstanding incentive awards issued to directors under the 2021 Stock Plan for NEDs (2021 NED Plan) and the 2018 Stock Plan for NEDs.

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Related income tax benefit recognized in income 6,438 5,513 9,330

As of December 31, 2024, there were $ 46.9 million in compensation costs, to be expensed over approximately the next three years , related to unvested share-based compensation arrangements granted by the Company.

Employees receive net shares, after applicable withholding obligations, upon each stock option exercise and RSU vest.

As of December 31, 2025, there were $ 46.5 million in compensation costs, to be expensed over approximately the next two years , related to unvested share-based compensation arrangements granted by the Company.

Employees receive net shares, after applicable withholding obligations, upon each RSU vest.

Equity-Settled Awards

PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023 and 2024 under the 2020 Long-Term Plan.

PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2022, 2023, 2024 and February 2025 under the 2020 Long-Term Plan, and in August 2025 under the 2025 Long-Term Plan.

Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period.

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Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year performance measurement period.

The risk-free interest rate is based on the yield curve of three-year U.S.

The risk-free interest

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note I – Incentive Plans (Continued)

rate is based on the yield curve of three-year U.S.

Treasury bonds, and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group.

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Fair value per share at grant date $ 19.65 - $ 22.11

$ 41.95 $ 60.46

Expected volatility 40.00 % 50.00 % 81.00 %

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The fair value of the PSUs based on ROACE was estimated based on the average high/low price of the Company’s stock on the grant date.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note I – Incentive Plans (Continued)

Changes in PSUs outstanding for each of the last three years are presented in the following table.

6 unchanged sentences

Outstanding at end of year 1,463,515 1,392,421 1,818,188

TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s NEDs under the 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan.

TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s non-employee directors under the 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan and 2025 Long-Term Plan.

The fair value of the time-based RSUs awarded for each of the last three years is presented in the following table.

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1 Under the 2021 NED Plan, RSUs granted in 2025 are scheduled to vest in February 2026.

2 The RSUs granted under the 2020 Long-Term Plan generally vest on the third anniversary of the date of grant.

2 The RSUs granted under the 2020 Long-Term Plan and the 2025 Long-Term Plan generally vest on the third anniversary of the date of grant.

Changes in RSUs outstanding for each of the last three years are presented in the following table.

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STOCK OPTIONS – In 2017, the Company ceased the inclusion of stock options and SARs as a part of the long-term incentive compensation mix.

As of December 31, 2023 there were no outstanding stock options.

As of December 31, 2024, there were no outstanding SARs.

Prior to 2017, the Committee fixed the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixed the option term at no more than seven years from such date.

Each option granted to date under the 2012 Long-Term Incentive Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant.

Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years .

For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.

The fair value of each option award was estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table.

Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock.

The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior.

The risk-free interest rate for periods within the expected term of the option is based on the U.S.

Treasury yield curve in effect at the time of grant.

As of December 31, 2024, there were no outstanding SARs or stock options.

During 2023, 11,000 stock options were exercised, and 2,000 stock options were forfeited, both at an exercise price of $ 28.51 per share, leaving zero options outstanding as of December 31, 2023.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Note I – Incentive Plans (Continued)

Changes in stock options outstanding during the last three years are presented in the following table.

Shares Average

Outstanding at December 31, 2021 1,319,500 $ 37.77

( 760,500 ) 23.29

( 546,000 ) 49.65

Outstanding at December 31, 2022 13,000 28.51

Exercised ( 11,000 ) 28.51

Forfeited ( 2,000 ) 28.51

Outstanding at December 31, 2023 — —

Exercisable at December 31, 2021 1,319,500 34.25

Exercisable at December 31, 2022 13,000 28.51

Cash-Settled Awards

The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of SARs and CRSUs.

SAR awards have terms similar to stock options.

The Company has granted phantom stock-based incentive awards to be settled in cash to certain employees in the form of CRSUs.

CRSUs generally settle on the third anniversary of the date of grant.

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Benefits paid ( 45,907 ) ( 45,743 ) ( 16,073 ) ( 16,072 )

Plan amendments 2

Obligation at December 31 659,494 655,324 63,399 54,994

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Fund Status and net plan liability recognized at December 31 $ ( 132,415 ) $ ( 163,204 ) $ ( 63,399 ) $ ( 54,994 )

1 Actuarial gains in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation.

2 At December 31, 2023, the Company recognized an increase to its domestic plan benefit obligation related to a plan amendment.

The amendment provides a permanent increase to benefits for retirees and beneficiaries who commenced payments prior to 2020.

1 Actuarial losses in 2025 for other post retirement benefits primarily relate to trend rate increases for incurred claims.

Actuarial gains for pension benefits in 2024 primarily relate to the increase in the discount rate assumption, which decreases the pension benefit obligation.

At December 31, 2025, amounts included in “Accumulated other comprehensive loss” in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.

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Amortization of prior service cost (credit)

Recognized actuarial loss (gain)

1,967 2,316 620 ( 532 ) ( 532 ) ( 532 )

Net periodic benefit expense 18,923 18,239 9,578 ( 759 ) ( 308 ) 2,032

Recognized actuarial (gain) loss

7,262 9,438 9,776 ( 3,182 ) ( 3,586 ) ( 3,512 )

Net periodic benefit cost (credit)

14,610 18,923 18,239 ( 71 ) ( 759 ) ( 308 )

Other pension costs 276 251 219 — — —

Total net periodic benefit expense $ 19,174 $ 18,458 $ 9,578 $ ( 759 ) $ ( 308 ) $ 2,032

Total net periodic benefit cost (credit)

$ 14,886 $ 19,174 $ 18,458 $ ( 71 ) $ ( 759 ) $ ( 308 )

The preceding tables in this note include the following amounts related to foreign benefit plans.

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Net plan liabilities recognized 397 ( 11,983 ) ( 90 ) ( 106 )

Net periodic benefit expense (benefit) 1,480 1,387 ( 44 ) ( 44 )

Net periodic benefit (credit) expense

2,131 1,480 ( 35 ) ( 44 )

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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During 2026, the Company currently expects to make contributions of $ 23.8 million to its domestic defined benefit pension plans, $ 0.8 million to its foreign defined benefit pension plans and $ 4.7 million to its domestic postretirement benefits plan.

PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan.

PLAN INVESTMENTS – Murphy Oil Corporation maintains an Investment Policy Statement that establishes investment standards related to its funded domestic qualified retirement plan.

Our investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes.

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fixed income 186,995 119,205 67,790 —

International commingled trust fund 7,047 — 7,047 —

Cash and equivalents 19,779 19,779 — —

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For commercial paper securities, the prices received generally utilize observable inputs in the pricing methodologies.

Other alternative strategies funds consist of two investments.

One of these investments is valued annually based on net asset value and permits withdrawals annually after a 90 -day notice, and the other investment is valued quarterly based on net asset values and has a three-year lock-up period and a 95 -day notice following the lock-up period.

The latter of these investments was sold during 2024.

Other alternative strategies funds consist of four investments.

The Company's domestic level 3 investments primarily relate to funds which invest primarily in U.S.

middle-market companies using various types of credit instruments.

For foreign plans, the equity securities funds are comprised of U.K.

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Total at December 31, 2023 $ 24,454

Actual return on plan assets:

Actual return (loss) on plan assets 1 :

Relating to assets held at the reporting date ( 3,574 )

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Relating to assets held at the reporting date 2,394

Relating to assets sold during the period ( 2,865 )

Purchases, sales and settlements

Total at December 31, 2025 $ 48,911

1 Gains and losses on Level 3 plan assets are recognized in the Consolidated Statements of Comprehensive Income (Loss) under the caption "Retirement and postretirement benefit plans.”

401(K) PLANS - Most full-time U.S.

employees of the Company may participate in a 401(k) or similar savings plans by allotting up to a specified percentage of their base pay.

The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6.0 %.

The Company matches contributions at a stated percentage of each employee’s plan, with a maximum match of 6.0 %.

Amounts charged to expense for the Company’s match to these plans were $ 9.1 million in 2025, $ 8.7 million in 2024 and $ 8.5 million in 2023.

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The Company is subject to commodity price risk related to products it produces and sells.

During 2024, the Company entered into natural gas swap contracts that will be effective in 2025.

During 2025 and 2024 the Company entered into natural gas swap contracts.

Under the swap contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.

At December 31, 2024 volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

NYMEX Henry Hub

Volumes MMCF/d

Start Date End Date

Fixed price derivative swap

United States

20 $ 3.20 1/1/2025 1/31/2025

Subsequent to year end, the Company entered into additional natural gas derivative contracts.

Volumes per day and the weighted average prices for these contracts are as follows:

During 2025, the Company entered into natural gas swap contracts that matured by December 31, 2025.

The Company did not have any outstanding natural gas derivative contracts at year end.

Volumes per day and the weighted average prices for these contracts were as follows:

NYMEX Henry Hub

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Note K – Financial Instruments and Risk Management (Continued)

At December 31, 2023 the Company did no t have any outstanding crude oil or natural gas derivative contracts.

During 2024, the Company entered into natural gas swap contracts that were effective in 2025.

At December 31, 2024, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows:

NYMEX Henry Hub

Volumes MMCF/d

Start Date End Date

Fixed price derivative swap United States Natural gas 20 $ 3.20 1/1/2025 1/31/2025

Foreign Currency Exchange Risks

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Type of Derivative Contract

Balance Sheet Location 2024 2023

Balance Sheets Location

Commodity swaps Accounts payable $ — ( 1,707 )

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Year Ended December 31,

Type of Derivative Contract Statement of Operations Locations 2024 2023 2022

Commodity swaps Loss on derivative instruments $ ( 1,707 ) $ — $ ( 160,690 )

Commodity collars Loss on derivative instruments — — ( 159,721 )

Type of Derivative Contract Statements of Operations Locations

2025 2024 2023

Commodity swaps Gain (loss) on derivative instruments $ 5,927 $ ( 1,707 ) $ —

The Company is subject to credit risks primarily associated with trade accounts receivable, cash equivalents and derivative instruments.

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The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal, because counterparties to the majority of transactions are major financial institutions.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note L – Net Income (Loss) Per Common Share

Net income (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for each of the three years presented .

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for each of the three years presented .

The following table reconciles the weighted-average shares outstanding used for these computations.

( Weighted-average shares )

( Weighted-average shares, except per share amounts )

2025 2024 2023

Basic method 143,124,118 150,011,458 155,233,560

Dilutive stock options and restricted stock units 1,015,894 1,412,869 2,198,305

Dilutive restricted stock units 901,204 1,015,894 1,412,869

Diluted method 144,025,322 151,027,352 156,646,429

The following table reflects certain options to purchase shares of common stock that were outstanding during each of the three years presented but were not included in the computation of diluted earnings per share because the incremental shares from the assumed conversion were antidilutive.

2024 2023 2022

Antidilutive stock options excluded from diluted shares — — 126,000

Weighted average price of these options — — $ 49.65

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

NET INCOME (LOSS) PER COMMON SHARE – BASIC

Continuing operations $ 0.73 $ 2.73 $ 4.27

Discontinued operations — ( 0.02 ) ( 0.01 )

Net income $ 0.73 $ 2.71 $ 4.26

NET INCOME (LOSS) PER COMMON SHARE – DILUTED

Continuing operations $ 0.72 $ 2.72 $ 4.23

Discontinued operations — ( 0.02 ) ( 0.01 )

Net income $ 0.72 $ 2.70 $ 4.22

Note M – Other Financial Information

Gain from Foreign Currency Transactions

Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $ 45.4 million gain in 2024, $ 10.8 million loss in 2023 and $ 23.0 million gain in 2022.

Supplemental Information to Statement of Cash Flows

Gain (Loss) from Foreign Currency Transactions

Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $ 29.4 million loss in 2025, $ 45.4 million gain in 2024 and $ 10.8 million loss in 2023.

Supplemental Information to Statements of Cash Flows

( Thousands of dollars )

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Increase (decrease) in accounts payable and accrued liabilities 1

3,101 3,287 ( 140,011 )

Increase (decrease) in income taxes payable ( 794 ) ( 2,004 ) ( 5,537 )

Net decrease (increase) in non-cash operating working capital $ 74,883 $ ( 99,361 ) $ ( 65,728 )

Net (increase) decrease in noncash working capital $ ( 74,052 ) $ 74,883 $ ( 99,361 )

Supplementary disclosures:

Cash income taxes paid, net of refunds $ 12,648 $ 12,356 $ 24,853

Interest paid, net of amounts capitalized of $ 8.8 million in 2025, $ 11.4 million in 2024 and $ 14.5 million in 2023

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1 Excludes receivable/payable balances relating to mark-to-market of derivative instruments.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note N – Accumulated Other Comprehensive Loss

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Related income taxes of $ 0.7 million and $ 1.4 million are included in income tax expense in 2025 and 2024, respectively.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – Assets and Liabilities Measured at Fair Value

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The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.

As of December 31, 2025, there were no outstanding commodity (NYMEX Henry Hub natural gas) swaps subject to fair value measurement.

The liabilities associated with these contacts have been finalized as of December 31, 2025 and were based on realized NYMEX Henry Hub pricing.

The commodity swaps liability as of December 31, 2024 was $ 1.7 million and recorded as “ Accounts payable ” in the Consolidated Balance Sheets.

The fair value of the commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas.

The before tax income effect of changes in fair value of natural gas derivative contracts is recorded in “(Loss) Gain on derivative instruments” in the Consolidated Statements of Operations.

The Company acquired Gulf of America assets from LLOG Exploration Offshore L.L.C.

and LLOG Bluewater Holdings, L.L.C.

(collectively, LLOG) and, in a separate agreement, from Petrobras America Inc.

(PAI) in 2019 and 2018, respectively.

Under the terms of both transactions, contingent consideration was paid after meeting specified revenue thresholds and project milestones and recorded to “Contingent consideration payment” in the Consolidated Statements of Cash Flows.

As at December 31, 2022, the Company’s liabilities with PAI and LLOG were based on realized inputs of volumes and pricing as a result of contractual thresholds and time durations being achieved.

As a result, the related liability as at December 31, 2022, of $ 192.7 million, was no longer subject to fair value measurement.

The liability was included in “Other accrued liabilities” in the Consolidated Balance Sheets and the changes in fair value of the contingent consideration during 2022 were recorded in “Other income (loss)” in the Consolidated Statements of Operations.

The fair value of

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – Assets and Liabilities Measured at Fair Value (Continued)

the commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas.

The before tax income effect of changes in fair value of natural gas derivative contracts was recorded in “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations.

The Company was previously exposed to contingent consideration payments related to a prior asset purchase agreement, which required additional payments contingent on specified revenue thresholds and project milestones being met.

At December 31, 2022, the Company’s liabilities were finalized and no longer subject to fair value measurement.

Final cash payment was made in 2023 and was recorded to “Contingent consideration payment“ in the Consolidated Statements of Cash Flows.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.

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The Company has off-balance sheet exposures relating to certain letters of credit.

The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – Assets and Liabilities Measured at Fair Value (Continued)

The fair value of these, which represents fees associated with obtaining the instruments, was minimal.

( Thousands of dollars )

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Fair Values – Nonrecurring

Impairment expenses of $ 62.9 million were incurred in 2024.

In the first quarter of 2024, an impairment charge of $ 34.5 million was triggered for the Calliope field, and in the fourth quarter of 2024, an impairment charge of $ 28.4 million was triggered for the Nearly Headless Nick field.

Both of the impairments were due to operational issues that led to reserve reductions.

There were no impairment expenses incurred in 2023.

Impairment expenses of $ 115.0 million and $ 62.9 million were incurred in 2025 and 2024, respectively.

In 2025, an impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) was recorded for the Dalmatian field, in the Gulf of America, as certain projects in the field were less competitive for capital allocation.

In 2024, an impairment charge of $ 34.5 million was recorded for the Calliope field and an impairment charge of $ 28.4 million was recorded for the Nearly Headless Nick field, in the Gulf of America.

Both impairment charges were due to operational issues that led to reserve reductions.

The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.

The fair value information associated with the impaired properties is presented in the following table:

The fair value information associated with the impaired properties is presented in the following tables.

Year Ended December 31, 2025

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$ — $ — $ 42,397 $ 157,399 $ 115,002

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – Assets and Liabilities Measured at Fair Value (Continued)

Year Ended December 31, 2024

Impairment Total

( Thousands of dollars )

Level 1 Level 2 Level 3

Impaired proved properties

United States - Offshore

$ — $ — $ 501 $ 63,410 $ 62,909

Note P – Commitments

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Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement.

Total costs incurred under these service arrangements were $ 225.9 million in 2024, $ 295.1 million in 2023 and $ 216.4 million in 2022.

Commitments for capital expenditures were approximately $ 417.0 million at December 31, 2024, including $ 53.6 million for the Gulf of America, $ 112.2 million for Eagle Ford Shale, $ 31.2 million for Canada and $ 220.0 million for Other Offshore, mainly for capital projects in Vietnam.

Commitments for operating agreements include approximately $ 178.0 million at December 31, 2024 for Other Offshore for the purpose of supporting future development activities in Vietnam.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Commitments for Vietnam in Other Offshore include future operating agreements for production activities.

Annual payments for the next five years are $ 23.6 million in 2026, $ 23.1 million in 2027, $ 24.0 million in 2028, $ 23.9 million in 2029 and $ 24.2 million in 2030.

Commitments for capital expenditures were approximately $ 551.2 million at December 31, 2025, primarily consisting of $ 245.3 million for the Gulf of America, $ 82.6 million for the Eagle Ford Shale, $ 49.8 million for Canada, $ 127.5 million for Vietnam, and $ 45.0 million in for Côte d’Ivoire.

Note Q – Environmental and Other Contingencies

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tax legislation changes, including tax rate changes, and retroactive tax claims;

trade policies, tariffs and other trade restrictions;

royalty and revenue sharing increases;

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and the causes and impacts of climate change.

These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased.

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.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note Q – Environmental and Other Contingencies (Continued)

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.

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In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold.

Pursuant to recent SEC amendments to this item, the Company will be using a threshold of $ 1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $ 1.0 million threshold.

There continues to be an increase in regulatory oversight of the oil and gas industry at the federal level, with a focus on climate change and GHG emissions (including methane emissions).

For example, in March 2024, the U.S.

EPA published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the U.S.

In November 2024, the U.S.

EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector.

The charge, referred to as the WEC, is a component of the Biden Administration’s Methane Emissions Reduction Program to limit methane emissions from the oil and gas industry under the 2022 IRA.

Executive orders have also been issued related to oil and gas activities on federal lands, infrastructure and environmental justice.

Pursuant to SEC amendments to this item, the Company will be using a threshold of $ 1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $ 1.0 million threshold.

In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions).

For example, in March 2024, the EPA published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA.

However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules.

In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector.

This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034.

In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France.

Although the U.S.

officially withdrew from the Paris Agreement on November 4, 2020, the U.S.

rejoined the Paris Agreement, which became effective for the U.S.

on February 19, 2021.

In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement again.

Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026.

In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement.

Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026.

In September 2025, the EPA announced a proposal to end the GHGRP for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal).

Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal.

On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change.

On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution.

The repeal calls into question the EPA’s authority to regulate GHGs, as well as the EPA’s prior scientific assessment of climate change risks.

Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact the EPA’s regulation of GHG emissions going forward.

While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time.

Further, many states have adopted or are considering regulations related to GHG emissions.

The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled.

Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note Q - Environmental and Other Contingencies (Continued)

have been taken for disposal.

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.

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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.

Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note Q - Environmental and Other Contingencies (Continued)

litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites.

8 unchanged sentences

Stock options exercised 1

— 2,657 181,655

Restricted stock awards 1

8 unchanged sentences

As of December 31, 2025, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program.

Subsequent to year end, as of February 25, 2025, the Company repurchased 3.4 million shares of its common stock in open-market transactions for $ 95.1 million, excluding taxes and fees.

As of this date, the Company had $ 555.0 million of its common stock remaining available to repurchase under the program.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note R - Common Stock Issued and Outstanding (Continued)

The share repurchase program is a component of the Company’s capital allocation framework, the details of which can be found as part of the Company’s Form 8-K filed on August 4, 2022 and Form 8-K filed on August 8, 2024.

1 unchanged sentence

Murphy’s reportable segments are organized into geographic areas of operations.

The Company’s exploration and production activity is subdivided into segments for the U.S., Canada and all other countries.

The Company’s E&P activity is subdivided into segments for the U.S., Canada and all other countries.

Each of these segments derive revenues primarily from the sale of crude oil, NGLs and/or natural gas.

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The CODM also considers budget-to-actual variances on a monthly basis for the performance measure when making decisions about allocating capital and personnel to the segments.

For the income statement periods presented in these financial statements, Murphy’s former CEO, Roger Jenkins, acted as the CODM.

As of January 1, 2025, Murphy appointed a new CEO, Eric Hambly.

Murphy’s President and Chief Executive Officer, Eric M.

Hambly, acts as the CODM.

Customers that accounted for 10% or more of the Company’s sales revenue for each of the below three years ended December 31, are shown below.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note S – Business Segments (Continued)

2025 2024 2023

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No assets were held for sale as of December 31, 2025 and 2024.

The former U.K., Malaysia and U.S.

refining and marketing units have been reported as discontinued operations for all periods presented in these consolidated financial statements.

The Company has accounted for its former U.K., Malaysia and U.S.

refining and marketing operations as discontinued operations for all periods presented.

Information about business segments and geographic operations is reported in the following tables.

For geographic purposes, revenues are attributed to the country in which the sale occurs.

Corporate and other activities, including interest income, other gains and losses (including foreign exchange gains/losses and realized/unrealized gains/losses on crude oil and natural gas contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals.

“Other segment costs” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM, or are reported to the CODM but are not considered to be significant segment expenses.

“Other segment costs” for the years presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment.

Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals.

“Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses.

“Other segment costs (income)” for the years presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Canada Other Total

E&P Corporate,

Other, and Discontinued Operations

E&P Corporate, and Discontinued Operations

Year ended December 31, 2025

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$ 2,153.9 $ 530.2 $ 5.7 $ 2,689.8 $ — $ 2,689.8

Sales of purchased natural gas

— 3.7 — 3.7 — 3.7

Gain on sales of assets and other operating income

5.9 1.7 10.0 17.6 13.8 31.4

Revenues from external customers 2,508.3 509.7 6.6 3,024.6 3.9 3,028.5

Total revenues and other income

2,159.8 531.9 15.7 2,707.4 13.8 2,721.2

Lease operating expenses

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Transportation, gathering and processing 107.0 92.7 — 199.7 — 199.7

Costs of purchased natural gas

— 3.1 — 3.1 — 3.1

Selling and general expenses 13.7 23.7 8.8 46.2 91.1 137.3

9 unchanged sentences

Accretion of asset retirement obligations 46.6 10.3 0.7 57.6 0.1 57.7

Other operating expenses

Other operating expenses (income)

10.8 1.8 ( 0.9 ) 11.7 2.2 13.9

Interest income

( 1.7 ) — — ( 1.7 ) ( 11.8 ) ( 13.5 )

Interest expense, net of capitalization

Income tax expense

Current income tax expense

0.1 0.1 0.2 0.4 95.7 96.1

Deferred income tax expense

Income tax expense (benefit)

Current income tax expense (benefit)

0.8 10.6 0.3 11.7 ( 1.8 ) 9.9

Total income tax expense

Deferred income tax expense (benefit)

76.9 4.0 ( 2.4 ) 78.5 ( 43.8 ) 34.7

Other segment costs (income)

Total income tax expense (benefit)

77.7 14.6 ( 2.1 ) 90.2 ( 45.6 ) 44.6

Other segment costs

4.2 1.6 0.3 6.1 31.6 37.7

Segment income (loss) - including NCI 1

2 unchanged sentences

Total assets at year-end 6,771.3 2,000.0 598.1 9,369.4 463.2 9,832.6

1 Includes results attributable to a noncontrolling interest in MP GOM.

1 Includes results attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

4 unchanged sentences

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

E&P Corporate, and Discontinued Operations

Year ended December 31, 2024

5 unchanged sentences

4.5 1.5 — 6.0 3.9 9.9

Revenues from external customers 2,928.3 517.5 11.0 3,456.8 3.3 3,460.1

Total revenues and other income

2,508.3 509.7 6.6 3,024.6 3.9 3,028.5

Lease operating expenses

19 unchanged sentences

Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 8.9 865.8

Impairment of assets 62.9 — — 62.9 — 62.9

Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 0.1 52.5

Other operating expenses

Other miscellaneous operating expenses

20.1 15.5 8.1 43.7 ( 4.4 ) 39.3

Loss on contingent consideration

7.1 — — 7.1 — 7.1

Total other operating expenses

Other operating expenses (income)

9.3 2.8 2.1 14.2 ( 3.2 ) 11.0

Interest income

( 22.0 ) — — ( 22.0 ) ( 12.2 ) ( 34.2 )

Interest expense, net of capitalization

0.2 0.4 0.2 0.8 105.1 105.9

Income tax expense

Current income tax expense

Income tax expense (benefit)

Current income tax expense (benefit)

1.5 3.2 0.2 4.9 0.9 5.8

Deferred income tax expense

Deferred income tax expense (benefit)

123.8 8.8 ( 31.2 ) 101.4 ( 28.9 ) 72.5

Total income tax expense

Total income tax expense (benefit)

125.3 12.0 ( 31.0 ) 106.3 ( 28.0 ) 78.3

5 unchanged sentences

Total assets at year-end 6,953.8 1,919.8 302.0 9,175.6 491.9 9,667.5

1 Includes results attributable to a noncontrolling interest in MP GOM.

1 Includes results attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

4 unchanged sentences

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

E&P Corporate, and Discontinued Operations

Year ended December 31, 2023

3 unchanged sentences

— 72.2 — 72.2 — 72.2

Gain on sales of assets and other operating income (loss)

Gain on sales of assets and other operating income

6.5 1.5 — 8.0 3.3 11.3

Revenues from external customers 3,461.2 762.9 23.0 4,247.1 ( 314.4 ) 3,932.7

Total revenues and other income

2,928.3 517.5 11.0 3,456.8 3.3 3,460.1

Lease operating expenses

20 unchanged sentences

Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 0.1 46.1

Other operating expenses

Other miscellaneous operating expenses

41.3 10.5 2.4 54.2 5.0 59.2

Loss on contingent consideration

78.3 — — 78.3 — 78.3

Total other operating expenses

Other operating expenses (income)

27.2 15.5 8.1 50.8 ( 4.4 ) 46.4

Interest income

( 3.3 ) — — ( 3.3 ) ( 9.3 ) ( 12.6 )

Interest expense, net of capitalization

0.1 0.2 0.2 0.5 111.9 112.4

Income tax expense

Current income tax expense

Income tax expense (benefit)

Current income tax expense (benefit)

3.1 3.7 0.6 7.4 8.8 16.2

Deferred income tax expense

Deferred income tax expense (benefit)

229.6 7.5 ( 6.7 ) 230.4 ( 50.6 ) 179.8

Total income tax expense

Total income tax expense (benefit)

232.7 11.2 ( 6.1 ) 237.8 ( 41.8 ) 196.0

Other segment costs (income)

Other segment costs

7.2 1.1 0.6 8.9 12.1 21.0

3 unchanged sentences

Total assets at year-end 7,107.0 2,080.0 213.3 9,400.2 366.5 9,766.7

1 Includes results attributable to a noncontrolling interest in MP GOM.

1 Includes results attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

15 unchanged sentences

Purchase options also exist for certain leases.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note T – Leases (Continued)

Related Expenses

Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:

Expenses related to finance and operating leases (both short-term and long-term) included in the Consolidated Financial Statements are as follows.

Year Ended December 31,

(Thousands of dollars) Financial Statement Category 2024 2023

(Thousands of dollars) Financial Statements Category 2025 2024

Operating lease 1, 2

18 unchanged sentences

1 Variable lease expenses.

For the years ended December 31, 2024 and 2023, includes variable lease expenses of $ 42.3 million and $ 36.7 million, respectively, primarily related to additional volumes processed at a natural gas processing plant.

For the years ended December 31, 2025 and 2024, included variable lease expenses of $ 34.6 million and $ 42.3 million, respectively, primarily related to operating costs at a natural gas processing plant in our Canada Onshore business.

2 Short-term leases due within 12 months.

For the year ended December 31, 2024, includes $ 236.4 million in lease operating expenses, $ 13.0 million for “Transportation, gathering and processing”, $ 38.5 million for “Exploration expenses, including undeveloped lease amortization”, $ 0.8 million in “Selling and general expenses”, $ 6.2 million in “Other operating expense”, $ 97.1 million in “Property, plant and equipment, net” and nil in “Asset retirement obligations” relating to short-term leases due within 12 months.

Expenses primarily relate to drilling rigs and other oil and natural gas field equipment.

For the year ended December 31, 2023, includes $ 78.2 million in lease operating expenses, $ 29.4 million in “Transportation, gathering and processing”, $ 80.3 million for “Exploration expenses, including undeveloped lease amortization”, $ 1.6 million in “Selling and general expenses", $ 0.3 million in “Other operating expense”, $ 112.7 million in “Property, plant and equipment, net” and $ 57.4 million in “Asset retirement obligations” relating to short-term leases due within 12 months.

Expenses primarily relate to drilling rigs and other oil and natural gas field equipment.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note T – Leases (Continued)

The table below shows amounts included in the Consolidated Financial Statements related to short-term leases due within 12 months.

These expenses primarily related to drilling rigs and other oil and natural gas field equipment.

(Thousands of dollars) Year Ended December 31,

Financial Statements Category

Lease operating expenses

$ 159,746 $ 236,402

Transportation, gathering and processing 8,308 12,993

Selling and general expenses 1,918 772

Other operating expense 16 6,230

Exploration expenses 13,211 38,500

Property, plant and equipment 96,909 97,104

Asset retirement obligations 65,418 10

Total short-term lease expense

$ 345,526 $ 392,011

Maturity of Lease Liabilities

11 unchanged sentences

1 Includes both the current and long-term portion of the lease liabilities.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note T – Leases (Continued)

Lease Term and Discount Rate

15 unchanged sentences

Operating leases ¹ $ 247,566 $ 349,312

1 For the year ended December 31, 2024, right-of-use assets obtained in exchange for lease liabilities primarily includes $ 254.1 million related to the extension of an operating lease pertaining to a drill ship used in our U.S.

Offshore business and $ 52.7 million pertaining to two drilling rigs and several natural gas compressor units at our U.S.

Finance leases 2

1 For the year ended December 31, 2025, right-of-use assets, obtained in exchange for operating lease liabilities, primarily included $ 153.7 million for a drill ship operating lease extension used in our U.S.

Offshore business and $ 72.2 million for a drilling rig and two support vessels in our Vietnam business.

December 31, 2024 included $ 254.1 million for a drill ship operating lease extension in our U.S.

Offshore business and $ 52.7 million related to two drilling rigs and several natural gas compressors in our U.S.

Onshore business.

December 31, 2023 includes $ 4.5 million related to natural gas compressor units at various U.S.

Onshore locations.

2 For the year ended December 31, 2025, right-of-use assets obtained in exchange for finance lease liabilities primarily included $ 8.8 million related to computing equipment in the U.S.

Note U – Subsequent Event

On January 28, 2026, the Board of Directors of Murphy Oil Corporation (NYSE:

MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $ 0.325 per share, or $ 1.30 per share on an annualized basis.

MUR) declared a quarterly cash dividend on the Common Stock of Murphy Oil Corporation of $ 0.35 per share, which on an annualized basis would be $ 1.40 per share.

The dividend is payable on March 2, 2026, to stockholders of record as of February 17, 2026.

In January 2026, the Company completed a series of transactions regarding its long-term debt arrangements and RCF.

In particular, the Company closed a public offering of $ 500.0 million aggregate principal amount of its 2034 Notes, used the proceeds to redeem an aggregate $ 227.5 million of its outstanding 2027 Notes and 2028 Notes, repaid $ 100.0 million that was outstanding on the previous RCF, as of December 31, 2025, and expects to use the remaining proceeds to cover transaction-related fees and expenses and for general corporate purposes.

In addition, the Company entered into an amendment to its credit agreement which increased its RCF capacity from $ 1.35 billion to $ 2.0 billion and extended the term of the agreement to 2031.

See Note F for additional information on these transactions.

Subsequent to the balance sheet date, the Company announced oil discoveries at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America and dry holes at the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire.

A portion of the Civette-1X dry hole charge was recorded in 2025.

The remainder of Civette-1X and all charges related to the Caracal-1X well will be recorded in the first quarter of 2026.

See Note D for additional information .

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

6 unchanged sentences

SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES

Reserves of crude oil, natural gas and NGLs are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year.

Reserves of oil and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year.

Many assumptions and judgments are required to estimate reserves.

Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year.

The average prices used for 2024 were $ 75.48 per BBL for NYMEX crude oil (WTI) and $ 2.13 per MCF for natural gas (Henry Hub).

The average prices used for 2023 were $ 78.22 per BBL for NYMEX crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub).

The average prices used for 2022 were $ 93.67 per BBL for NYMEX crude oil (WTI) and $ 6.36 per MCF for natural gas (Henry Hub).

The average prices used for 2025 were $ 65.34 per BBL for crude oil (WTI) and $ 3.39 per MCF for natural gas (Henry Hub).

The average prices used for 2024 were $ 75.48 per BBL for crude oil (WTI) and $ 2.13 per MCF for natural gas (Henry Hub).

The average prices used for 2023 were $ 78.22 per BBL for crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub).

Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs) and commercially available technologies to establish “reasonable certainty” of economic producibility.

Estimates are presented in millions of barrels of oil equivalents and dollars and billions of cubic feet with one decimal;

totals within the tables may not add as a result of rounding.

Estimates are presented in millions of barrels of oil equivalents and dollars and billions of cubic feet rounded to one decimal.

As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered.

8 unchanged sentences

These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of NGLs.

All crude oil, natural gas and NGL reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures.

All oil and natural gas reserves are from consolidated subsidiaries (including NCI) and proportionately consolidated joint ventures.

The Company has no proved reserves attributable to investees accounted for by the equity method.

18 unchanged sentences

Extensions and discoveries 112.6 12.7 87.3 12.6

Purchases of properties 5.0 5.0 — —

Sale of properties ( 5.2 ) — ( 5.2 ) —

4 unchanged sentences

Extensions and discoveries 31.4 16.0 15.4 —

Sale of properties ( 5.2 ) — ( 5.2 ) —

Production ( 67.5 ) ( 39.1 ) ( 28.3 ) ( 0.1 )

1 unchanged sentence

Revisions of previous estimates 26.0 18.0 7.1 0.9

Improved recovery 11.3 11.3 — —

Extensions and discoveries 43.0 4.9 38.1 —

Purchases of properties 4.3 4.3 — —

Sale of properties ( 3.4 ) ( 3.4 ) — —

Production ( 68.9 ) ( 39.3 ) ( 29.5 ) ( 0.1 )

12 unchanged sentences

2 Total and United States includes proved developed reserves of 13.1 MMBOE, consisting of 12.1 MMBBL of oil, 0.4 MMBBL of NGLs and 3.9 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 1.5 MMBOE, consisting of 1.3 MMBBL of oil, 0.1 MMBBL of NGLs and 0.8 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

4 Totals within the tables may not add as a result of rounding.

3 Total and United States includes proved undeveloped reserves of 1.9 MMBOE, consisting of 1.8 MMBBL of oil and 0.3 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

2 unchanged sentences

2025 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney.

Revisions of previous estimates - The equivalent reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices and higher gas prices that increased royalty rates and accelerated royalty incentive payouts in the Tupper Montney.

Extensions and discoveries - In 2025, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

Purchases and sales of properties - In 2025, the Company acquired incremental working interest in various properties in the Eagle Ford Shale and divested a minor area of the Eagle Ford Shale in separate transactions.

2024 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.

Improved Recovery – Proved equivalent reserves were added in 2024 for the non-operated St.

Malo waterflood in the Gulf of America.

Extensions and discoveries - In 2024, proved equivalent reserves were added for drilling activities predominantly in Tupper Montney, the Eagle Ford Shale, and projects in the Gulf of America.

Extensions and discoveries - In 2024, proved equivalent reserves were added for drilling activities predominantly in the Tupper Montney, the Eagle Ford Shale, and projects in the Gulf of America.

2023 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S.

and performance adjustments in Tupper Montney and the Eagle Ford Shale.

These negative revisions were partially offset by positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney.

Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in Tupper Montney, the Eagle Ford Shale, and Vietnam.

and performance adjustments in the Tupper Montney and the Eagle Ford Shale.

These negative revisions were partially offset by positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.

Extensions and discoveries - In 2023, proved equivalent reserves were added for drilling and expansion activities predominantly in the Tupper Montney, the Eagle Ford Shale, and Vietnam.

Purchases and sales of properties - In 2023, the Company divested a portion of its working interest, in the Kaybob Duvernay and all of its non-operated Placid Montney assets.

2022 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney.

These negative revisions were partially offset by positive well performance in the Gulf of America.

Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Tupper Montney and Kaybob Duvernay, as well as the Gulf of America and Eagle Ford Shale.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America, and divested certain working interests in the Gulf of America and Eagle Ford Shale.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

8 unchanged sentences

Extensions and discoveries 22.5 8.9 1.5 12.1

Purchases of properties 4.2 4.2 — —

Sale of properties

5 unchanged sentences

Extensions and discoveries 16.6 10.7 5.9 –

Sale of properties

( 2.0 ) — ( 2.0 ) —

Production ( 34.6 ) ( 30.8 ) ( 3.7 ) ( 0.1 )

1 unchanged sentence

Revisions of previous estimates 20.2 18.2 1.8 0.2

Improved recovery 10.7 10.7 — —

Extensions and discoveries 5.7 3.4 2.3 —

Purchases of properties 3.5 3.5 – –

Sales of properties ( 1.8 ) ( 1.8 ) — –

Production ( 34.0 ) ( 30.3 ) ( 3.6 ) ( 0.1 )

13 unchanged sentences

3 Total and United States includes proved undeveloped reserves of 1.8 MMBBL attributable to the noncontrolling interest in MP GOM.

4 Totals within the tables may not add as a result of rounding.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

2 unchanged sentences

2025 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The crude oil reserves revisions in 2024 resulted predominantly from performance adjustments in the Eagle Ford Shale and Gulf of America.

Revisions of previous estimates - The crude oil reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, revisions in the Gulf of America for additional field life at the Chinook #8 location, in the Cascade and Chinook fields, due to the Pioneer FPSO purchase, partially offset by the effects of lower oil prices.

Extensions and discoveries - In 2025, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and in the Kaybob Duvernay in Canada.

2024 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The crude oil reserves revisions in 2024 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America.

Improved Recovery – Proved oil reserves were added in 2024 for the non-operated St.

Malo waterflood in the Gulf of America.

Extensions and discoveries - In 2024, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and Gulf of America.

Extensions and discoveries - In 2024, proved oil reserves were added for drilling activities predominantly in the Eagle Ford Shale and the Gulf of America.

2023 Comments for Proved Crude Oil Reserves Changes

3 unchanged sentences

Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.

2022 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The positive crude oil reserves revisions in 2022 resulted predominantly from improved well performance in the Gulf of America and impacts of higher commodity prices in the U.S.

Extensions and discoveries - In 2022, proved oil reserves were added for drilling and expansion activities predominantly in the Gulf of America and the Eagle Ford Shale.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

6 unchanged sentences

Revisions of previous estimates ( 1.4 ) ( 1.2 ) ( 0.2 ) —

Improved recovery 0.2 0.2 — —

Extensions and discoveries 2.0 1.7 0.3 —

Purchase of properties 0.3 0.3 — —

Sale of properties

3 unchanged sentences

Revisions of previous estimates 1.2 0.3 0.9 —

Improved recovery 0.4 0.4 — —

Extensions and discoveries 2.9 2.4 0.5 —

Sale of properties

( 0.6 ) — ( 0.6 ) —

Production ( 3.5 ) ( 3.3 ) ( 0.2 ) —

1 unchanged sentence

Revisions of previous estimates 1.4 1.2 0.2 —

Improved recovery 0.4 0.4 — —

Extensions and discoveries 1.1 0.7 0.4 —

Purchases of properties 0.4 0.4 – —

Sale of properties

( 0.8 ) ( 0.8 ) — —

Production ( 4.0 ) ( 3.8 ) ( 0.2 ) —

12 unchanged sentences

2 Total and United States includes proved developed reserves of 0.4 MMBBL attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 0.1 MMBBL attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

2 unchanged sentences

2025 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates - The NGL reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney.

Revisions of previous estimates - The NGL reserves revisions in 2025 resulted predominantly from performance adjustments in the Eagle Ford Shale and the Gulf of America, partially offset by lower commodity prices in the United States.

Extensions and discoveries - In 2025, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2024 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates - The NGL reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.

Improved Recovery – Proved NGL reserves were added in 2024 for the non-operated St.

Malo waterflood in the Gulf of America.

Extensions and discoveries - In 2024, proved NGL reserves were added for drilling activities predominantly in Tupper Montney and Eagle Ford Shale.

Extensions and discoveries - In 2024, proved NGL reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2023 Comments for Proved Natural Gas Liquids Reserves Changes

4 unchanged sentences

Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.

2022 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates - The positive NGL reserves revisions in 2022 resulted predominantly from improved well performance in the Gulf of America, Eagle Ford Shale, and Kaybob Duvernay.

Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the Gulf of America and Eagle Ford Shale, as well as in Tupper Montney and Kaybob Duvernay.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

6 unchanged sentences

Revisions of previous estimates ( 6.9 ) ( 19.0 ) 12.1 —

Improved recovery 2.6 2.6 — —

Extensions and discoveries 528.9 12.3 513.8 2.8

Purchases of properties 2.9 2.9 — —

Sale of properties

3 unchanged sentences

Revisions of previous estimates 39.1 7.7 31.4 —

Improved recovery 1.2 1.2 – —

Extensions and discoveries 71.4 17.0 54.4 —

Sale of properties ( 15.6 ) — ( 15.6 ) —

Production ( 176.1 ) ( 30.1 ) ( 146.0 ) —

1 unchanged sentence

Revisions of previous estimates 26.7 ( 8.7 ) 30.8 4.6

Improved recovery 1.2 1.2 — —

Extensions and discoveries 217.2 4.7 212.5 —

Purchases of properties 2.4 2.4 — —

Sale of properties

( 5.1 ) ( 5.1 ) — —

Production ( 185.3 ) ( 31.0 ) ( 154.3 ) —

12 unchanged sentences

December 31, 2025 4

1,202.6 84.8 1,110.4 7.4

1 Total and United States includes total proved reserves of 4.2 BCF attributable to the noncontrolling interest in MP GOM.

2 Includes proved natural gas reserves to be consumed in operations as fuel of 54.2 BCF, 35.1 BCF and 7.4 BCF for the U.S., Canada and Other, respectively, with 1.7 BCF attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved developed reserves of 3.9 BCF attributable to the noncontrolling interest in MP GOM.

4 Total and United States includes proved undeveloped reserves of 0.3 BCF attributable to the noncontrolling interest in MP GOM.

4 Includes proved natural gas reserves to be consumed in operations as fuel of 67.9 BCF, 36.0 BCF and 2.8 BCF for the U.S., Canada and Other, respectively, with 1.1 BCF attributable to the noncontrolling interest in MP GOM.

5 Totals within the tables may not add as a result of rounding.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

2 unchanged sentences

2025 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The natural gas reserves revisions in 2024 resulted predominantly from performance adjustments in Tupper Montney and Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney.

Revisions of previous estimates - The natural gas reserves revisions in 2025 resulted predominantly from performance adjustments in the Tupper Montney, partially offset by negative revisions due to increased royalty rates and accelerated royalty incentive payouts resulting from higher commodity prices in the Tupper Montney and the effects of reduced oil price in the Eagle Ford Shale.

Extensions and discoveries - In 2025, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2024 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The natural gas reserves revisions in 2024 resulted predominantly from performance adjustments in the Tupper Montney and the Eagle Ford Shale, and positive revisions due to reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in the Tupper Montney.

Improved Recovery – Proved natural gas reserves were added in 2024 for the non-operated St.

Malo waterflood in the Gulf of America.

Extensions and discoveries - In 2024, proved natural gas reserves were added for drilling activities predominantly in Tupper Montney and Eagle Ford Shale.

Extensions and discoveries - In 2024, proved natural gas reserves were added for drilling activities predominantly in the Tupper Montney and the Eagle Ford Shale.

2023 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The negative natural gas reserves revisions in 2023 resulted predominantly from lower commodity prices in the U.S.

and performance adjustments in Tupper Montney and Eagle Ford Shale.

These negative revisions were partially offset by positive revisions in the Gulf of America, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Tupper Montney.

Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in Tupper Montney.

and performance adjustments in the Tupper Montney and the Eagle Ford Shale.

Extensions and discoveries - In 2023, proved natural gas reserves were added for drilling and expansion activities predominantly in the Tupper Montney.

Purchases and sales of properties - In 2023, the Company divested a portion of its working interest in the Kaybob Duvernay and all of its non-operated Placid Montney assets.

2022 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The negative natural gas reserves revisions in 2022 resulted predominantly from increased royalty rates and accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney.

Extensions and discoveries - In 2022, proved natural gas reserves were added for drilling and expansion activities predominantly in Tupper Montney, as well as in the Gulf of America and Eagle Ford Shale.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the Gulf of America and divested certain working interests in the Gulf of America and Eagle Ford Shale.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

15 unchanged sentences

Total charged to expense 1

33.4 0.3 66.3 100.0

Property additions $ 763.5 $ 152.5 $ 180.9 $ 1,096.9

11 unchanged sentences

Total charged to expense 1

90.1 0.4 33.5 124.0

Property additions $ 601.7 $ 137.9 $ 71.8 $ 811.4

11 unchanged sentences

Total charged to expense 1

166.5 0.4 57.0 223.9

Property additions $ 671.3 $ 206.2 $ 13.1 $ 890.6

1 Excludes undeveloped lease amortization for the years ended 2025, 2024 and 2023 of $ 11.7 million, $ 9.6 million and $ 10.9 million, respectively.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

6 unchanged sentences

Natural gas sales 106.5 275.8 — 382.3

Sales of purchased natural gas — 3.7 — 3.7

Total oil and natural gas revenues 2,153.9 530.2 5.7 2,689.8

5 unchanged sentences

Transportation, gathering and processing 107.0 92.7 — 199.7

Costs of purchased natural gas — 3.1 — 3.1

Exploration costs charged to expense 33.5 0.3 66.2 100.0

13 unchanged sentences

Sales of purchased natural gas — 3.7 — 3.7

— 72.2 — 72.2

Total oil and natural gas revenues 2,503.8 508.2 6.6 3,018.6

10 unchanged sentences

Accretion of asset retirement obligations 43.1 8.6 0.7 52.4

Impairment of assets 62.9 — — 62.9

Selling and general expenses ( 3.3 ) 20.4 6.7 23.8

Other expenses 31.2 16.8 8.9 56.9

Other expenses (benefits) ( 5.6 ) 3.3 2.6 0.3

Total costs and expenses 1,821.1 448.7 50.1 2,319.9

3 unchanged sentences

1 Results exclude corporate overhead, interest and discontinued operations.

Results include noncontrolling interest in MP GOM.

Results include amounts attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

27 unchanged sentences

1 Results exclude corporate overhead, interest and discontinued operations.

Results include noncontrolling interest in MP GOM.

Results include amounts attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves 1

Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 1

( Millions of dollars )

24 unchanged sentences

Standardized measure of discounted future net cash flows $ 5,488.0 $ 1,328.0 $ 37.4 $ 6,853.4

1 Includes noncontrolling interest in MP GOM.

2 Totals within the table may not add as a result of rounding.

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves 1 (Continued)

Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 1 (Continued)

The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.

16 unchanged sentences

Standardized measure at December 31 $ 4,624.2 $ 5,395.9 $ 6,853.4

1 Includes noncontrolling interest in MP GOM.

2 The average prices used for 2024 were $ 75.48 per BBL for NYMEX crude oil (WTI) and $ 2.13 per MCF for natural gas (Henry Hub).

The average prices used for 2023 were $ 78.22 per BBL for NYMEX crude oil (WTI) and $ 2.64 per MCF for natural gas (Henry Hub).

The average prices used for 2022 were $ 93.67 per BBL for NYMEX crude oil (WTI) and $ 6.36 per MCF for natural gas (Henry Hub).

1 Includes amounts attributable to the noncontrolling interest in MP GOM.

2 The average prices used for crude oil (WTI) were $ 65.34 /BBL in 2025, $ 75.48 /BBL in 2024 and $ 78.22 /BBL in 2023.

The average prices used for natural gas (Henry Hub) were $ 3.39 /MCF in 2025, $ 2.13 /MCF in 2024 and $ 2.64 /MCF in 2023.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

29 unchanged sentences

Quarter Fourth

Quarter Year 1

Year ended December 31, 2025

Revenue from contracts with customers 1

Income from continuing operations before income taxes 145.6 189.6 153.8 78.6 567.6

Income from continuing operations 115.5 156.9 151.7 65.2 489.3

Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5

Net income attributable to Murphy 90.0 127.7 139.1 50.3 407.1

Income from continuing operations per common share ²

$ 672.7 $ 683.0 $ 721.0 $ 613.1 $ 2,689.8

Income (loss) from continuing operations before income taxes 1

122.8 34.9 ( 3.7 ) 28.9 182.9

Income (loss) from continuing operations 1

90.0 33.8 ( 7.8 ) 22.3 138.3

Net income (loss) including noncontrolling interest 89.4 35.1 ( 8.3 ) 22.6 138.8

Net income (loss) attributable to Murphy 73.0 22.3 ( 3.0 ) 11.9 104.2

Income (loss) from continuing operations per common share ²

Basic 0.51 0.15 ( 0.02 ) 0.08 0.73

Diluted 0.50 0.15 ( 0.02 ) 0.08 0.72

Net income per common share ²

Net income (loss) per common share ²

Basic 0.51 0.16 ( 0.02 ) 0.08 0.73

3 unchanged sentences

Revenue from contracts with customers 1

$ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6

Income from continuing operations before income taxes 1

145.6 189.6 153.8 78.6 567.6

Income from continuing operations 1

115.5 156.9 151.7 65.2 489.3

Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5

7 unchanged sentences

Cash dividend per common share 0.300 0.300 0.300 0.300 1.200

1 Revenue from contracts with customers, “Income from continuing operations before income taxes”, “Income from continuing operations” and “Net income including noncontrolling interest” include results attributable to the noncontrolling interest in MP GOM.

1 “Revenue from contracts with customers”, “Income (loss) from continuing operations before income taxes”, “Income (loss) from continuing operations” and “Net income (loss) including noncontrolling interest” includes results attributable to the noncontrolling interest in MP GOM.

2 The sum of quarterly income (loss) from continuing operations per share and net income (loss) per share may not agree with total year net income (loss) per share as each quarterly computation is based on the weighted average of common shares outstanding.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SCHEDULE II - VALUATION ACCOUNTS AND RESERVES

( Millions of dollars )

January 1 Charged

to Expense Deductions Other Balance at December 31

Deducted from asset accounts:

Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6

Deferred tax asset valuation allowance 146.9 2.6 — — 149.5

Deducted from asset accounts:

Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6

Deferred tax asset valuation allowance 136.0 10.9 — — 146.9

Deducted from asset accounts:

Allowance for doubtful accounts $ 1.6 $ — $ — $ — $ 1.6

Deferred tax asset valuation allowance 111.2 24.8 — — 136.0

CAD or C$ - Canadian dollar

USD or US$ - United States dollar

Units of Measurement:

Units of Measure:

BBL - Barrels

BCF - Billion cubic feet

BOE - Barrels of oil equivalent

BOEPD - Barrels of oil equivalent per day

MCF - Thousand cubic feet

MMBBL - Million barrels of oil

MMBBL - Million barrels

MMBOE - Million barrels of oil equivalent

3 unchanged sentences

Crude oil - Collectively, crude oil and condensate hydrocarbons

Crude oil, natural gas and natural gas liquids - Collectively, oil and natural gas

Development well - A well that is drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive

1 unchanged sentence

E&P - Exploration and production

Exploratory well - A well is drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area

Exploratory well - A well drilled to find and produce crude oil or natural gas in an unproved area and includes delineation wells which target a new reservoir in a field known to be productive or to extend a known reservoir beyond the proved area

FPSO - Floating production, storage and offloading vessel

Hydrocarbons - Organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products

10 unchanged sentences

WTI - West Texas Intermediate

Abbreviations:

AIP - Annual Incentive Plan

ARO - Asset retirement obligation

1 unchanged sentence

ASU - Accounting Standards Update

Bureau of Ocean Energy Management

DEFINITIONS - Continued

Bureau of Safety and Environmental Enforcement

CERCLA - U.S.

Comprehensive Environmental Response, Compensation and Liability Act

CODM - Chief operating decision maker

CRSU - Cash-settled restricted time-based stock unit

DD&A - Depreciation, depletion and amortization

EBITDA - Earnings before interest, taxes, depreciation and amortization

FASB - Financial Accounting Standards Board

Generally Accepted Accounting Principles

NCI - Noncontrolling interest

PCAOB - Public Company Accounting Oversight Board

Securities and Exchange Commission

AIP - Annual Incentive Plan

Bureau of Ocean Energy Management

Bureau of Safety and Environmental Enforcement

CRSU - Cash-settled restricted time-based stock unit

EBITDAX - Earnings before interest, taxes, depreciation and amortization, and exploration expenses

Environmental Protection Agency

ESG - Environmental, social and governance

FASB - Financial Accounting Standards Board

FCF - Free cash flow

generally accepted accounting principles

GHG - Greenhouse gas

GHGRP - Greenhouse Gas Reporting Program

IRA - Inflation Reduction Act

MP GOM - MP Gulf of Mexico, LLC

PAI - Petrobras America Inc.

NCI - Noncontrolling interest

NED - Non-employee director

OBBBA - One Big Beautiful Bill Act

Oil Pollution Act

OT - Operational technology

PCAOB - Public Company Accounting Oversight Board

PSU - Performance-based restricted stock unit

RCF - Revolving credit facility

RCF - Senior unsecured guaranteed revolving credit facility

ROACE - Return on average capital employed

1 unchanged sentence

SAR - Stock appreciation right

Securities and Exchange Commission

SOFR - Secured Overnight Financing Rate

TCFD - Task Force on Climate-related Financial Disclosures

TSR - Total Shareholder Return

WEC - Waste emission charge

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures