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Item 9A. Controls and Procedures

2025-02-27 compared with 2024-02-23 · 724 added, 541 removed, 1843 unchanged (41% of the section changed)

CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board.

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, with the participation of the Company’s management, as of December 31, 2024, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

7 unchanged sentences

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

1 unchanged sentence

Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 14, 2025 under the captions “Election of Directors” and “The Board and Committees.”

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

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

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

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

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

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

1 to this Form 10-K.

EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 14, 2025 under the captions “Compensation Discussion and Analysis” and “How We Are Compensated” and in various compensation schedules.

As required by U.S federal securities laws, the Company revised its incentive-based compensation recoupment (clawback) policy providing for the recovery of erroneously awarded incentive-based compensation received by current or former executive officers.

As required by U.S.

federal securities laws, the Company implemented its incentive-based compensation recoupment (clawback) policy providing for the recovery of erroneously awarded incentive-based compensation received by current or former executive officers.

We have filed our written recoupment policy as Exhibit 97.1 to this Form 10-K report and as of December 31, 2024, there have been no accounting restatements requiring compensation recoupment.

30 unchanged sentences

Note K – Financial Instruments and Risk Management

Note L – Earnings per Share

Note L – Net Income (Loss) Per Common Share

Note M – Other Financial Information

6 unchanged sentences

Note T – Leases

Supplemental Oil and Natural Gas Information (unaudited)

Note U – Subsequent Event

Supplemental Oil and Gas Information (unaudited)

Supplemental Quarterly Information (unaudited)

14 unchanged sentences

Exhibit 2.1 to Form 10-K filed February 27, 2019

2.4 Share Sale and Purchase Agreement between Canam Offshore Limited and PTTEP HK Offshore Limited for the sale and purchase of the entire issued share capital of Murphy Sarawak Oil Co., Ltd.

and Murphy Sabah Oil Co., Ltd., dated March 21, 2019

Exhibit 10.3 to Form 10-Q filed May 2, 2019

3.1 Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005

12 unchanged sentences

Exhibit 4.1 to Form 8-K filed November 30, 2012

4.5 Third Supplemental Indenture dated as of August 17, 2016, between Murphy Oil Corporation and U.S.

Bank National Association, as trustee, relating to 6.875% Notes due 2024

Exhibit 4.1 to Form 8-K filed August 17, 2016

4.6 Fourth Supplemental Indenture dated as of August 18, 2017, between Murphy Oil Corporation and U.S.

Bank National Association, as trustee, relating to 5.75% Notes due 2025

Exhibit 4.1 to Form 8-K filed August 18, 2017

4.5 Fifth Supplemental Indenture dated as of November 27, 2019, between Murphy Oil Corporation and U.S.

6 unchanged sentences

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

10.1 New Credit Agreement dated as of November 17, 2022 among Murphy Oil Corporation, Murphy Exploration & Production Company – International, and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto

Exhibit 10.1 to Form 10-K filed February 27, 2023

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

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

10.1 Murphy Oil Corporation Annual Incentive Plan

1 unchanged sentence

10.2 Murphy Oil Corporation 2018 Long-Term Incentive Plan

Exhibit A to definitive proxy statement filed March 29, 2012

10.4 Amendment to the Murphy Oil Corporation 2012 Long-Term Incentive Plan

Exhibit 10.8 to Form 10-K filed February 27, 2020

10.5 Form of employee stock option (2012 Long-Term Incentive Plan)

Exhibit 99.1 to Form 10-K filed February 28, 2014

10.6 Form of stock appreciation right (2012 Long-Term Incentive Plan)

Exhibit 99.3 to Form 10-Q filed May 7, 2014

10.7 Murphy Oil Corporation 2018 Long-Term Incentive Plan

Exhibit B to definitive proxy statement filed March 23, 2018

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Exhibit 10.4 to Form 8-K filed September 5, 2013

10.28 First Amendment to the New Credit Agreement dated as of December 16, 2022 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto

Exhibit 10.28 to Form 10-K filed February 27, 2023

M urphy Oil Corporation Comp ensation Recoupment Policy

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

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

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

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

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

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

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

Exhibit 10.33 to Form 10-K filed February 23, 2024

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

Exhibit 10.34 to Form 10-K filed February 23, 2024

Form of non-employee director elective restricted stock unit (2021 NED Plan)

Exhibit 10.35 to Form 10-Q filed May 2, 2024

Severance Protection Agreement dated as of August 7, 2013 between Murphy Oil Corporation and Roger W.

Exhibit 10.1 to Form 8-K filed August 9, 2013

Amendment to Severance Protection Agreement dated as of August 7, 2013, between Murphy Oil Corporation and Roger W.

Exhibit 10.1 to Form 10-Q filed May 2, 2019

Credit Agreement, dated as of October 7, 2024, among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd., as borrowers, JPMorgan Chase Bank N.A., as administrative agent, and the lenders party thereto

Exhibit 10.1 to Form 8-K filed October 7, 2024

Form of Severance Protection Agreement

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

Murphy Oil Corporation Insider Trading Policy

*21.1 Subsidiaries of Murphy Oil Corporation

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*23.3 Consent of McDaniel & Associates Consultants Ltd.

Consent of Gaffney, Cline & As sociates Pte .

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

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

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Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*99.1 Ryder Scott reserves audit report for U.S.

Onshore and Gulf of Mexico

*99.2 Ryder Scott reserves audit report for MP GOM JV

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

Gaffney, Cline independent audit report for Vietnam proved crude oil and natural gas reserves

101.INS Inline XBRL Instance Document

Murphy Oil Corporation Compensation Recoupment Policy

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

Netherland, Sewell & Associates, Inc.

independent reserves audit report U.S.

Gulf of Mexico

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

101.SCH Inline XBRL Taxonomy Extension Schema Document

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104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

FORM 10-K SUMMARY

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MURPHY OIL CORPORATION

By /s/ ROGER W.

JENKINS Date:

By /s/ ERIC M.

February 27, 2025

Jenkins, Chief Executive Officer

Hambly, President and

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 27, 2025 by the following persons on behalf of the registrant and in the capacities indicated.

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Kelley, Director

JENKINS /s/ R.

MADISON MURPHY

Hambly, President and

Chief Executive Officer and Director

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Sugg, Director

/s/ ROBERT B.

/s/ THOMAS J.

MIRELES /s/ PAUL D.

Tudor, III, Director

Mireles, Executive Vice President

and Chief Financial Officer

(Principal Financial Officer) Paul D.

(Principal Financial Officer)

Vice President and Controller

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Current liabilities

Current maturities of long-term debt, finance lease $ 723 $ 687

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

Accounts payable 472,165 446,891

1 unchanged sentence

Other taxes payable 31,685 29,339

Operating lease liabilities 207,840 220,413

Operating lease liabilities Note T

253,208 207,840

Other accrued liabilities 117,802 130,033

Current asset retirement obligations 1

48,080 10,712

Total current liabilities 942,814 846,545

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Total liabilities and equity $ 9,667,479 $ 9,766,697

See Notes to Consolidated Financial Statements, page 70.

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.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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

Gain on sale of assets and other income 11,293 32,932 23,916

Gain on sale of assets and other operating income 11,583 11,293 32,932

Total revenues and other income 3,028,474 3,460,147 3,932,662

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Other income (loss)

Other (loss) income ( 8,587 ) 14,310 ( 16,771 )

Other income (loss) 70,902 ( 8,587 ) 14,310

Interest expense, net ( 105,926 ) ( 112,373 ) ( 150,759 )

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Net income attributable to noncontrolling interest 79,314 62,122 173,672

NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 661,559 $ 965,047 $ ( 73,664 )

INCOME (LOSS) PER COMMON SHARE – BASIC

NET INCOME ATTRIBUTABLE TO MURPHY $ 407,171 $ 661,559 $ 965,047

NET INCOME (LOSS) PER COMMON SHARE – BASIC

Continuing operations $ 2.73 $ 4.27 $ 6.23

Discontinued operations ( 0.02 ) ( 0.01 ) ( 0.01 )

Net income (loss) $ 4.26 $ 6.22 $ ( 0.48 )

INCOME (LOSS) PER COMMON SHARE – DILUTED

Net income $ 2.71 $ 4.26 $ 6.22

NET INCOME (LOSS) PER COMMON SHARE – DILUTED

Continuing operations $ 2.72 $ 4.23 $ 6.14

Discontinued operations ( 0.02 ) ( 0.01 ) ( 0.01 )

Net income (loss) $ 4.22 $ 6.13 $ ( 0.48 )

Net income $ 2.70 $ 4.22 $ 6.13

Cash dividends per common share $ 1.200 $ 1.100 $ 0.825

2 unchanged sentences

Diluted 151,027 156,646 157,475

See Notes to Consolidated Financial Statements, page 70.

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Other comprehensive income (loss), net of tax

Net gain (loss) from foreign currency translation

Net (loss) gain from foreign currency translation

( 134,692 ) 36,598 ( 106,335 )

Retirement and postretirement benefit plans 27,737 ( 23,029 ) 99,360

Deferred loss on interest rate hedges reclassified to interest expense – – 1,690

Other comprehensive income (loss)

3 unchanged sentences

Comprehensive income attributable to noncontrolling interest 79,314 62,122 173,672

COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY

$ 300,216 $ 675,128 $ 958,072

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ 675,128 $ 958,072 $ ( 42 )

See Notes to Consolidated Financial Statements, page 70.

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Depreciation, depletion and amortization 865,753 861,602 776,817

Deferred income tax expense (benefit) 179,823 286,079 ( 4,146 )

Unsuccessful exploration well costs and previously suspended exploration costs 73,201 169,795 82,085

Contingent consideration payment

( 139,574 ) – –

Long-term non-cash compensation 61,953 89,246 63,382

Deferred income tax expense 72,434 179,823 286,079

Impairment of assets 62,909 — —

Accretion of asset retirement obligations 52,511 46,059 46,243

Long-term non-cash compensation 45,057 61,953 89,246

Amortization of undeveloped leases 9,587 10,925 13,300

Mark to market loss on contingent consideration 7,113 78,285 63,147

Mark to market (gain) loss on derivative instruments – ( 214,788 ) 112,113

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

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

1,707 — ( 214,788 )

Contingent consideration payment

— ( 139,574 ) —

Mark-to-market loss on contingent consideration

— 7,113 78,285

Gain from sale of assets

Impairment of assets – – 196,296

— — ( 17,899 )

Other operating activities, net ( 18,349 ) ( 74,728 ) ( 34,193 )

Net (increase) decrease in noncash working capital ( 99,361 ) ( 65,728 ) 118,457

Net decrease (increase) in non-cash working capital

74,883 ( 99,361 ) ( 65,728 )

Net cash provided by continuing operations activities 1,728,990 1,748,755 2,180,244

5 unchanged sentences

Proceeds from sales of property, plant and equipment — 102,913 4,528

Property additions for King's Quay FPS – – ( 17,734 )

Net cash required by investing activities ( 908,164 ) ( 998,680 ) ( 1,109,471 )

Financing Activities

Borrowings on revolving credit facility 600,000 400,000 165,000

Repayment of revolving credit facility ( 600,000 ) ( 400,000 ) ( 365,000 )

Retirement of debt ( 650,112 ) ( 498,175 ) ( 647,707 )

Early redemption of debt cost ( 15,700 ) — ( 8,295 )

Debt issuance 600,000 — —

Debt issuance cost

( 10,145 ) — —

Borrowings on revolving credit facility 350,000 600,000 400,000

Repayment of revolving credit facility ( 350,000 ) ( 600,000 ) ( 400,000 )

Issue costs of revolving credit facility ( 14,718 ) ( 20 ) ( 14,353 )

Repurchase of common stock ( 301,350 ) ( 150,022 ) —

Contingent consideration paid ( 60,243 ) ( 81,742 ) –

Cash dividends paid ( 179,961 ) ( 170,978 ) ( 128,219 )

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Finance lease obligation payments ( 665 ) ( 622 ) ( 636 )

Debt issuance, net of cost – – 541,913

Issue costs of debt facility ( 20 ) ( 14,353 ) –

Contingent consideration payment — ( 60,243 ) ( 81,742 )

Net cash required by financing activities

3 unchanged sentences

Effect of exchange rate changes on cash and cash equivalents 2,210 ( 1,246 ) ( 3,873 )

Net (decrease) increase in cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

106,495 ( 174,889 ) ( 29,221 )

1 unchanged sentence

Cash and cash equivalents at end of period $ 423,569 $ 317,074 $ 491,963

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.

See Notes to Consolidated Financial Statements, page 70.

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Years Ended December 31 (Thousands of dollars except number of shares) 2024 2023 2022

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

Common Stock – par $ 1.00 , authorized 450,000,000 shares at December 31, 2023, 2022 and 2021, issued 195,100,628 shares at December 31, 2023, 2022 and 2021

Balance at beginning and end of year 195,101 195,101 195,101

Balance at beginning and end of year - par $ 1.00 , authorized 450,000,000 shares at December 31, 2024, 2023 and 2022, issued 195,100,628 shares at December 31, 2024, 2023 and 2022

195,101 195,101 195,101

Capital in Excess of Par Value

Balance at beginning of year 880,297 893,578 926,698

Share-based compensation 29,386 25,242 25,429

Restricted stock transactions and other 1

( 70,539 ) ( 42,667 ) ( 58,362 )

Share-based compensation 39,192 29,386 25,242

Balance at end of year 848,950 880,297 893,578

1 unchanged sentence

Balance at beginning of year 6,546,079 6,055,498 5,218,670

Net income (loss) for the year attributable to Murphy 661,559 965,047 ( 73,664 )

Net income attributable to Murphy 407,171 661,559 965,047

Cash dividends paid ( 179,961 ) ( 170,978 ) ( 128,219 )

2 unchanged sentences

Balance at beginning of year ( 521,117 ) ( 534,686 ) ( 527,711 )

Foreign currency translation (losses) gains, net of income taxes 36,598 ( 106,335 ) 12,116

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

( 134,692 ) 36,598 ( 106,335 )

Retirement and postretirement benefit plans, net of income taxes 27,737 ( 23,029 ) 99,360

Deferred loss on interest rate hedge reclassified to interest expense,

net of income taxes – – 1,690

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

1 unchanged sentence

Balance at beginning of year ( 1,737,566 ) ( 1,614,717 ) ( 1,655,447 )

Purchase of treasury shares ( 151,241 ) – –

Repurchase of common stock ( 302,681 ) ( 151,241 ) —

Awarded restricted stock, net of forfeitures 45,229 28,392 40,730

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

See Notes to Consolidated Financial Statements, page 70.

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

These notes are an integral part of the consolidated financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 71 - 105 of the Form 10-K report.

Note A – Significant Accounting Polices

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries.

The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and gas exploration activities worldwide.

BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of the Company and are presented in conformity with GAAP.

The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries.

Note A – Significant Accounting Policies

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries.

The Company primarily produces oil and natural gas in the U.S.

and Canada and conducts oil and natural gas exploration activities worldwide.

BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries and are presented in conformity with GAAP.

Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis.

Investments in affiliates in which the Company owns from 20 % to 50 % are accounted for by the equity method.

Beginning in the fourth quarter of 2018, Murphy reports 100 % of the sales volume, revenues, costs, assets and liabilities including the 20 % noncontrolling interest in MP GOM in accordance with accounting for noncontrolling interest as prescribed by Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-10-45, “Consolidations”.

Murphy reports 100 % of the sales volume, revenues, costs, assets and liabilities including the 20 % noncontrolling interest in MP GOM in accordance with accounting for noncontrolling interest as prescribed by Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810-10-45, “Consolidations”.

Other investments are generally carried at cost.

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Actual results may differ from the estimates.

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

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

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

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The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers, joint venture partners and historical write-off experience.

Any trade accounts receivable balances written off are

Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts.

The Company has not experienced any significant credit-related losses in the past three years.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note A – Significant Accounting Policies (Continued)

charged against the allowance for doubtful accounts.

The Company has not experienced any significant credit-related losses in the past three years.

INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations.

Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing condition), or market.

Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and including costs incurred to bring the inventory to its existing condition), or market.

Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment.

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Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable.

An impairment is recognized when there are indications that the estimated undiscounted future net cash flows of an asset are less than its carrying value.

If an impairment occurs, the carrying value of the impaired asset is reduced to fair value.

There were no impairments recognized in 2023 and 2022.

The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset.

An impairment is assessed when there is an indication that the estimated undiscounted future net cash flows of an asset are less than its carrying value.

If an impairment occurs, the carrying value of the impaired asset is reduced to its fair value.

See Note D for further discussion of impairment charges.

The Company records a liability for ARO equal to the fair value of the estimated cost to retire an asset.

The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled, or the asset is placed in service.

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The Company reevaluates the adequacy of its recorded ARO liability at least annually.

Actual costs of asset retirements such as dismantling oil and natural gas production facilities and site restoration are charged against the related liability.

Actual costs of asset retirements such as dismantling oil and natural gas production facilities, plugging and abandoning wells and restoring sites are charged against the related liability.

Any difference between costs incurred upon settlement of an ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings.

7 unchanged sentences

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

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

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

Operating leases are presented on the Consolidated Balance Sheets as “Operating lease assets” with the corresponding lease liabilities presented in “Operating lease liabilities” and “Non-current operating lease liabilities”.

Finance lease assets are presented on the Consolidated Balance Sheets within

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note A – Significant Accounting Policies (Continued)

operating or finance lease.

Finance lease assets (related to Brunei) are presented on the Consolidated Balance Sheets within “Property, plant and equipment”, with the corresponding liabilities presented in “Current maturities of long-term debt, finance lease” and “Long-term debt, including finance lease obligation”.

“Property, plant and equipment”, with the corresponding liabilities presented in “Current maturities of long-term debt, finance lease” and “Long-term debt, including finance lease obligation”.

Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term.

4 unchanged sentences

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

If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used.

If there is a range of reasonably estimated costs, the most likely amount will be recorded.

If no amount is most likely, the minimum of the range is used.

Related expenditures are charged against the liability.

2 unchanged sentences

INCOME TAXES – The Company accounts for income taxes using the asset and liability method.

Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities arising from differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse.

8 unchanged sentences

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Continued)

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

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

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

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

The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk.

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

Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions.

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Continued)

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

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

5 unchanged sentences

Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock.

The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units (PSUs) that are equity settled, and expense is recognized over the three -year vesting period.

The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period.

The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units (PSUs) with market based conditions, and expense is recognized over the three-year vesting period.

The fair value of PSUs with performance-based conditions and time-based restricted stock units (RSUs) is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period.

The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options.

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When SARs are exercised and when CRSUs settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note A – Significant Accounting Policies (Continued)

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.

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

NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period.

NET INCOME (LOSS) PER COMMON SHARE – Basic net income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period.

Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares.

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Accounting Principles Adopted

None affecting the Company.

Reportable Segment Disclosures.

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

Improvements to Reportable Segment Disclosures .

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

The Company adopted this standard in the fourth quarter of 2024.

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

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

Refer to Note S .

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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

Recent Accounting Pronouncements

Expense Disaggregation Disclosures.

In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40):

Disaggregation of Income Statement Expenses.

The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027.

The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements.

In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described.

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

Income Tax Disclosures.

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

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

Improvements to Income Tax Disclosures.

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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.

Murphy is currently evaluating the impact of adopting this standard.

Reportable Segment Disclosures.

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

Improvements to Reportable Segment Disclosures .

The standard becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024.

The standard does not affect our determination of significant segments.

Murphy is currently evaluating the impact of adopting this standard.

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

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe.

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

The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments:

Additionally, revenue from sales to customers is generated from three primary revenue streams:

crude oil and condensate, natural gas liquids and natural gas.

For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production.

crude oil, natural gas and NGLs.

For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production.

The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by GAAP.

- In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico.

- In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America.

Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point.

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For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

The Company also purchases natural gas in Canada to meet certain sales commitments.

Disaggregation of Revenue

The Company reviews performance-based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Note C - Revenue from Contracts with Customers (Continued)

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.

The Company’s revenues and other income for each of the three year presented were as follows.

The Company’s revenues and other income for each of the three years presented were as follows.

Years Ended December 31,

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$ 586,584 $ 676,139 $ 856,219

United States - Offshore 1

1,777,723 2,072,353 2,229,658

Canada - Onshore 70,855 78,088 131,400

Offshore 78,650 117,747 92,741

Canada - Offshore 193,961 78,650 117,747

Other 6,537 11,022 22,824

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United States - Onshore 32,853 33,178 64,015

United States - Offshore 1

38,858 47,434 60,424

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United States - Onshore 17,443 21,346 64,037

United States - Offshore 1

50,329 71,332 161,160

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Canada - Onshore

3,742 72,215 181,485

Total sales of purchased natural gas 3,742 72,215 181,689

Total revenue from sales to customers 3,018,598 3,448,854 4,220,140

(Loss) gain on crude contracts – ( 320,410 ) ( 525,850 )

Gain on sale of assets and other income

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

Gain on sale of assets and other operating income 11,583 11,293 32,932

Total revenues and other income

$ 3,028,474 $ 3,460,147 $ 3,932,662

Total revenue and other income $ 3,460,147 $ 3,932,662 $ 2,299,281

1 Includes revenue attributable to noncontrolling interest in MP GOM.

In 2022, the Company included additional line items on the face of the Consolidated Statements of Operations to report “Sales of purchased natural gas” and “Costs of purchased natural gas”.

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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This occurs at the time the product is delivered to a third party purchaser at the contractually determinable price.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note C – Revenue from Contracts with Customers (Continued)

Contract Balances and Asset Recognition

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For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note C - Revenue from Contracts with Customers (Continued)

Performance Obligations

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Location Commodity End Date Description Approximate Volumes

Natural Gas and NGL Q1 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

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 2024 Contracts to sell natural gas at CAD fixed pricing 124 MMCFD

Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD fixed pricing 25 MMCFD

Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD index pricing 28 MMCFD

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

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

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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

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

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

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

Note D – Property, Plant and Equipment

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

During the third quarter of 2022, the Company completed the disposition of its 62.5 % operated 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 asset retirement obligations of approximately $ 47.9 million.

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 the Block CA-2 asset in Brunei for contingent consideration valued at approximately $ 8.7 million.

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 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 Kodiak field for a purchase price of $ 50.0 million, net of closing adjustments.

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

Canada $ – $ – $ 171,296

Other Foreign – – 18,000

Corporate – – 7,000

United States - Offshore

$ 62,909 $ — $ —

Exploratory Wells

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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 )

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Ending balance at December 31 $ 72,055 $ 49,118 $ 171,860

Reclassifications to proved properties of $ 82.2 million, for the year ended December 31, 2023, are primarily related to LDV-4X in Vietnam.

Capitalized well costs charged to dry hole expense of $ 40.6 million are related to the Cholula-1EXP well in offshore Mexico, and Oso #1 (Atwater Valley 138), and Chinook #7 (Walker Ridge 425) exploration wells in the Gulf of Mexico.

The preceding table excludes well costs of $ 129.2 million incurred and expensed directly to dry hole during the year ended December 31, 2023, related to the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) explorations well in the Gulf of Mexico.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized.

The projects are aged based on the last well drilled in the project.

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)

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

2024 2023 2022

( Thousands of dollars )

Projects Amount No.

Wells Amount No.

Aging of capitalized well costs

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$ 72,055 8 $ 49,118 4 $ 171,860 9

Of the $ 49.1 million of exploratory well costs capitalized more than one year at December 31, 2023, $ 26.5 million is in the U.S., $ 15.1 million is in Vietnam, $ 4.8 million is in Canada and $ 2.7 million is in Brunei.

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

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

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Notes payable

5.75 % notes, due August 2025

$ – $ 248,675

5.875 % notes, due December 2027

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117,582 179,708

6.00 % notes, due October 2032

5.875 % notes, due December 2042 ¹

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Total notes payable, net of unamortized discount 1,270,496 1,324,837

Capitalized lease obligation, due through March 2029 4,238 4,844

Finance lease obligations, due through November 2034 4,877 4,238

Total debt including current maturities 1,275,373 1,329,075

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1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.

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

nil in 2024, nil in 2025, nil in 2026, $ 443.2 million in 2027, $ 372.2 million in 2028 and $ 519.5 million thereafter.

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

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

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

In November 2022, the Company entered into a $ 800 million revolving credit facility, and the previous revolving credit facility has been terminated effective November 2022.

The RCF is a senior unsecured guaranteed facility which expires on November 17, 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.

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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 Prime Rate in effect on such day, (b) the New York Federal Reserve Bank (NYFRB) 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.

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

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

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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 and S&P, respectively.

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.

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

In November 2023, the Company tendered a total of $ 249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes, retiring $ 250 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.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

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Note F - Financing Arrangements and Debt (Continued)

Debt Offering

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

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

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

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

Debt Extinguishment

In December 2024, the Company redeemed $ 79.0 million of the 2027 Notes.

The total cost of the debt extinguishment of $ 1.2 million, consisting of cash costs of $ 0.8 million and non-cash costs of $ 0.4 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024.

In October 2024, the Company tendered an aggregate $ 521.1 million of its notes, comprised of:

$ 258.8 million of the 2027 Notes, $ 200.2 million of the 2028 Notes and $ 62.1 million of the 2029 Notes.

The total cost of the debt extinguishment of $ 18.2 million, consisting of cash costs of $ 14.9 million and non-cash costs of $ 3.3 million, is included in “Interest expense, net” on the Consolidated Statements of Operations for the year ended December 31, 2024.

In May 2024, the Company paid a total of $ 50.5 million to complete the open market repurchases of $ 26.5 million aggregate principal of its 2027 Notes and $ 23.5 million aggregate principal of its 2028 Notes.

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

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

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

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

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

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

In November 2022, the Company redeemed $ 200.0 million aggregate principal amount of its 2025 Notes.

The cost of debt extinguishment of $ 3.9 is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022.

The cash costs of $ 2.9 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.

In September and October 2022, the Company paid a total of $ 7.2 million to complete the open market repurchases of $ 9.2 million aggregate principal amount of its 6.125 % senior notes due 2042 (2042 Notes).

There were no additional cash costs related to the September and October 2022 debt extinguishment on the 2042 Notes for the year ended December 31, 2022.

In August 2022, the Company redeemed the remaining $ 42.4 million of its 6.875 % senior notes due in 2024 (2024 Notes) and tendered $ 100.0 million and $ 98.1 million aggregate principal amount of its 2025 Notes and 2028 Notes, respectively.

The total cost of the debt extinguishment of $ 4.0 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022.

The debt extinguishment on the 2025 and 2028 Notes had cash costs of $ 2.0 million and is shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.

In June 2022, the Company redeemed $ 200.0 million aggregate principal amount of its 6.875 % 2024 Notes.

The cost of the debt extinguishment of $ 4.3 million is included in “Interest expense, net” on the Consolidated Statement of Operations for the year ended December 31, 2022.

The cash costs of $ 3.4 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2022.

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

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

Note G – Asset Retirement Obligations

The asset retirement obligations liabilities recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.

The ARO liabilities recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.

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

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Changes due to translation of foreign currencies ( 11,390 ) 3,004

Balance at end of year 914,763 911,653

Balance at end of period 1,008,884 914,763

Current portion of liability ( 48,080 ) ( 10,712 )

Noncurrent portion of liability $ 904,051 $ 817,268

1 Included in “Other accrued liabilities” on the Consolidated Balance Sheets.

Non-current portion of liability $ 960,804 $ 904,051

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.

1 unchanged sentence

prices for oil field services, technological changes, governmental requirements and other factors.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note H – Income Taxes

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2024 2023 2022

Income tax expense (benefit) based on the U.S.

Income tax expense based on the U.S.

statutory tax rate

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

$ 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

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Total gross deferred tax assets 727,433 777,683

Less valuation allowance ( 146,861 ) ( 136,008 )

Valuation allowance

( 149,498 ) ( 146,861 )

Net deferred tax assets 577,935 630,822

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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 2012 Long-Term Incentive Plan (2012 Long-Term Plan), the 2018 Long-Term Incentive Plan (2018 Long-Term Plan) and the 2020 Long-Term Incentive Plan (2020 Long-Term Plan).

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

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

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The 2020 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock to employees.

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

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.

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Based on awards made to date, 1.2 million shares are available for grant under the 2020 Long-Term Plan at December 31, 2024.

The Stock Plan for Non-Employee Directors (2021 NED Plan) permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company 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

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Note I – Incentive Plans (Continued)

Company currently has outstanding incentive awards issued to Directors under the 2021 NED Plan and the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan).

The Company generally expects to issue treasury shares to satisfy vesting of restricted stock and restricted stock units.

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

All awards on or after May 12, 2021, were made under the 2021 NED Plan.

The Company generally expects to issue treasury shares to satisfy the vesting of restricted stock and RSUs.

Amounts recognized in the financial statements with respect to share-based plans for each of the three years presented are shown in the following table.

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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 restricted stock unit vest.

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

Equity-Settled Awards

PERFORMANCE-BASED RESTRICTED STOCK UNITS – PSUs to be settled in common shares were granted in 2020 under the 2018 Long-Term Plan, and in 2021, 2022 and 2023 under the 2020 Long-Term Plan.

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

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

1 unchanged sentence

If performance goals are not met, PSUs will not vest, but the recognized compensation cost associated with the stock award would not be reversed.

For PSUs, the performance conditions are based on the Company’s total shareholder return ( 80 % weighting), compared to an industry peer group of companies, and the EBITDA divided by Average Capital Employed metric ( 20 % weighting) for PSU awards, over the performance period.

The performance conditions for the PSUs are weighted 80 % on the Company’s total shareholder return (TSR) relative to an industry peer group and 20 % on the return on average capital employed (ROACE), measured over the applicable performance period.

ROACE is calculated by dividing the Company’s EBITDA by the average of the opening and closing Capital Employed (the sum of total equity and short-term and long-term debt).

During the performance period, PSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death.

1 unchanged sentence

No dividends are paid, nor do voting rights exist on awards of PSUs prior to their settlement.

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

( Number of stock units )

2023 2022 2021

Outstanding at beginning of year 2,148,467 2,670,756 2,207,429

Granted 409,160 595,700 1,156,800

Vested and issued ( 408,135 ) ( 654,177 ) ( 642,473 )

Forfeited ( 331,304 ) ( 463,812 ) ( 51,000 )

Outstanding at end of year 1,818,188 2,148,467 2,670,756

The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model.

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

The fair value of the PSUs based on the Company’s TSR was estimated on the date of grant using a Monte Carlo valuation model.

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

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

3 unchanged sentences

Fair value per share at grant date $ 41.95 $ 60.46 $ 37.77 - $ 47.37

$ 37.77 - $ 47.37

Expected volatility 50.00 % 81.00 % 79.00 % - 81.00 %

79.00 % - 81.00 %

Risk-free interest rate 4.14 % 3.90 % 1.39 % - 2.85 %

1.39 % - 2.85 %

Stock beta 1.062 1.034 1.195 - 1.200

1.195 - 1.200

Expected life 3.0 years 3.0 years 3.0 years

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note I – Incentive Plans (Continued)

TIME-BASED RESTRICTED STOCK UNITS – Time-based RSUs have been granted to the Company’s Non-Employee Directors (NED) under the 2018 NED Plan and 2021 NED Plan, and to certain employees under the 2020 Long-Term Plan.

The fair value of the time-based restricted stock units awarded for each of the last three years are presented in the following table.

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

( Number of stock units )

2024 2023 2022

Outstanding at beginning of year 1,818,188 2,148,467 2,670,756

Granted 536,900 409,160 595,700

Vested and issued ( 938,599 ) ( 408,135 ) ( 654,177 )

Forfeited ( 24,068 ) ( 331,304 ) ( 463,812 )

Outstanding at end of year 1,392,421 1,818,188 2,148,467

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

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

Type of Plan Valuation Methodology 2024 2023 2022

1 unchanged sentence

Closing Stock Price at Grant Date $ 30.26 - $ 45.70

$ 43.27 $ 32.84

Long-Term Incentive Plan 2

Average Low/High Stock Price at Grant Date $ 42.20 $ 29.80 - $ 49.86

Average High/Low Stock Price at Grant Date

$ 37.78 - $ 45.98

$ 42.20 $ 29.80 - $ 49.86

1 Under the 2021 NED Plan, RSUs granted in 2024 are scheduled to vest in February 2025.

2 The RSUs granted under the 2018 and 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 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.

7 unchanged sentences

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 Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant.

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 .

13 unchanged sentences

( 546,000 ) 49.65

( 558,900 ) 52.61

Outstanding at December 31, 2022 13,000 28.51

2 unchanged sentences

Outstanding at December 31, 2023 — —

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

Exercisable at December 31, 2023 – –

The total intrinsic value of options exercised during 2023 was $ 0.16 million.

Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise.

Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.

Cash-Settled Awards

3 unchanged sentences

Each award granted is settled, net of applicable income tax withholdings, in cash rather than with common shares.

Total pre-tax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $ 29.4 million in 2023, $ 49.3 million in 2022 and $ 18.2 million in 2021.

Total pretax expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $ 1.7 million in 2024, $ 29.4 million in 2023 and $ 49.3 million in 2022.

The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees.

12 unchanged sentences

Upon the disposal of Murphy’s former U.K.

downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business.

refining and marketing assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business.

No additional benefits will accrue to these former U.K.

employees under the Company’s retirement plan after the date of their separation from Murphy.

GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its Consolidated Balance Sheets and to recognize changes in that funded status between periods through “Accumulated other comprehensive loss”.

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status for the respective periods presented.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note J – Employee and Retiree Benefit Plans (Continued)

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status for the respective periods presented.

Benefits Other

7 unchanged sentences

Participant contributions — — 2,730 2,629

Actuarial loss (gain) 26,625 ( 238,407 ) ( 5,567 ) ( 29,533 )

Actuarial (gain) loss 1

( 35,417 ) 26,625 825 ( 5,567 )

Medicare Part D subsidy — — 358 299

17 unchanged sentences

Fund Status and net plan liability recognized at December 31 $ ( 163,204 ) $ ( 221,342 ) $ ( 54,994 ) $ ( 63,808 )

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

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

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

In 2023, the increase to the pension benefits obligation is primarily due to the decrease in the interest rate assumption.

At December 31, 2023, amounts included in “Accumulated other comprehensive loss” (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note J – Employee and Retiree Benefit Plans (Continued)

recognized in net periodic benefit expense are shown in the following table.

At December 31, 2024, amounts included in “Accumulated other comprehensive loss” in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.

( Thousands of dollars )

4 unchanged sentences

$ ( 181,451 ) $ 43,147

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note J – Employee and Retiree Benefit Plans (Continued)

The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.

16 unchanged sentences

Amortization of prior service cost (credit) 2,316 620 ( 684 ) ( 532 ) ( 532 ) ( 532 )

Recognized actuarial (gain) loss 9,776 16,098 20,565 ( 3,512 ) ( 615 ) ( 29 )

Recognized actuarial loss (gain)

9,438 9,776 16,098 ( 3,586 ) ( 3,512 ) ( 615 )

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

Curtailment expense 219 – – – – –

Other pension costs 251 219 — — — —

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

8 unchanged sentences

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

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2023 and 2022 and net periodic benefit expense for 2023 and 2022.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note J – Employee and Retiree Benefit Plans (Continued)

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2024 and 2023 and net periodic benefit expense for 2024 and 2023.

Benefit Obligations Net Periodic Benefit Expense

32 unchanged sentences

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

Asset classes and target allocations are determined by our investment committee and includes equities, fixed income and other investments, including hedge funds, real estate and cash equivalent securities.

Asset classes and target allocations are determined by our investment committee and include equities, fixed income and other investments, including hedge funds, real estate and cash equivalent securities.

Investment managers are prohibited from investing in equity or fixed income securities issued by the Company.

The majority of plan assets are highly liquid, providing flexibility for benefit payment requirements.

The current target allocations for plan assets are 40 - 75 % equity securities, 20 - 60 % fixed income securities, 0 - 15 % alternatives and 0 - 20 % cash and equivalents.

Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.

The current target allocations for plan assets are 40 - 75 % equity securities, 20 - 60 % fixed

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note J – Employee and Retiree Benefit Plans (Continued)

income securities, 0 - 15 % alternatives and 0 - 20 % cash and equivalents.

Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.

The weighted average asset allocation for the Company’s funded pension benefit plans at the respective balance sheet dates are shown in the following table.

71 unchanged sentences

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 also 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.

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

The latter of these investments was sold during 2024.

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

20 unchanged sentences

Total at December 31, 2024 $ 18,015

THRIFT PLANS – Most full-time U.S.

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

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 %.

4 unchanged sentences

The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features.

Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange.

Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the NYMEX.

The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.

For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.

Certain interest rate derivative contracts were previously accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL and amortized to “Interest expense, net” over time.

In 2021, the Company redeemed all of the remaining notes due 2022, which were associated with the interest rate derivative contracts and expensed the remainder of the previously deferred loss on the interest rate swap of $ 2.1 million to “Interest expense, net” in the Consolidated Statement of Operations.

Commodity Price Risks

During 2022, the Company had crude oil swaps and collar contracts.

Under the swaps contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.

Under the collar contracts, which also matured monthly, the Company purchased a put option and sold a call option with no net premiums paid to or received from counterparties.

Upon maturity, collar contracts required payments by the Company if the NYMEX average closing price was above the ceiling price or payments to the Company if the NYMEX average closing price was below the floor price.

At December 31, 2023 and December 31, 2022, the Company did no t have any outstanding crude oil derivative contracts.

At December 31, 2021, the Company had 20,000 barrels per day in NYMEX WTI swap contracts at a price per barrel of $ 44.88 and 25,000 barrels per day in NYMEX WTI collar contracts with an average ceiling price per barrel of $ 75.20 and an average floor price per barrel of $ 63.24 , both maturing ratably during 2022.

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

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

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

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

NYMEX Henry Hub

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:

NYMEX Henry Hub

Area Commodity Volumes MMCF/d Price/MCF Start Date End Date

Fixed price derivative swap

United States

40 $ 3.58 2/1/2025 6/30/2025

Fixed price derivative swap

United States

60 $ 3.65 7/1/2025 9/30/2025

Fixed price derivative swap

United States

60 $ 3.74 10/1/2025 12/31/2025

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Note K – Financial Instruments and Risk Management (Continued)

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

Foreign Currency Exchange Risks

1 unchanged sentence

The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2024 and 2023.

At December 31, 2024 and 2023, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

See also Note O .

( Thousands of dollars )

Asset (Liability) Derivatives Fair Value at December 31,

Type of Derivative Contract

Balance Sheet Location 2024 2023

Commodity swaps Accounts payable $ ( 1,707 ) —

The gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments for each of the three years presented are shown in the following table.

4 unchanged sentences

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

The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments.

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

Trade receivables arise mainly from sales of oil and natural gas in the U.S.

5 unchanged sentences

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

Note L – Earnings Per Share

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 .

5 unchanged sentences

Diluted method 151,027,352 156,646,429 157,474,838

1 Due to a net loss recognized by the Company for the year ended December 31, 2021, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

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

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

1 unchanged sentence

Weighted average price of these options — — $ 49.65

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 $ 10.8 million loss in 2023, $ 23.0 million gain in 2022 and $ 1.0 million gain in 2021.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note M – Other Financial Information (Continued)

Noncash operating working capital (increased) decreased during each of the three years presented as shown in the following table.

Note M – Other Financial Information

Gain from Foreign Currency Transactions

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

Supplemental Information to Statement of Cash Flows

( Thousands of dollars )

6 unchanged sentences

Increase (decrease) in income taxes payable ( 2,004 ) ( 5,537 ) 6,593

Net (increase) decrease in noncash operating working capital $ ( 99,361 ) $ ( 65,728 ) $ 118,457

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

Supplementary disclosures:

5 unchanged sentences

(Increase) decrease in capital expenditure accrual ( 5,935 ) 17,517 ( 31,397 )

1 Excludes receivable/payable balances relating to mark-to-market of crude contracts.

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

Note N – Accumulated Other Comprehensive Loss

The components of AOCL on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table.

The components of ”Accumulated other comprehensive loss” on the Consolidated Balance Sheets for the periods presented and the changes during the respective periods are shown net of taxes in the following table.

( Thousands of dollars )

29 unchanged sentences

Nonqualified employee savings plan $ 19,469 $ — $ — $ 19,469 $ 17,785 $ — $ — $ 17,785

Commodity swaps — 1,707 — 1,707 — — — —

$ 19,469 $ 1,707 $ — $ 21,176 $ 17,785 $ — $ — $ 17,785

2 unchanged sentences

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.

In 2019, the Company acquired strategic deepwater Gulf of Mexico assets from LLOG Exploration Offshore L.L.C.

and LLOG Bluewater Holdings, L.L.C., (LLOG).

Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $ 200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022;

and $ 50 million following first oil from certain development projects.

The revenue threshold was not exceeded for 2019 or 2020;

however, the threshold was met in 2021 and 2022.

In 2018, the Company, through a subsidiary, acquired Gulf of Mexico producing assets from Petrobras America Inc.

(PAI), a subsidiary of Petróleo Brasileiro S.A.

Under the terms of the transaction, in addition to the consideration paid, Murphy had an obligation to pay additional contingent consideration of up to $ 150 million if certain price and production thresholds are exceeded beginning in 2019 through 2025;

and $ 50 million carry for PAI development costs in the St.

Malo Field if certain enhanced oil recovery projects are undertaken.

The price and production thresholds were not exceeded for 2019 and 2020;

however, the thresholds were met in 2021 and 2022.

As of December 31, 2021, Murphy had completely funded the carried interest.

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, is no longer subject to fair value measurement.

The liability is 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 (loss) income” in the Consolidated Statements of Operations.

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

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

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

4 unchanged sentences

The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities.

Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value

Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy.

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

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

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.

( Thousands of dollars )

3 unchanged sentences

Fair Values – Nonrecurring

There were no impairment expenses incurred in 2023 and 2022.

Impairment expenses of $ 62.9 million were incurred in 2024.

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

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

There were no impairment expenses incurred in 2023.

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

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

Year Ended December 31, 2024

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

1 unchanged sentence

and Canada Onshore.

Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2045, while the Canada Onshore processing contracts call for minimum monthly payments through 2051.

Onshore and U.S.

Offshore transportation contracts require minimum monthly payments through 2045, while the Canada Onshore transportation contracts call for minimum monthly payments through 2051.

and Canada Onshore, future required minimum annual payments for the next five years are $ 148.8 million in 2025, $ 117.7 million in 2026, $ 105.5 million in 2027, $ 96.0 million in 2028 and $ 64.2 million in 2029.

1 unchanged sentence

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 $ 209.8 million at December 31, 2023, including $ 173.3 million for costs to develop deepwater U.S.

Gulf of Mexico fields, $ 13.3 million for Eagle Ford Shale, $ 19.2 million for Canada and $ 4.0 million for Other Foreign.

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

Note Q – Environmental and Other Contingencies

8 unchanged sentences

expropriation of property;

restrictions and preferences affecting the issuance of oil and gas or mineral leases;

restrictions and preferences affecting the issuance of oil and natural gas or mineral leases;

restrictions on drilling and/or production;

3 unchanged sentences

Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.

ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety.

ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety.

The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials;

6 unchanged sentences

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.

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.

3 unchanged sentences

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 December 2023, the U.S.

EPA announced 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.

In addition, there have been a number of executive orders issued that address climate change, including creation of climate-related task forces, directives to federal agencies to procure carbon-free electricity, and a goal of a carbon pollution-free power sector by 2035 and a net-zero emissions U.S.

economy by 2050.

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.

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.

The Paris Agreement entered into force in November 2016.

Although the U.S.

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

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

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

on February 19, 2021.

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

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

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note Q - Environmental and Other Contingencies (Continued)

have been taken for disposal.

In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control.

Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes

(including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.

Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.

Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses.

11 unchanged sentences

Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note R – Common Stock Issued and Outstanding

11 unchanged sentences

1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon issuance of shares.

On August 4, 2022, the Board authorized a share repurchase program of up to $ 300 million of the Company’s common stock.

During 2023, the Board authorized an increase to the program, bringing the total amount allowed to be repurchased under the program to $ 600 million.

The Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $ 1,100.0 million of its common stock.

This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors.

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.

During the year ended December 31, 2023, the Company repurchased 3,411,158 shares of its common stock under the share repurchase program for $ 151.2 million, including excise taxes, commissions and fees.

As of December 31, 2023, the Company had $ 450 million remaining available to repurchase.

During the year ended December 31, 2024, the Company repurchased 8.0 million shares of its common stock under the share repurchase program for $ 300.0 million ($ 302.7 million including excise taxes and fees).

As of December 31, 2024, the Company had $ 650.1 million of its common stock remaining available to repurchase under the program.

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note R - Common Stock Issued and Outstanding (Continued)

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

Note S – Business Segments

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

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

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

The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense.

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

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

The Company’s management team and Chief Operating Decision Maker (CODM) evaluates segment performance-based on income (loss) from operations, excluding interest income and interest expense, and allocates financial and capital resources for each segment predominantly in the annual budget and forecasting process.

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

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

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

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

1 unchanged sentence

Chevron Corporation 13 % 16 % 19 %

ExxonMobil Corporation 27 % 12 % N/A

Due to the quantity of active oil and gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.

ExxonMobil Corporation 20 % 27 % 12 %

Phillips 66 10 % N/A N/A

Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.

No assets were held for sale as of December 31, 2024 and 2023.

The former U.K.

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

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

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

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

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

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

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.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

5 unchanged sentences

E&P Corporate,

Other Discontinued

Operations Consolidated

Other, and Discontinued Operations

Year ended December 31, 2024

Segment income (loss) - including NCI 1

Revenue from production

$ 2,503.8 $ 504.5 $ 6.6 $ 3,014.9 $ — $ 3,014.9

Sales of purchased natural gas

— 3.7 — 3.7 — 3.7

Gain on sales of assets and other operating income

4.5 1.5 — 6.0 3.9 9.9

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

Interest and other income (loss) ( 3.9 ) ( 1.1 ) ( 0.6 ) ( 5.6 ) ( 3.0 ) – ( 8.6 )

Interest expense, net of capitalization ( 0.1 ) ( 0.2 ) ( 0.2 ) ( 0.5 ) ( 111.9 ) – ( 112.4 )

Income tax expense (benefit) 232.7 11.2 ( 6.1 ) 237.8 ( 41.8 ) – 196.0

Significant noncash charges (credits)

Lease operating expenses

Lease operating expenses and taxes other than income

471.3 176.8 1.6 649.7 — 649.7

Repair and maintenance

63.7 4.8 — 68.5 — 68.5

Workovers 214.9 3.9 — 218.8 — 218.8

Total lease operating expenses

749.9 185.5 1.6 937.0 — 937.0

Severance and ad valorem taxes 37.8 1.4 — 39.2 — 39.2

Transportation, gathering and processing 130.9 79.9 — 210.8 — 210.8

Costs of purchased natural gas

— 3.1 — 3.1 — 3.1

Selling and general expenses ( 3.3 ) 20.4 6.7 23.8 89.1 112.9

Exploration Expenses

Geological and geophysical 14.4 0.2 12.6 27.2 — 27.2

Dry holes and previously suspended exploration costs

70.9 — 2.3 73.2 — 73.2

Other exploratory costs, including undeveloped lease amortization and delay lease rentals

10.9 0.3 21.9 33.1 — 33.1

Total exploration expenses 96.2 0.5 36.8 133.5 — 133.5

Depreciation, depletion and amortization 709.2 146.0 1.7 856.9 8.9 865.8

Impairment of assets 62.9 — — 62.9 — 62.9

Accretion of asset retirement obligations 43.1 8.6 0.7 52.4 0.1 52.5

Amortization of undeveloped leases 8.1 0.1 2.7 10.9 – – 10.9

Deferred and noncurrent income taxes 229.6 7.5 ( 6.7 ) 230.4 ( 50.6 ) – 179.8

Other operating expenses

9.3 2.8 2.1 14.2 ( 3.2 ) 11.0

Interest Income ( 22.0 ) — — ( 22.0 ) ( 12.2 ) ( 34.2 )

Interest (expense), net of capitalization 0.2 0.4 0.2 0.8 105.1 105.9

Income tax expense

Current income tax expense

1.5 3.2 0.2 4.9 0.9 5.8

Deferred income tax expense

123.8 8.8 ( 31.2 ) 101.4 ( 28.9 ) 72.5

Total income tax expense

125.3 12.0 ( 31.0 ) 106.3 ( 28.0 ) 78.3

Other segment costs (income)

6.9 0.1 0.3 7.3 ( 44.0 ) ( 36.7 )

Segment income (loss) - including NCI 1

$ 561.9 $ 49.0 $ ( 12.5 ) $ 598.4 $ ( 111.9 ) $ 486.5

Additions to property, plant, equipment $ 601.7 $ 137.9 $ 71.8 $ 811.4 $ 29.2 $ 840.6

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note S – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

Year ended December 31, 2023

Segment income (loss) - including NCI 1

Revenue from production

$ 2,921.8 $ 443.8 $ 11.0 $ 3,376.6 $ — $ 3,376.6

Sales of purchased natural gas

— 72.2 — 72.2 — 72.2

Gain on sales of assets and other operating income

6.5 1.5 — 8.0 3.3 11.3

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

Interest and other income (loss) ( 6.6 ) ( 1.9 ) ( 0.5 ) ( 9.0 ) 23.3 – 14.3

Interest expense, net of capitalization ( 0.1 ) – ( 0.3 ) ( 0.4 ) ( 150.4 ) – ( 150.8 )

Income tax expense (benefit) 370.8 43.6 2.9 417.3 ( 107.8 ) – 309.5

Significant noncash charges (credits)

Lease operating expenses

Lease operating expenses and taxes other than income

532.3 144.7 1.9 678.9 — 678.9

Repair and maintenance

53.2 5.0 — 58.2 — 58.2

Workovers 45.2 2.1 — 47.3 — 47.3

Total lease operating expenses

630.7 151.8 1.9 784.4 — 784.4

Severance and ad valorem taxes 41.4 1.4 — 42.8 — 42.8

Transportation, gathering and processing 157.0 76.0 — 233.0 — 233.0

Costs of purchased natural gas

— 51.7 — 51.7 — 51.7

Selling and general expenses 11.8 16.5 9.4 37.7 81.2 118.9

Exploration Expenses

Geological and geophysical 6.6 0.1 19.4 26.1 — 26.1

Dry holes and previously suspended exploration costs

153.1 — 16.7 169.8 — 169.8

Other exploratory costs, including undeveloped lease amortization and delay lease rentals

14.9 0.4 23.6 38.9 — 38.9

Total exploration expenses 174.6 0.5 59.7 234.8 — 234.8

Depreciation, depletion and amortization 706.0 142.2 2.3 850.5 11.0 861.5

Accretion of asset retirement obligations 37.8 7.8 0.4 46.0 0.1 46.1

Amortization of undeveloped leases 8.7 0.2 4.4 13.3 – – 13.3

Deferred and noncurrent income taxes 362.7 34.8 0.6 398.1 ( 112.0 ) – 286.1

Additions to property, plant, equipment 838.6 208.5 ( 5.7 ) 1,041.4 21.9 – 1,063.3

Total assets at year-end 6,930.6 2,125.6 217.4 9,273.6 1,034.6 0.8 10,309.0

Year ended December 31, 2021

Segment income (loss) - including NCI 1

Other operating expenses

Other miscellaneous operating expenses

20.1 15.5 8.1 43.7 ( 4.4 ) 39.3

Revenues from external customers 2,337.5 476.3 4.9 2,818.7 ( 519.4 ) – 2,299.3

Interest and other income (loss) ( 11.6 ) ( 1.9 ) 3.2 ( 10.3 ) ( 6.5 ) – ( 16.8 )

Loss on contingent consideration

7.1 — — 7.1 — 7.1

Total other operating expenses

27.2 15.5 8.1 50.8 ( 4.4 ) 46.4

Interest Income ( 3.3 ) — — ( 3.3 ) ( 9.3 ) ( 12.6 )

Interest expense, net of capitalization

0.1 0.2 0.2 0.5 111.9 112.4

Income tax expense

Current income tax expense

3.1 3.7 0.6 7.4 8.8 16.2

Deferred income tax expense

229.6 7.5 ( 6.7 ) 230.4 ( 50.6 ) 179.8

Total income tax expense

232.7 11.2 ( 6.1 ) 237.8 ( 41.8 ) 196.0

Other segment costs (income)

7.2 1.1 0.6 8.9 12.1 21.0

Segment income (loss) - including NCI 1

$ 905.1 $ 41.6 $ ( 65.5 ) $ 881.2 $ ( 157.5 ) $ 723.7

Additions to property, plant, equipment $ 671.3 $ 206.2 $ 13.1 $ 890.6 $ 24.2 $ 914.8

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

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

5 unchanged sentences

E&P Corporate,

Other Discontinued

Operations Consolidated

Income tax expense (benefit) 183.9 ( 1.7 ) ( 9.5 ) 172.7 ( 178.6 ) – ( 5.9 )

Significant noncash charges (credits)

Impairment of assets – 171.3 18.0 189.3 7.0 – 196.3

Other, and Discontinued Operations Consolidated

Year ended December 31, 2022

Revenue from production

$ 3,435.5 $ 580.0 $ 23.0 $ 4,038.5 $ — $ 4,038.5

Sales of purchased natural gas

0.2 181.5 — 181.7 — 181.7

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

25.5 1.4 — 26.9 ( 314.4 ) ( 287.5 )

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

Lease operating expenses

Lease operating expenses and taxes other than income

458.2 147.9 1.5 607.6 — 607.6

Repair and maintenance

34.9 4.7 — 39.6 — 39.6

Workovers 29.6 2.5 — 32.1 — 32.1

Total lease operating expenses

522.7 155.1 1.5 679.3 — 679.3

Severance and ad valorem taxes 55.7 1.3 — 57.0 — 57.0

Transportation, gathering and processing 142.2 70.5 — 212.7 — 212.7

Costs of purchased natural gas

0.2 171.8 — 172.0 — 172.0

Selling and general expenses 20.4 21.9 2.2 44.5 88.8 133.3

Exploration Expenses

Geological and geophysical 8.3 0.4 1.8 10.5 — 10.5

Dry holes and previously suspended exploration costs

23.0 — 59.1 82.1 — 82.1

Other exploratory costs, including undeveloped lease amortization and delay lease rentals

16.2 0.7 23.7 40.6 — 40.6

Total exploration expenses 47.5 1.1 84.6 133.2 — 133.2

Depreciation, depletion and amortization 617.0 141.5 5.4 763.9 12.9 776.8

Accretion of asset retirement obligations 36.5 9.6 0.1 46.2 — 46.2

Amortization of undeveloped leases 11.1 0.2 7.6 18.9 – – 18.9

Deferred and noncurrent income taxes 176.3 ( 1.9 ) ( 8.0 ) 166.4 ( 170.5 ) – ( 4.1 )

Other operating expenses

Other miscellaneous operating expenses

41.3 10.5 2.4 54.2 5.0 59.2

Loss on contingent consideration

78.3 — — 78.3 — 78.3

Total other operating expenses

119.6 10.5 2.4 132.5 5.0 137.5

Interest Income ( 0.3 ) — — ( 0.3 ) ( 2.5 ) ( 2.8 )

Interest expense, net of capitalization

0.1 — 0.3 0.4 150.4 150.8

Income tax expense

Current income tax expense

8.1 8.8 2.3 19.2 4.2 23.4

Deferred income tax expense

362.7 34.8 0.6 398.1 ( 112.0 ) 286.1

Total income tax expense

370.8 43.6 2.9 417.3 ( 107.8 ) 309.5

Other segment costs (income)

6.9 1.8 0.6 9.3 ( 20.8 ) ( 11.5 )

Segment income (loss) - including NCI 1

$ 1,521.9 $ 134.2 $ ( 77.0 ) $ 1,579.1 $ ( 440.4 ) $ 1,138.7

Additions to property, plant, equipment $ 838.6 $ 208.5 $ ( 5.7 ) $ 1,041.4 $ 21.9 $ 1,063.3

1 unchanged sentence

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note S – Business Segments (Continued)

Geographic Information Certain long-lived assets at December 31 1

4 unchanged sentences

2022 6,562.8 1,499.1 166.1 8,228.0

1 Certain long-lived assets at December 31 exclude investments, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

1 Certain long-lived assets at December 31 represent total non-current assets, excluding investments, right-of-use operating lease assets, non-current receivables, deferred tax assets and other intangible assets.

Note T – Leases

Nature of Leases

The Company has entered into various operating leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and natural gas field equipment.

The Company has entered into various operating and financial leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and natural gas field equipment.

Remaining lease terms range from 1 year to 16 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month.

Options to extend lease terms are at the Company’s discretion.

Early lease terminations are a combination of Company discretion and mutual agreement between the Company and lessor.

Early lease terminations are a combination of Company discretion and mutual agreement between the Company and the lessor.

Purchase options also exist for certain leases.

8 unchanged sentences

Operating lease 2

Selling and general expense 9,859 8,003

Selling and general expenses 10,990 9,859

Operating lease 2

14 unchanged sentences

2 Short-term leases due within 12 months.

For the year ended December 31, 2023, includes $ 78.2 million in LOE, $ 29.4 million for “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.

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, 2022, includes $ 62.8 million in LOE, $ 31.5 million in “Transportation, gathering and processing”, $ 8.8 million for “Exploration expenses, including undeveloped lease amortization, $ 0.7 million in “Selling and general expenses", $ 0.1 million in “Other operating expense”, $ 125.4 million in “Property, plant and equipment, net” and $ 11.2 million in “Asset retirement obligations” relating to short-term leases due within 12 months.

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.

32 unchanged sentences

Operating leases ¹ $ 349,312 $ 5,923

1 For the year ended December 31, 2023, right-of-use assets obtained in exchange for lease liabilities primarily includes $ 4.5 million related to natural gas compressor units at various U.S.

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

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

Onshore business.

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

Onshore locations.

December 31, 2022 includes $ 254.0 million related to an offshore drilling rig with a lease term of 24 months.

Note U – Subsequent Event

On January 30, 2025, the Board of Directors of Murphy Oil Corporation (NYSE:

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

The dividend is payable on March 3, 2025, to stockholders of record as of February 18, 2025.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.

The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.

Additional background information concerning some of the schedules follows:

3 unchanged sentences

SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES

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

Many assumptions and judgmental decisions are required to estimate reserves.

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

Many assumptions and judgments are required to estimate reserves.

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

The average prices used for 2023 were $ 78.22 per barrel 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 barrel for NYMEX crude oil (WTI) and $ 6.36 per MCF for natural gas (Henry Hub).

The average prices used for 2021 were $ 66.56 per barrel for NYMEX crude oil (WTI) and $ 3.60 per MCF for natural gas (Henry Hub).

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

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

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

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

11 unchanged sentences

Production quantities shown are net volumes withdrawn from reservoirs.

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

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

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

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

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

1 unchanged sentence

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVES

SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

GAAP requires calculation of future net cash flows using a 10 % annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.

12 unchanged sentences

Revisions of previous estimates ( 23.6 ) 29.0 ( 52.8 ) 0.2

Improved recovery 5.3 5.3 — —

Extensions and discoveries 80.1 20.6 59.5 —

Purchases of properties 5.0 5.0 — —

Sales of properties ( 0.7 ) – ( 0.7 ) –

Sale of properties ( 4.4 ) ( 4.4 ) — —

Production ( 63.9 ) ( 41.9 ) ( 21.7 ) ( 0.3 )

3 unchanged sentences

Extensions and discoveries 112.6 12.7 87.3 12.6

Purchases of properties 5.0 5.0 – –

Sales of properties ( 4.4 ) ( 4.4 ) – –

Sale of properties ( 5.2 ) — ( 5.2 ) —

Production ( 70.4 ) ( 45.3 ) ( 25.0 ) ( 0.1 )

3 unchanged sentences

Extensions and discoveries 31.4 16.0 15.4 —

Sales of properties ( 5.2 ) – ( 5.2 ) –

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

10 unchanged sentences

December 31, 2024 ³ 292.8 88.5 191.8 12.5

1 Includes proved reserves of 15.5 MMBOE, consisting of 14.0 MMBBL oil, 0.6 MMBBL NGLs and 5.3 BCF natural gas attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 12.8 MMBOE, consisting of 11.7 MMBBL oil, 0.5 MMBBL NGLs and 3.8 BCF natural gas attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.7 MMBOE, consisting of 2.3 MMBBL oil, 0.1 MMBBL NGLs and 1.5 BCF natural gas attributable to the noncontrolling interest in MP GOM.

1 Total and United States includes proved reserves of 15.9 MMBOE, consisting of 14.5 MMBBL of oil, 0.6 MMBBL of NGLs and 5 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 14.4 MMBOE, consisting of 13.2 MMBBL of oil, 0.5 MMBBL of NGLs and 4.2 BCF of natural gas attributable to the noncontrolling interest in MP GOM.

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

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

3 unchanged sentences

2024 Comments for Proved Equivalent Reserves Changes

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

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

Malo waterflood in the Gulf of America.

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

2023 Comments for Proved Equivalent Reserves Changes

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

1 unchanged sentence

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 Canada at Tupper Montney, the Eagle Ford Shale in the U.S., and Other international.

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

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

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

2022 Comments for Proved Equivalent Reserves Changes

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

These negative revisions were partially offset by positive well performance in the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2022, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney and Kaybob Duvernay as well as in the U.S.

at the Gulf of Mexico and Eagle Ford Shale.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S.

Gulf of Mexico and divested working interests in one field in the U.S.

Gulf of Mexico and a portion of Eagle Ford Shale.

2021 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The equivalent reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices in Tupper Montney.

These negative revisions were partially offset by positive revisions in the U.S.

from higher commodity prices, which partially reversed the 2020 capital expenditure reduction and improved well performance in the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney as well as in the U.S.

at the Eagle Ford Shale and the Gulf of Mexico.

Purchases and sales of properties - In 2021, the Company acquired incremental working interests in Terra Nova offshore Canada and in the U.S.

Gulf of Mexico.

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

6 unchanged sentences

Revisions of previous estimates 23.4 19.9 3.3 0.2

Improved recovery 4.7 4.7 — —

Extensions and discoveries 18.9 16.1 2.8 —

Purchases of properties 4.2 4.2 — —

Sale of properties

( 3.6 ) ( 3.6 ) — —

Production ( 35.5 ) ( 32.7 ) ( 2.5 ) ( 0.3 )

3 unchanged sentences

Extensions and discoveries 22.5 8.9 1.5 12.1

Purchases of properties 4.2 4.2 – –

Sales of properties ( 3.6 ) ( 3.6 ) – –

Sale of properties

( 2.0 ) — ( 2.0 ) —

Production ( 37.9 ) ( 35.6 ) ( 2.2 ) ( 0.1 )

3 unchanged sentences

Extensions and discoveries 16.6 10.7 5.9 —

Sales of properties ( 2.0 ) – ( 2.0 ) –

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

10 unchanged sentences

December 31, 2024 ³ 90.4 61.1 17.3 12.0

1 Includes total proved reserves of 14.0 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 11.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

1 Total and United States includes proved reserves of 14.5 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 13.2 MMBBL attributable to the noncontrolling interest in MP GOM.

3 Total and United States includes proved undeveloped reserves of 1.3 MMBBL attributable to the noncontrolling interest in MP GOM.

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

3 unchanged sentences

2024 Comments for Proved Crude Oil Reserves Changes

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

and performance adjustments in the Eagle Ford Shale and the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2023, proved oil reserves were added for drilling and expansion activities predominantly in the Eagle Ford Shale and Other international.

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

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

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

Malo waterflood in the Gulf of America.

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

2023 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The positive crude oil reserves revisions in 2022 resulted predominantly from improved well performance in the U.S.

Gulf of Mexico 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 U.S.

Gulf of Mexico and the Eagle Ford Shale.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S.

Gulf of Mexico and divested working interests in one field in the U.S.

Gulf of Mexico and a portion of the Eagle Ford Shale.

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

and performance adjustments in the Eagle Ford Shale and the Gulf of America.

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

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

2022 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates - The positive crude oil reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices in the U.S., which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2021, proved oil reserves were added for drilling and expansion activities predominantly in the U.S.

at the Eagle Ford Shale and the Gulf of Mexico.

Purchases and sales of properties - In 2021, the Company acquired incremental working interests in Terra Nova offshore Canada and one field in the U.S.

Gulf of Mexico.

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 4.4 3.9 0.5 —

Improved recovery 0.2 0.2 — —

Extensions and discoveries 2.5 1.9 0.6 —

Purchase of properties 0.3 0.3 — —

Sale of properties

( 0.2 ) ( 0.2 ) — —

Production ( 3.9 ) ( 3.6 ) ( 0.3 ) —

1 unchanged sentence

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 —

Purchases of properties 0.3 0.3 – –

Sales of properties ( 0.2 ) ( 0.2 ) – –

Sale of properties

( 0.6 ) — ( 0.6 ) —

Production ( 4.1 ) ( 3.8 ) ( 0.3 ) —

1 unchanged sentence

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 —

Sales of properties ( 0.6 ) – ( 0.6 ) –

Production ( 3.5 ) ( 3.3 ) ( 0.2 ) —

10 unchanged sentences

December 31, 2024 ³ 14.5 12.2 2.3 —

1 Includes total proved reserves of 0.6 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 0.5 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

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

1 Total and United States includes total proved reserves of 0.6 MMBBL attributable to the noncontrolling interest in MP GOM.

2 Total and United States includes proved developed reserves of 0.5 MMBBL attributable to the noncontrolling interest in MP GOM.

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

2 unchanged sentences

2024 Comments for Proved Natural Gas Liquids Reserves Changes

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

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

Malo waterflood in the Gulf of America.

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

2023 Comments for Proved Natural Gas Liquids Reserves Changes

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

and performance adjustments in the Eagle Ford Shale.

These revisions were partially offset by improvements in the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2023, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S.

at the Eagle Ford Shale.

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

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 U.S.

Gulf of Mexico and the Eagle Ford Shale, as well as in Canada at Kaybob Duvernay.

Extensions and discoveries - In 2022, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S.

Gulf of Mexico and the Eagle Ford Shale, as well as in Canada at Tupper Montney and Kaybob Duvernay.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S.

Gulf of Mexico and divested working interests in one field in the U.S.

Gulf of Mexico and a portion of the Eagle Ford Shale.

These revisions were partially offset by improvements in the Gulf of America.

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

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

2022 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates - The positive NGL reserves revisions in 2021 resulted predominantly from impacts of higher commodity prices, which partially reversed the 2020 capital expenditure reductions and improved well performance in the U.S.

Gulf of Mexico.

Extensions and discoveries - In 2021, proved NGL reserves were added for drilling and expansion activities predominantly in the U.S.

at Eagle Ford Shale.

Purchases and sales of properties - In 2021, the Company acquired incremental working interests in the U.S.

Gulf of Mexico.

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 ( 309.8 ) 30.7 ( 340.5 ) —

Improved recovery 2.6 2.6 — —

Extensions and discoveries 352.4 15.7 336.7 —

Purchases of properties 2.9 2.9 — —

Sales of properties ( 4.4 ) – ( 4.4 ) –

Sale of properties

( 3.6 ) ( 3.6 ) — —

Production ( 146.9 ) ( 33.7 ) ( 113.2 ) —

1 unchanged sentence

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 ( 15.6 ) — ( 15.6 ) —

2 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 —

Sales of properties ( 15.6 ) – ( 15.6 ) –

Production ( 176.1 ) ( 30.1 ) ( 146.0 ) —

12 unchanged sentences

December 31, 2024 ³ 1,127.6 92.1 1,032.7 2.8

1 Includes total proved reserves of 5.3 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 3.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 1.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

4 Includes proved natural gas reserves to be consumed in operations as fuel of 71.3 BCF, 41.9 BCF and 2.8 BCF for the U.S.

Canada and Other, respectively, with 1.2 BCF attributable to the noncontrolling interest in MP GOM.

1 Total and United States includes total proved reserves of 5.0 BCF attributable to the noncontrolling interest in MP GOM.

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

3 Total and United States includes proved undeveloped reserves of 0.8 BCF attributable to the noncontrolling interest in MP GOM.

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

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

Tab le of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL GAS INFORMATION (UNAUDITED) – Continued

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 4 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2021 – 2024 (Continued)

2024 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The negative natural gas 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 in the U.S.

Gulf of Mexico, as well as reduced royalty rates and delayed royalty incentive payouts resulting from lower commodity prices in Canada at Tupper Montney.

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

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

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

Malo waterflood in the Gulf of America.

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

2023 Comments for Proved Natural Gas Reserves Changes

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

Extensions and discoveries - In 2022, proved natural gas reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney, as well as in the U.S.

Gulf of Mexico and Eagle Ford Shale.

Purchases and sales of properties - In 2022, the Company acquired incremental working interests in two producing fields in the U.S.

Gulf of Mexico and divested working interests in one field in the U.S.

Gulf of Mexico and a portion of Eagle Ford Shale.

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

and performance adjustments in Tupper Montney and Eagle Ford Shale.

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

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

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

2022 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates - The negative natural gas reserves revisions in 2021 resulted predominantly from accelerated royalty incentive payouts due to higher commodity prices at Tupper Montney.

Extensions and discoveries - In 2021, proved equivalent reserves were added for drilling and expansion activities predominantly in Canada at Tupper Montney, as well as in the U.S.

at the Eagle Ford Shale and the Gulf of Mexico.

Purchases and sales of properties - In 2021, the Company acquired incremental working interests at Terra Nova offshore Canada and in the U.S.

Gulf of Mexico.

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

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 5 – Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Schedule 5 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

( Millions of dollars )

39 unchanged sentences

Property additions $ 838.6 $ 208.5 $ ( 5.6 ) $ 1,041.5

1 2021 Canada proved property acquisitions represents cash received from divesting partners on acquisition of an additional 7.525 % working interest at Terra Nova as part of the sanction of an asset life extension project.

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities 1

Schedule 6 – Results of Operations for Oil and Gas Producing Activities 1

( Millions of dollars )

16 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

31 unchanged sentences

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities 1 (Continued)

Schedule 6 – Results of Operations for Oil and Gas Producing Activities 1 (Continued)

( Millions of dollars )

3 unchanged sentences

Natural gas sales 225.3 312.6 — 537.9

Sales of purchased natural gas

0.2 181.5 — 181.7

Total oil and natural gas revenues 3,435.8 761.6 22.8 4,220.2

5 unchanged sentences

Transportation, gathering and processing 142.2 70.5 — 212.7

Costs of purchased natural gas 0.2 171.8 — 172.0

Exploration costs charged to expense 38.8 0.8 80.2 119.8

2 unchanged sentences

Accretion of asset retirement obligations 36.5 9.6 0.1 46.2

Impairment of assets – 171.3 18.0 189.3

Selling and general expenses 20.4 21.9 2.2 44.5

9 unchanged sentences

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

Proved Oil and Natural Gas Reserves 1

Proved Oil and Gas Reserves 1

( Millions of dollars )

29 unchanged sentences

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

Proved Oil and Natural Gas Reserves 1 (Continued)

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.

12 unchanged sentences

Net change in income taxes 298.8 1,229.6 ( 1,399.9 )

Net increase (decrease) ( 4,959.8 ) 4,514.2 4,680.4

Net (decrease) increase

( 1,457.5 ) ( 4,959.8 ) 4,514.2

Standardized measure at January 1 6,853.4 11,813.2 7,299.0

1 unchanged sentence

1 Includes noncontrolling interest in MP GOM.

2 The average prices used for 2023 were $ 78.22 per barrel 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 barrel for NYMEX crude oil (WTI) and $ 6.36 per MCF for natural gas (Henry Hub).

The average prices used for 2021 were $ 66.56 per barrel for NYMEX crude oil (WTI) and $ 3.60 per MCF for natural gas (Henry Hub).

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).

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) – Continued

Schedule 8 – Capitalized Costs Relating to Oil and Natural Gas Producing Activities

Schedule 8 – Capitalized Costs Relating to Oil and Gas Producing Activities

( Millions of dollars )

2 unchanged sentences

Unproved oil and natural gas properties 1

$ 247.3 $ 6.6 $ 29.1 $ 283.0

Proved oil and natural gas properties 16,598.8 4,498.1 246.7 21,343.6

6 unchanged sentences

Unproved oil and natural gas properties 1

$ 337.3 $ 13.1 $ 49.7 $ 400.1

Proved oil and natural gas properties 15,868.4 4,716.0 153.7 20,738.1

15 unchanged sentences

Revenue from contracts with customers $ 794.8 $ 801.0 $ 753.2 $ 669.6 $ 3,018.6

Income (loss) from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0

Income (loss) from continuing operations 214.0 92.5 278.2 140.5 725.2

Net income (loss) including noncontrolling interest 214.3 91.9 277.8 139.7 723.7

Net income (loss) attributable to Murphy 191.6 98.3 255.3 116.4 661.6

Income (loss) from continuing operations per common share ²

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

Income from continuing operations 115.5 156.9 151.7 65.2 489.3

Net income including noncontrolling interest 114.7 156.3 151.1 64.4 486.5

Net income attributable to Murphy 90.0 127.7 139.1 50.3 407.1

Income from continuing operations per common share ²

Basic 0.60 0.84 0.93 0.35 2.73

Diluted 0.60 0.83 0.93 0.34 2.72

Net income (loss) per common share ²

Net income per common share ²

Basic 0.59 0.84 0.93 0.35 2.71

3 unchanged sentences

Revenue from contracts with customers $ 840.0 $ 812.9 $ 953.8 $ 842.2 $ 3,448.9

Income (loss) from continuing operations before income taxes ( 81.9 ) 515.5 734.0 282.7 1,450.3

Income (loss) from continuing operations ( 64.9 ) 410.4 574.5 220.8 1,140.8

Net income (loss) including noncontrolling interest ( 65.5 ) 409.5 574.1 220.6 1,138.7

Net income (loss) attributable to Murphy ( 113.3 ) 350.6 528.3 199.4 965.0

Income (loss) from continuing operations per common share ²

Income from continuing operations before income taxes 267.9 127.3 356.3 169.5 921.0

Income from continuing operations 214.0 92.5 278.2 140.5 725.2

Net income including noncontrolling interest 214.3 91.9 277.8 139.7 723.7

Net income attributable to Murphy 191.6 98.3 255.3 116.4 661.6

Income from continuing operations per common share ²

Basic 1.23 0.63 1.64 0.76 4.27

Diluted 1.22 0.62 1.63 0.75 4.23

Net income (loss) per common share ²

Net income per common share ²

Basic 1.23 0.63 1.64 0.76 4.26

17 unchanged sentences

Deferred tax asset valuation allowance 111.2 24.8 — — 136.0

AECO - Alberta Energy Company and is the Canadian benchmark price for natural gas

AIP - Annual Incentive Plan

ARO - asset retirement obligation

CAD or C$ - Canadian dollar

USD or US$ - United States dollar

Units of Measurement:

BBL - Barrels

BCF - Billion cubic feet

BOE - Barrels of oil equivalent

Bureau of Ocean Energy Management

BOEPD - barrel of oil equivalent per day

Bureau of Safety and Environmental Enforcement

CAD or C$ - Canadian dollar

CRSU - cash-settled restricted time-based stock unit

DD&A - depreciation, depletion and amortization

Deepwater - offshore location in greater than 1,000 feet of water

DE&I - Diversity, Equity and Inclusion

Downstream - refining and marketing operations

Dry hole - an exploratory well that does not find oil or natural gas in commercial quantities

E&P - exploration and production

EBITDA - earnings before interest, taxes, depreciation and amortization

Environmental Protection Agency

Exploratory well - a well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive by another reservoir

FPS - floating production system

Generally Accepted Accounting Principles

GHG - greenhouse gas

Hyrdocarbons - organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products

LOE - lease operating expense

BOEPD - Barrels of oil equivalent per day

MCF - Thousand cubic feet

3 unchanged sentences

MMCF - Million cubic feet

MPGOM - MP Gulf of Mexico, LLC

NCI - noncontrolling interest

AECO - Alberta Energy Company and is the Canadian benchmark price for natural gas

Crude oil - Collectively, crude oil and condensate hydrocarbons

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

Dry hole - An exploratory well that does not find oil or natural gas in commercial quantities

E&P - Exploration and production

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

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

Liquids - Collectively, crude oil, condensate and natural gas liquid hydrocarbons

Net acres or net wells - The portions of gross acres or gross wells owned by the Company

NGL - natural gas liquid

NGLs - Natural gas liquids

NYMEX - New York Mercantile Exchange

1 unchanged sentence

Operator - The company serving as the manager and often the decision-maker of a drilling or production project

PAI - Petrobras America Inc.

PCAOB - Public Company Accounting Oversight Board

DEFINITIONS - Continued

Production Sharing Contract (PSC) - Agreement between extracting company(ies) and a host country regarding each party’s share of production after stipulated exploratory and development costs are recovered

PSU - performance-based restricted stock unit

QRE - Qualified reserve estimator

Seismic - Two-dimensional or three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons

Working interest - Right to drill and produce oil and natural gas on the leased acreage, as well as the obligation to pay costs

WTI - West Texas Intermediate

ARO - Asset retirement obligation

ASC - Accounting Standards Codification

ASU - Accounting Standards Update

DEFINITIONS - Continued

CODM - Chief Operating Decision Maker

DD&A - Depreciation, depletion and amortization

EBITDA - Earnings before interest, taxes, depreciation and amortization

FASB - Financial Accounting Standards Board

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

Environmental Protection Agency

ESG - Environmental, Social and Governance

GHG - Greenhouse gas

IRA - Inflation Reduction Act

MP GOM - MP Gulf of Mexico, LLC

PAI - Petrobras America Inc.

PSU - Performance-based restricted stock unit

RCF - Revolving credit facility

ROACE - Return on average capital employed

RSU - Time-based restricted stock unit

SAR - Stock appreciation right

SEAL - Sergipe-Alagoas Basin

Securities and Exchange Commission

Seismic - two-dimensional or three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons

SOFR - Secured Overnight Financing Rate

TCFD - Task Force on Climate-related Financial Disclosures

Upstream - oil and natural gas exploration and production operations, including synthetic oil operations

USD - United States dollar

VIE - variable interest entity

Working interest - right to drill and produce oil and natural gas on the leased acreage, as well as the obligation to pay costs

WTI - West Texas Intermediate

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