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Item 1. Financial Statements

2025-08-06 compared with 2025-05-07 · 521 added, 261 removed, 995 unchanged (44% of the section changed)

2 unchanged sentences

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars, except share amounts) March 31,

(Thousands of dollars, except share amounts) June 30,

2025 December 31,

42 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Thousands of dollars, except per share amounts) 2025 2024 2025 2024

3 unchanged sentences

Total revenue from sales to customers 683,065 801,007 1,355,795 1,595,855

(Loss) on derivative instruments ( 9,459 ) —

Gain on derivative instruments 10,808 — 1,349 —

Gain on sale of assets and other operating income 1,697 1,764 4,137 3,328

10 unchanged sentences

Impairment of assets — — — 34,528

Other operating expense 5,629 7,266

Other operating expense (income) 1,833 ( 2,219 ) 7,462 5,047

Total costs and expenses 603,359 618,449 1,125,176 1,260,804

1 unchanged sentence

Other income (loss)

Other income 2,402 11,551

Other income (loss) ( 32,304 ) 26,245 ( 29,902 ) 37,796

Interest expense, net ( 25,053 ) ( 20,986 ) ( 48,576 ) ( 41,007 )

Total other loss ( 21,121 ) ( 8,470 )

Total other income (loss) ( 57,357 ) 5,259 ( 78,478 ) ( 3,211 )

Income from continuing operations before income taxes 34,854 189,581 157,627 335,168

1 unchanged sentence

Income from continuing operations 33,822 156,905 123,873 272,435

Loss from discontinued operations, net of income taxes ( 633 ) ( 872 )

Income (loss) from discontinued operations, net of income taxes 1,302 ( 643 ) 669 ( 1,515 )

Net income including noncontrolling interest 35,124 156,262 124,542 270,920

17 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Thousands of dollars) 2025 2024 2025 2024

12 unchanged sentences

CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended

Six Months Ended

(Thousands of dollars) 2025 2024

3 unchanged sentences

Depreciation, depletion and amortization 453,484 426,677

Deferred income tax expense 16,343 19,478

Accretion of asset retirement obligations 28,477 25,827

Long-term non-cash compensation 22,016 21,823

Mark-to-market loss on derivative instruments

Deferred income tax expense 21,216 53,928

Amortization of undeveloped leases 3,909 5,778

Loss from discontinued operations

Mark-to-market loss on derivative instruments

Unsuccessful exploration well costs and previously suspended exploration costs ( 776 ) 58,280

(Income) loss from discontinued operations

( 669 ) 1,515

Impairment of assets — 34,528

Other operating activities, net ( 2 ) ( 33,959 )

Net (increase) in non-cash working capital

( 22,784 ) ( 24,353 )

Net decrease in non-cash working capital

Net cash provided by continuing operations activities 658,731 866,443

6 unchanged sentences

Repayment of revolving credit facility ( 150,000 ) ( 200,000 )

Retirement of debt — ( 50,000 )

Repurchase of common stock ( 102,620 ) ( 105,887 )

3 unchanged sentences

Finance lease obligation payments ( 486 ) ( 331 )

Net cash provided (required) by financing activities

Issue costs of revolving debt facility

Net cash required by financing activities

( 22,355 ) ( 334,271 )

8 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Thousands of dollars except number of shares) 2025 2024 2025 2024

Balance at beginning and end of period – par $ 1.00 , authorized 450,000,000 shares at March 31, 2025 and March 31, 2024, issued 195,100,628 shares at March 31, 2025 and March 31, 2024

Balance at beginning and end of period – par $ 1.00 , authorized 450,000,000 shares at June 30, 2025 and June 30, 2024, issued 195,100,628 shares at June 30, 2025 and June 30, 2024

$ 195,101 $ 195,101 $ 195,101 $ 195,101

31 unchanged sentences

Note A – Basis of Presentation

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at March 31, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2025 and 2024, in conformity with U.S.

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at June 30, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2025 and 2024, in conformity with U.S.

generally accepted accounting principles (GAAP).

2 unchanged sentences

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2024 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.

Financial results for the three-month period ended March 31, 2025 are not necessarily indicative of future results.

Financial results for the three-month and six-month periods ended June 30, 2025 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

42 unchanged sentences

Note C - Revenue from Contracts with Customers (Continued)

The Company’s revenues and other income for the three-month periods ended March 31, 2025 and 2024 were as follows.

The Company’s revenues and other income for the three-month and six-month periods ended June 30, 2025 and 2024 were as follows.

Three Months Ended

June 30, Six Months Ended

(Thousands of dollars) 2025 2024 2025 2024

12 unchanged sentences

United States - Onshore

9,893 7,311 18,380 15,147

United States - Offshore 1

8,311 9,337 17,560 19,711

Canada - Onshore

1,523 1,595 3,270 3,032

Total natural gas liquids revenue 19,727 18,243 39,210 37,890

1 unchanged sentence

United States - Onshore

8,099 3,352 16,066 7,628

United States - Offshore 1

6 unchanged sentences

Canada - Onshore

— 3,497 — 3,742

Total sales of purchased natural gas — 3,497 — 3,742

Total revenue from sales to customers 683,065 801,007 1,355,795 1,595,855

(Loss) on derivative instruments ( 9,459 ) —

Gain on derivative instruments 10,808 — 1,349 —

Gain on sale of assets and other operating income 1,697 1,764 4,137 3,328

5 unchanged sentences

Contract Balances and Asset Recognition

As of March 31, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 203.7 million and $ 178.3 million, respectively.

As of June 30, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 172.2 million and $ 178.3 million, respectively.

Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing.

Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as of March 31, 2025.

The Company has not entered into any revenue contracts that have financing components as of June 30, 2025.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts.

10 unchanged sentences

The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.

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

As of June 30, 2025, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:

Location Commodity End Date Description Approximate Volumes

6 unchanged sentences

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

Canada NGLs Q4 2026

Contracts to sell NGLs at CAD index pricing As produced

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

2 unchanged sentences

Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

As of March 31, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 96.8 million.

The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2025 and 2024.

As of June 30, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 110.5 million.

The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2025 and 2024.

(Thousands of dollars) 2025 2024

2 unchanged sentences

Capitalized exploratory well costs charged to expense — ( 26,471 )

Balance at March 31 $ 96,845 $ 34,185

Capital additions of $ 24.8 million, for the quarter ended March 31, 2025, are mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam and long-lead equipment for the Cello #1 and Banjo #1 exploration wells (Mississippi Canyon 385) in the Gulf of America.

The Lac Da Hong-1X (Pink Camel) exploration well in Vietnam encountered 106 feet of net oil pay from one reservoir.

There were no capitalized well costs charged to dry hole expense for the three months ended

Balance at June 30 $ 110,524 $ 43,038

Capital additions of $ 38.5 million, for the six months ended June 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam and long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

March 31, 2025.

Capitalized well costs charged to dry hole expense of $ 26.5 million for the three months ended March 31, 2024 were related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America.

The preceding table excludes well costs of $ 0.2 million and $ 5.9 million incurred and expensed directly to dry hole for the three months ended March 31, 2025 and 2024, respectively.

In 2025, the amount primarily relates to the finalization of previous dry hole wells, and in 2024, the amount primarily relates to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

additions of $ 20.4 million, for the six months ended June 30, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America.

There were no capitalized well costs charged to dry hole expense for the six months ended June 30, 2025.

Capitalized well costs charged to dry hole expense of $ 26.5 million for the six months ended June 30, 2024 were related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America.

The preceding table excludes well costs of $ 31.8 million incurred and expensed directly to dry hole for the six months ended June 30, 2024.

This amount primarily related to the non-operated Orange #1 (Mississippi Canyon 216) exploration well in the Gulf of America.

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

7 unchanged sentences

$ 110,524 11 $ 43,038 6

Of the $ 87.4 million of exploration well costs capitalized more than one year at March 31, 2025, $ 59.0 million was in Vietnam, $ 21.2 million was in the Gulf of America, $ 4.4 million was in Canada, and $ 2.7 million was in Brunei.

Of the $ 94.5 million of exploration well costs capitalized and classified as more than one year at June 30, 2025, $ 65.0 million was in Vietnam, $ 22.1 million was in the Gulf of America, $ 4.7 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.

1 unchanged sentence

During the first quarter of 2025, Murphy purchased a floating production storage and offloading vessel (FPSO) from BW Offshore (UK) Limited for a gross purchase price of $ 125.0 million, subject to customary closing adjustments.

This acquisition includes an initial $ 100.0 million payment in the first quarter of 2025.

The remaining balance will be due when certain contractual obligations are met, which is expected by the end of the second quarter of 2025.

An initial payment of $ 100.0 million was made in the first quarter of 2025, with the remaining balance paid during the second quarter of 2025, after certain contractual obligations were met.

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

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

There were no impairments in the three months ended March 31, 2025.

There were pretax impairments of $ 34.5 million in the three months ended March 31, 2024 related to the Calliope fie ld in Mississippi Canyon in the Gulf of America, in which operational issues led to a reserve reduction.

There were no impairments in the three and six months ended June 30, 2025, as well as no impairments in the three months ended June 30, 2024.

There were pretax impairments of $ 34.5 million in the six months ended June 30, 2024 related to the Calliope fie ld in Mississippi Canyon in the Gulf of America, in which operational issues led to a reserve reduction.

Subsequent Event

Subsequent to quarter end, on July 1, 2025, the Company purchased additional working interests in Eagle Ford Shale, in acreages primarily operated by Murphy, for $ 23.0 million, subject to certain post-closing adjustments.

Note E – Financing Arrangements and Debt

As of March 31, 2025, the Company had a $ 1.35 billion revolving credit facility (RCF).

As of June 30, 2025, the Company had a $ 1.35 billion revolving credit facility (RCF).

The RCF is a senior unsecured guaranteed facility which expires on October 7, 2029.

At March 31, 2025, the Company had $ 200.0 million of outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At March 31, 2025, the interest rate in effect on borrowings under the RCF was 6.67 %.

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

At June 30, 2025, the Company had $ 200.0 million of outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At June 30, 2025, the interest rate in effect on borrowings under the RCF was 6.67 %.

At June 30, 2025, the Company was in compliance with all covenants related to the RCF.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt (Continued)

The Company also has a shelf registration statement on file with the U.S.

Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2027.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows

Three Months Ended

Six Months Ended

(Thousands of dollars) 2025 2024

5 unchanged sentences

Increase (decrease) in income taxes payable 4,789 ( 1,006 )

Net (increase) in non-cash working capital $ ( 22,784 ) $ ( 24,353 )

Net decrease in non-cash working capital $ 7,905 $ 1,126

Supplementary disclosures:

1 unchanged sentence

Interest paid, net of amounts capitalized of $ 2.9 million in 2025 and $ 7.8 million in 2024

44,577 38,262

Non-cash investing activities:

3 unchanged sentences

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

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the three-month periods ended March 31, 2025 and 2024 are shown in the following table.

(Thousands of dollars) March 31, 2025 March 31, 2024

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the six-month periods ended June 30, 2025 and 2024 are shown in the following table.

(Thousands of dollars) June 30, 2025 June 30, 2024

Balance at beginning of year $ 1,008,884 $ 914,763

22 unchanged sentences

the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2025 and 2024.

Three Months Ended March 31,

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2025 and 2024.

Three Months Ended June 30,

Pension Benefits Other Postretirement Benefits

7 unchanged sentences

Total net periodic benefit expense $ 3,680 $ 4,734 $ ( 398 ) $ ( 28 )

The components of net periodic benefit expense, other than the service cost, are recorded in “Other income” in the Consolidated Statements of Operations.

During the three-month period ended March 31, 2025, the Company made contributions of $ 7.3 million to its defined benefit pension and postretirement benefit plans.

Six Months Ended June 30,

Pension Benefits Other Postretirement Benefits

(Thousands of dollars) 2025 2024 2025 2024

Service cost $ 3,366 $ 3,412 $ 168 $ 270

Interest cost 16,880 16,784 1,416 1,564

Expected return on plan assets ( 17,824 ) ( 16,716 ) — —

Estimated defined contribution provision 122 109 — —

Amortization of prior service cost (credit) 983 1,158 ( 266 ) ( 266 )

Recognized actuarial loss (gain) 3,805 4,721 ( 2,113 ) ( 1,624 )

Total net periodic benefit expense $ 7,332 $ 9,468 $ ( 795 ) $ ( 56 )

The components of net periodic benefit expense, other than the service cost, are recorded in “Other income (loss)” in the Consolidated Statements of Operations.

During the six-month period ended June 30, 2025, the Company made contributions of $ 18.6 million to its defined benefit pension and postretirement benefit plans.

Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 12.3 million.

Note I – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

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

Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s common stock and stock-based awards to employees.

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

The 2020 Long-Term Plan expires in 2030.

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

Shares issued pursuant to awards granted under the 2020 Long-Term Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market.

Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the 2020 Long-Term Plan.

In addition, the 2020 Long-Term Plan authorizes the Committee to grant cash-settled equity awards to employees.

These cash-settled RSU awards do not require issuance of the Company’s common stock, are time-based, and generally vest on the third anniversary of the date of grant.

The Company recognizes expenses for all share-based and cash-based incentive compensation in the Consolidated Statements of Operations using a fair value-based measurement method over the applicable vesting periods.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

During the three months ended March 31, 2025, the Committee granted the following awards from the 2020 Long-Term Plan:

other employees.

Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

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

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

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

Additional information on the 2025 Long-Term Plan can be found in Exhibit A to definitive proxy statement filed on March 28, 2025 .

Similar to the 2020 Long-Term Plan, the 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock and stock-based awards to employees.

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

Shares issued pursuant to awards granted under the 2025 Long-Term Plan and the previous 2020 Long-Term Plan, may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares repurchased on the open market.

Share awards that have been canceled, expired, forfeited, or otherwise not issued will not count as shares issued under both plans.

During the six months ended June 30, 2025, the Committee granted the following awards from the 2020 Long-Term Plan:

Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology

9 unchanged sentences

2 Time-based RSUs generally vest on the third anniversary of the date of grant.

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.

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.

During the three months ended March 31, 2025, the Committee granted the following awards to NEDs under the 2021 NED Plan:

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

During the six months ended June 30, 2025, the Committee granted the following awards to NEDs under the 2021 NED Plan:

Type of Award Number of Awards Granted Grant Date Grant Date Fair Value Valuation Methodology

3 unchanged sentences

2,114 March 31, 2025 $ 28.40 Closing Stock Price

Time-Based RSUs 2

2,668 June 30, 2025 $ 22.50 Closing Stock Price

1 NED’s time-based RSUs are scheduled to vest on the first anniversary of the date of grant.

5 unchanged sentences

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.

Three Months Ended

Six Months Ended

(Thousands of dollars) 2025 2024

2 unchanged sentences

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $ 1.0 million per executive per year, is not eligible for a U.S.

income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

income tax deduction under the current tax law.

Note J – Net Income (Loss) Per Common Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month periods ended March 31, 2025 and 2024.

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month and six-month periods ended June 30, 2025 and 2024.

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

Three Months Ended

June 30, Six Months Ended

(Weighted-average shares) 2025 2024 2025 2024

Basic method 142,720,904 152,153,401 143,502,425 152,408,912

Dilutive stock options and restricted stock units 788,142 1,152,204

Dilutive restricted stock units 494,710 990,183 641,426 1,070,766

Diluted method 143,215,614 153,143,584 144,143,851 153,479,678

1 unchanged sentence

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes.

For the three-month periods ended March 31, 2025 and 2024, the Company’s effective income tax rates were as follows:

Three months ended March 31, 26.7 % 20.6 %

The effective tax rate for the three-month period ended March 31, 2025 was above the U.S.

For the three-month and six-month periods ended June 30, 2025 and 2024, the Company’s effective income tax rates were as follows:

Three months ended June 30, 3.0 % 17.2 %

Six months ended June 30, 21.4 % 18.7 %

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

The effective tax rate for the three-month period ended June 30, 2025 was below the U.S.

statutory tax rate of 21% primarily due to several factors including:

no tax applied to the pretax income of the noncontrolling interest in MP GOM, a Canada tax credit received, and the effects of tax losses generated in Canada which has a higher tax rate.

These impacts are partially offset by exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available as well as stock-based compensation.

The effective tax rate for the three-month period ended June 30, 2024 was below the U.S.

statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.

These impacts are partially offset by the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S.

Federal rate, and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

The effective tax rate for the six-month period ended June 30, 2025 was above the U.S.

statutory tax rate of 21% primarily due to several factors including:

the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S.

3 unchanged sentences

and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.

The effective tax rate for the three-month period ended March 31, 2024 was below the U.S.

statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and partially offset by several factors, including:

These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.

The effective tax rate for the six-month period ended June 30, 2024 was below the U.S.

statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.

These impacts were partially offset by several factors including:

the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S.

Federal rate;

state tax expense;

and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

state tax expense and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

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

2 unchanged sentences

Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities.

As of March 31, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:

As of June 30, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:

Canada – 2016;

1 unchanged sentence

The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

Subsequent to the balance sheet date, on July 4, 2025, the current U.S.

Administration signed into law the legislation commonly referred to as the One Big Beautiful Bill Act (OBBBA), which includes a broad range of tax reform provisions affecting corporations.

The OBBBA, among other changes, permanently reinstates the "bonus" depreciation provisions that allow for the immediate expensing of 100% of the cost of certain qualified property acquired and placed in service after January 19, 2025, permanently reinstates the elective immediate expensing of domestic research and experimental expenditures paid or incurred in tax years beginning after December 31, 2024 (with a special transition rule that allows accelerated deduction of the remaining unamortized balance of capitalized domestic research and experimental expenditures), and permanently relaxes the limitation on the deductibility of business interest effective for tax years beginning after December 31, 2024.

The OBBBA also modifies certain international tax provisions effective for tax years beginning after December 31, 2025.

The Company is currently evaluating the impact of these tax law changes and will recognize the income tax effects in the consolidated financial statements beginning in the period in which the OBBBA was signed into law.

Note L – Financial Instruments and Risk Management

2 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 (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

Derivative instruments are traded with creditworthy major financial institutions or over national

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.

exchanges such as the New York Mercantile Exchange (NYMEX).

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

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

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.

The Company had no foreign currency exchange derivatives outstanding at March 31, 2025 and 2024.

The Company had no foreign currency exchange derivatives outstanding at June 30, 2025 and 2024.

Commodity Price Risks

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

During the three months ended March 31, 2025, the Company entered into natural gas swap contracts.

During the second quarter of 2025, the Company had the following open natural gas swap contracts.

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

At March 31, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

At June 30, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

NYMEX Henry Hub

2 unchanged sentences

Fixed price derivative swap United States Natural Gas 60 $ 3.74 10/1/2025 12/31/2025

At March 31, 2024, the Company did no t have any crude oil or natural gas derivative contracts.

At March 31, 2025 and December 31, 2024, the fair value of derivative instruments not designated as hedging instruments are presented in the following table:

During first six months ended June 30, 2025, the Company did no t have any crude oil derivative contracts.

During first six months ended June 30, 2024, the Company did no t have any crude oil or natural gas derivative contracts.

At June 30, 2025 and December 31, 2024, the fair value of derivative instruments not designated as hedging instruments are presented in the following table:

(Thousands of dollars) Asset (Liability) Derivatives Fair Value

Type of Derivative Contract Balance Sheet Location March 31, 2025 December 31, 2024

Type of Derivative Contract Balance Sheet Location June 30, 2025 December 31, 2024

Commodity swaps Accounts payable $ ( 337 ) $ ( 1,707 )

For the three-month periods ended March 31, 2025 and 2024, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:

(Thousands of dollars) Three Months Ended March 31,

For the three-month and six-month periods ended June 30, 2025 and 2024, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:

Gain (Loss) Gain (Loss)

(Thousands of dollars) Three Months Ended

June 30, Six Months Ended June 30,

Type of Derivative Contract Statement of Operations Location 2025 2024 2025 2024

Commodity swaps Loss on derivative instruments $ ( 9,459 ) $ —

Commodity swaps Gain on derivative instruments $ 10,808 $ — $ 1,349 $ —

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Fair Values – Recurring

4 unchanged sentences

Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The fair value measurements for these assets and liabilities at March 31, 2025 and December 31, 2024, are shown in the following table:

March 31, 2025 December 31, 2024

The fair value measurements for these assets and liabilities at June 30, 2025 and December 31, 2024, are shown in the following table.

June 30, 2025 December 31, 2024

(Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total

2 unchanged sentences

$ 19,763 $ 337 $ — $ 20,100 $ 19,469 $ 1,707 $ — $ 21,176

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

The commodity swaps liability as of March 31, 2025 was $ 8.9 million and recorded as “Accounts payable” in the Consolidated Balance Sheets.

The commodity swaps liability as of June 30, 2025 was $ 0.3 million and recorded as “Accounts payable” in the Consolidated Balance Sheets.

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

4 unchanged sentences

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

There were no offsetting positions recorded at March 31, 2025 and December 31, 2024.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at March 31, 2025 and December 31, 2024.

There were no offsetting positions recorded at June 30, 2025 and December 31, 2024.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at June 30, 2025 and December 31, 2024.

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties.

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

March 31, December 31,

June 30, 2025 December 31, 2024

(Thousands of dollars) Carrying

4 unchanged sentences

Fair Values – Nonrecurring

There were no impairment expenses incurred in the first quarter of 2025.

In the first quarter of 2024, an impairment charge of $ 34.5 million was triggered for the Calliope field, due to operational issues that led to reserve reductions.

There were no impairment expenses incurred in the three and six months ended June 30, 2025 or the three months ended June 30, 2024.

In the six months ended June 30, 2024, an impairment charge of $ 34.5 million was triggered for the Calliope field, due to operational issues that led to reserve reductions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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.

Three Months Ended March 31, 2024

Six Months Ended June 30, 2024

Impairment Total

1 unchanged sentence

Level 1 Level 2 Level 3

Property, plant and equipment:

Impaired proved properties

1 unchanged sentence

$ — $ — $ 437 $ 34,965 $ 34,528

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2024 and March 31, 2025 and the changes during the three-month periods ended March 31, 2025 are presented net of taxes in the following table.

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2024 and June 30, 2025 and the changes during the six-month period ended June 30, 2025 are presented net of taxes in the following table.

(Thousands of dollars) Foreign

6 unchanged sentences

Net other comprehensive income (loss) 88,555 1,739 90,294

Balance at March 31, 2025 $ ( 517,991 ) $ ( 110,884 ) $ ( 628,875 )

1 Reclassifications before taxes of $ 1.0 million are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2025.

Balance at June 30, 2025 $ ( 427,769 ) $ ( 110,009 ) $ ( 537,778 )

1 Reclassifications before taxes of $ 2.1 million are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2025.

See Note H for additional information.

Related income taxes of $ 0.2 million are included in "Income tax expense” on the Consolidated Statements of Operations for the three-month period ended March 31, 2025.

Related income taxes of $ 0.3 million are included in "Income tax expense” on the Consolidated Statements of Operations for the six-month period ended June 30, 2025.

Note N – Environmental and Other Contingencies

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

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

The 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

products, wastewater and hazardous materials;

the emission and discharge of such materials to the environment, including methane and other greenhouse gas (GHG) emissions;

8 unchanged sentences

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

Pursuant to SEC amendments to this

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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

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

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

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

This rule was disapproved by a joint Congressional resolution in March 2025.

This rule, however, was disapproved by a joint Congressional resolution in March 2025.

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

Although the U.S.

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

rejoined the Paris Agreement in 2021.

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

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

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

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

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

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

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

However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note O – Common Stock Issued and Outstanding

Activity in the number of shares of common stock issued and outstanding for the three-month periods ended March 31, 2025 and 2024 is shown below.

Activity in the number of shares of common stock issued and outstanding for the six-month periods ended June 30, 2025 and 2024 is shown below.

( Number of shares outstanding )

March 31, 2025 March 31, 2024

June 30, 2025 June 30, 2024

Beginning of period 145,845,124 152,748,642

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

During the three months ended March 31, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $ 100.0 million ($ 100.9 million including excise taxes and fees).

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

During the three months ended June 30, 2025, the Company did no t repurchase any share of its common stock.

During the six months ended June 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $ 100.0 million ($ 100.9 million including excise taxes and fees).

As of June 30, 2025, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program.

Note P – Business Segments

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Other, and Discontinued Operations

Three Months Ended March 31, 2025

Three Months Ended June 30, 2025

Revenue from production

$ 552.2 $ 127.9 $ 2.9 $ 683.0 $ — $ 683.0

Sales of purchased natural gas

Gain on sales of assets and other operating income

26 unchanged sentences

Interest expense, net of capitalization

— 0.2 — 0.2 24.9 25.1

Income tax expense

Current income tax expense

Current income tax expense (benefit)

0.7 0.3 0.2 1.2 ( 5.0 ) ( 3.8 )

1 unchanged sentence

19.2 ( 2.2 ) ( 0.7 ) 16.3 ( 11.5 ) 4.8

Total income tax expense

Total income tax expense (benefit)

19.9 ( 1.9 ) ( 0.5 ) 17.5 ( 16.5 ) 1.0

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Other, and Discontinued Operations Consolidated

Three Months Ended March 31, 2024

Three Months Ended June 30, 2024

Revenue from production

32 unchanged sentences

Interest expense, net of capitalization — 0.1 — 0.1 20.8 20.9

Income tax expense

Current income tax expense (benefit)

1.1 ( 3.5 ) 0.3 ( 2.1 ) 0.3 ( 1.8 )

Deferred income tax expense (benefit)

42.7 ( 0.7 ) 0.6 42.6 ( 8.2 ) 34.4

Total income tax expense (benefit)

43.8 ( 4.2 ) 0.9 40.5 ( 7.9 ) 32.6

Other segment costs (income)

1.8 ( 0.3 ) 0.1 1.6 ( 4.2 ) ( 2.6 )

Segment income (loss) - including NCI 1

$ 185.7 $ 8.9 $ ( 10.1 ) $ 184.5 $ ( 28.3 ) $ 156.2

Additions to property, plant, equipment $ 195.2 $ 42.1 $ 12.1 $ 249.4 $ 4.3 $ 253.7

Total assets at quarter-end

7,222.6 2,050.5 244.2 9,517.3 376.4 9,893.7

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations

Six Months Ended June 30, 2025

Revenue from production

$ 1,059.7 $ 293.2 $ 2.9 $ 1,355.8 $ — $ 1,355.8

Gain on sales of assets and other operating income

3.3 0.8 — 4.1 3.6 7.7

Revenues from external customers 1,063.0 294.0 2.9 1,359.9 3.6 1,363.5

Lease operating expenses

Lease operating expenses and taxes other than income

200.3 91.9 1.2 293.4 — 293.4

Repair and maintenance

24.1 2.6 — 26.7 — 26.7

Workovers 99.7 0.8 — 100.5 — 100.5

Total lease operating expenses

324.1 95.3 1.2 420.6 — 420.6

Severance and ad valorem taxes 18.8 0.7 — 19.5 — 19.5

Transportation, gathering and processing 59.0 43.9 — 102.9 — 102.9

Costs of purchased natural gas

Selling and general expenses 6.8 11.7 4.5 23.0 44.8 67.8

Exploration Expenses

Geological and geophysical 3.9 — 0.5 4.4 — 4.4

Dry holes and previously suspended exploration costs

( 0.8 ) — 0.1 ( 0.7 ) — ( 0.7 )

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

6.3 0.1 14.8 21.2 — 21.2

Total exploration expenses 9.4 0.1 15.4 24.9 — 24.9

Depreciation, depletion and amortization 377.6 70.5 1.3 449.4 4.1 453.5

Accretion of asset retirement obligations 23.0 5.1 0.4 28.5 — 28.5

Other operating expenses

4.0 1.7 ( 1.3 ) 4.4 3.1 7.5

Interest Income ( 0.9 ) — — ( 0.9 ) ( 6.0 ) ( 6.9 )

Interest expense, net of capitalization

— — 0.1 0.1 48.5 48.6

Income tax expense

Current income tax expense (benefit)

1.3 14.0 0.2 15.5 ( 2.9 ) 12.6

Deferred income tax expense (benefit)

43.7 ( 1.6 ) ( 0.7 ) 41.4 ( 20.2 ) 21.2

Total income tax expense (benefit)

45.0 12.4 ( 0.5 ) 56.9 ( 23.1 ) 33.8

Other segment cost

1.8 0.6 0.3 2.7 35.6 38.3

Segment income (loss) - including NCI 1

$ 194.4 $ 52.0 $ ( 18.5 ) $ 227.9 $ ( 103.4 ) $ 124.5

Additions to property, plant, equipment $ 493.2 $ 101.1 $ 56.1 $ 650.4 $ 7.0 $ 657.4

Total assets at quarter-end

6,984.9 2,038.6 364.4 9,387.9 451.6 9,839.5

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

Six Months Ended June 30, 2024

Revenue from production

$ 1,336.5 $ 251.5 $ 4.2 $ 1,592.2 $ — $ 1,592.2

Sales of purchased natural gas

— 3.7 — 3.7 — 3.7

Gain on sales of assets and other operating income

2.6 0.7 — 3.3 — 3.3

Revenues from external customers 1,339.1 255.9 4.2 1,599.2 — 1,599.2

Lease operating expenses

Lease operating expenses and taxes other than income

240.6 90.4 0.7 331.7 — 331.7

Repair and maintenance

26.8 1.4 — 28.2 — 28.2

Workovers 131.5 2.5 — 134.0 — 134.0

Total lease operating expenses

398.9 94.3 0.7 493.9 — 493.9

Severance and ad valorem taxes 19.8 0.7 — 20.5 — 20.5

Transportation, gathering and processing 70.8 39.2 — 110.0 — 110.0

Costs of purchased natural gas

— 3.1 — 3.1 — 3.1

Selling and general expenses ( 3.5 ) 9.6 3.0 9.1 45.0 54.1

Exploration Expenses

Geological and geophysical 3.7 0.1 5.9 9.7 — 9.7

Dry holes and previously suspended exploration costs

57.1 — 1.2 58.3 — 58.3

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

7.1 — 12.0 19.1 — 19.1

Total exploration expenses 67.9 0.1 19.1 87.1 — 87.1

Depreciation, depletion and amortization 349.0 71.3 0.9 421.2 5.5 426.7

Impairment of assets 34.5 — — 34.5 — 34.5

Accretion of asset retirement obligations 21.1 4.3 0.4 25.8 — 25.8

Other operating expenses 3.2 2.0 0.1 5.3 ( 0.3 ) 5.0

Interest Income ( 20.8 ) — — ( 20.8 ) ( 5.5 ) ( 26.3 )

Interest expense, net of capitalization

— 0.2 0.1 0.3 40.7 41.0

Income tax expense

Current income tax expense

13 unchanged sentences

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended March 31, 2025 included under “ Item 1 .

Financial Statements ” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2024.

2 unchanged sentences

Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities.

The Company has more than a century-long history of demonstrating strong execution and innovative, full-cycle development capabilities with a focus on value creation that drives shareholder returns.

The Company boasts over a century of strong execution and innovative, full-cycle development capabilities, with a focus on value creation to enhance shareholder returns.

The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada.

1 unchanged sentence

The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

Significant Company financial and operational highlights during the first quarter of 2025 were as follows:

• Drilled an oil discovery at Lac Da Hong-1X (Pink Camel) in offshore Vietnam and encountered 106 feet of net oil pay from one reservoir

• Closed the strategic acquisition of the BW Pioneer FPSO in the Gulf of America for $125.0 million gross purchase price

• Paid quarterly dividend of $0.325 per share or $1.30 per share annualized

• Repurchased $100.0 million ($100.9 million including excise taxes and fees) of common stock, or 3.6 million shares

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2025, was $90.0 million, a decrease of $25.6 million compared to the same period of 2024.

Lower net income from continuing operations was largely driven by lower revenues from production ($121.9 million) and was partially offset by lower impairment of assets ($34.5 million), lower exploration expenses ($29.9 million), and lower lease operating expenses ($29.2 million).

Lower revenues were primarily driven by lower crude oil production in the U.S., resulting from workover and turnaround-related downtime, and well performance, combined with lower crude oil prices.

This was partially offset by increased crude oil sales at Canada Offshore, as 2024 had lower production build-up following the completion of the non-operated Terra Nova asset life extension project.

In 2024, there were asset impairment charges relating to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

Lower lease operating expenses were primarily driven by lower sales volumes in the U.S.

and lower operating costs at the non-operated Terra Nova field as 2024 had higher asset restart costs, partially offset by increased sales volumes at the non-operated Terra Nova field.

Exploration expenses decreased in 2025, as 2024 had additional expenses for dry holes and previously suspended exploration costs relating to Hoffe Park #1 (Mississippi Canyon 166) exploration well and costs related to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

For the three months ended March 31, 2025, total hydrocarbon production was 163,374 barrels of oil equivalent per day, a decrease of 8% compared to the first quarter of 2024.

The decrease was principally due to lower production in the U.S., partially offset by higher production in Canada.

Decreases in the Gulf of America resulted from workover and turnaround-related downtime, and well performance, while decreases in the Eagle Ford Shale were due to natural decline and well downtime related to workovers and winter weather.

Significant Company financial and operational highlights during the second quarter of 2025 were as follows:

• Increased production to 196,315 barrels of oil equivalent (BOE) per day (including NCI), up from 187,847 BOE per day in the second quarter of 2024, and up from 163,374 BOE per day in the first quarter of 2025

• Paid quarterly dividend of $46.4 million ($0.325 per share, or $1.30 per share annualized)

Subsequent to the second quarter of 2025:

• Closed an acquisition of additional working interests in Eagle Ford Shale, in acreages primarily operated by Murphy, for a gross purchase price of $23.0 million

• Declared a quarterly dividend of $0.325 per share or $1.30 per share annualized

• Signed a rig contract for our upcoming Côte d’Ivoire three-well exploration program

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2025, was $33.8 million, a decrease of $123.1 million compared to the same period in 2024.

Lower net income from continuing operations was driven primarily by lower revenues from production ($114.4 million), lower other income ($58.5 million), and higher depreciation, depletion and amortization expenses (DD&A) ($43.8 million).

These decreases were partially offset by lower lease operating expenses ($44.1 million), lower exploration expenses ($32.3 million), and lower income tax expenses ($31.6 million).

Lower revenues during the quarter were the result of lower oil prices partially offset by higher production volumes.

Lower other income was the result of unrealized foreign exchange losses and no repeat of prior year interest income on joint interest receivables.

Higher DD&A was due to higher overall production.

Lower lease operating expenses were caused primarily by less workover expenses in the current period and lower production handling fees related to lower Gulf of America production.

Lower exploration expenses were due to no dry holes recorded in 2025 (2024:

non-operated Orange #1 (Mississippi Canyon 216) exploration well), and lower income tax expenses were driven by lower net income.

For the three months ended June 30, 2025, total hydrocarbon production was 196,315 barrels of oil equivalent per day, an increase of 5% compared to the second quarter of 2024.

The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in both the U.S.

Higher production in the Eagle Ford Shale was primarily the result of new wells online during the period, and higher production at Tupper Montney was due to better well performance and no repeat of 2024 planned turnaround-related downtime.

Lower production in the Gulf of America was caused by

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Overview (Continued)

production in Canada primarily related to the non-operated Terra Nova field following the asset resuming operations.

downtime and well performance issues at several wells but was partially offset by wells coming back online during the quarter.

Net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2025, was $123.9 million, a decrease of $148.6 million compared to the same period in 2024.

Lower net income from continuing operations was largely driven by lower revenues from production ($236.3 million), lower other income ($67.7 million), and higher DD&A ($26.8 million), and was partially offset by lower lease operating expenses ($73.3 million), lower exploration expenses ($62.2 million), lower impairment of assets ($34.5 million), and lower income tax expenses ($29.0 million).

Lower revenues were primarily driven by lower crude oil prices combined with decreased oil production in the current period.

These items were partially offset by higher natural gas prices, and higher production volumes in the Eagle Ford Shale and Canada.

Lower other income was the result of unrealized foreign exchange losses and no repeat of prior year interest income on joint interest receivables.

Higher DD&A was due to higher production at new onshore wells.

Lower lease operating expenses were caused primarily by less workover expenses in the current period and lower production handling fees related to reduced Gulf of America production.

Lower exploration expenses were due to no dry holes recorded in 2025 (2024:

non-operated Orange #1 (Mississippi Canyon 216) and Hoffe Park #1 (Mississippi Canyon 166) exploration wells).

Impairment charges related to the Calliope field were recorded in the first quarter of 2024, and there were no impairment charges recorded in 2025.

Lower income tax expenses were driven by lower net income.

For the six months ended June 30, 2025, total hydrocarbon production was 179,935 barrels of oil equivalent per day, a decrease of 1% compared to the same period in 2024.

The decrease was principally due to lower offshore production in the Gulf of America, partially offset by increased production in the Eagle Ford Shale and in both onshore and offshore Canada.

Lower production in the Gulf of America was caused by downtime and well performance issues at several wells but was partially offset by other wells coming back online.

Higher production in the Eagle Ford Shale was the result of bringing online new wells in Karnes during the period, and higher production at Tupper Montney was due to better performance in 2025, and no repeat of planned turnaround-related downtime in 2024.

Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada.

1 unchanged sentence

In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

Geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand of crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

For the three months ended March 31, 2025, West Texas Intermediate (WTI) crude oil price at the end of the first quarter of 2025 was $71.48 per barrel, whereas the crude oil price at the end of April 2025 was $58.21, reflecting a 19% reduction in price.

The average sales price in April 2025 was $63.79 per barrel.

As of May 5, 2025 closing, the NYMEX WTI forward curve price for remainder of 2025 was $56.46 per barrel.

Geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

At June 30, 2025, the West Texas Intermediate (WTI) crude oil price was $65.11 per barrel, whereas the crude oil price at the end of July 2025 was $69.26, reflecting an 6% increase in price.

As of August 4, 2025 closing, the NYMEX WTI forward curve price for the remainder of 2025 was $65.03 per barrel.

Reductions in commodity prices will reduce the Company’s future profits and operating cash flows.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations

2 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

4 unchanged sentences

Total exploration and production

89.7 184.5 227.9 327.6

Corporate and other (55.9) (27.7) (104.1) (55.2)

Income from continuing operations 33.8 156.8 123.8 272.4

Loss from discontinued operations ¹ (0.6) (0.9)

Discontinued operations, net of tax 1

1.3 (0.6) 0.7 (1.5)

Net income including noncontrolling interest 35.1 156.2 124.5 270.9

Net income attributable to noncontrolling interest

12.8 28.5 29.2 53.2

Net income attributable to Murphy $ 22.3 $ 127.7 $ 95.3 $ 217.7

7 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

3 unchanged sentences

Sales of purchased natural gas

1.7 1.8 4.1 3.4

Total revenues and other income

684.7 802.8 1,359.9 1,599.2

Cost and Expenses

7 unchanged sentences

Total exploration expenses, including undeveloped lease amortization

10.4 42.8 24.9 87.2

Selling and general expenses 13.1 2.9 23.0 9.0

2 unchanged sentences

Income tax provisions

17.6 40.4 56.9 77.8

Results of operations (excluding Corporate segment) 1

3 unchanged sentences

Results of Operations (Continued)

The following table contains the weighted average sales prices for the three-month periods ended March 31, 2025 and 2024:

The following table contains the weighted average sales prices for the three-month and six-month periods ended June 30, 2025 and 2024:

Three Months Ended

June 30, Six Months Ended

(Weighted average sales prices) 2025 2024 2025 2024

3 unchanged sentences

United States - Offshore 1

64.48 81.67 68.23 79.61

Canada - Onshore 2

59.94 72.25 61.73 70.24

Canada - Offshore 2

64.76 84.34 70.39 85.25

70.86 100.92 70.86 96.43

Natural gas liquids – dollars per barrel

1 unchanged sentence

United States - Offshore 1

19.35 22.77 22.75 23.56

Canada - Onshore 2

33.84 35.46 35.00 35.16

Natural gas – dollars per thousand cubic feet

1 unchanged sentence

United States - Offshore 1

3.47 2.00 3.89 2.32

Canada - Onshore 2

1.65 1.37 1.96 1.68

1 Prices include the effect of noncontrolling interest in MP GOM.

dollar equivalent.

The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2025 and 2024:

The following table contains benchmark prices relevant to the Company for the three-month and six-month periods ended June 30, 2025 and 2024:

Three Months Ended

June 30, Six Months Ended

(Average price for the period) 2025 2024 2025 2024

2 unchanged sentences

AECO (C$/MCF)

1.69 1.18 1.93 1.84

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

1 unchanged sentence

Production Volumes

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2025 and 2024.

The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2025 and 2024.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 33 .

Three Months Ended

June 30, Six Months Ended

(Barrels per day unless otherwise noted) 2025 2024 2025 2024

5 unchanged sentences

Canada - Onshore

2,307 2,978 2,445 2,617

Canada - Offshore

5,638 7,506 7,237 6,885

Other 296 245 275 245

3 unchanged sentences

United States - Onshore

5,557 4,125 4,818 4,145

United States - Offshore 1

4,720 4,505 4,265 4,596

Canada - Onshore

494 494 516 474

Total net natural gas liquids

10,771 9,124 9,599 9,215

Net natural gas – thousands of cubic feet per day

23 unchanged sentences

Sales Volumes

The following table contains hydrocarbons sold during the three-month periods ended March 31, 2025 and 2024.

The following table contains hydrocarbons sold during the three-month and six-month periods ended June 30, 2025 and 2024.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 33 .

Three Months Ended

June 30, Six Months Ended

(Barrels per day unless otherwise noted) 2025 2024 2025 2024

5 unchanged sentences

Canada - Onshore

2,307 2,978 2,444 2,617

Canada - Offshore

7,762 5,645 9,436 6,322

Other 457 469 230 240

Total net crude oil and condensate

2 unchanged sentences

United States - Onshore

5,557 4,125 4,819 4,145

United States - Offshore 1

4,720 4,505 4,264 4,596

Canada - Onshore

494 494 516 474

Total net natural gas liquids

10,771 9,124 9,599 9,215

Net natural gas – thousands of cubic feet per day

26 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

3 unchanged sentences

United States - Natural gas liquids

18.1 16.6 35.9 34.9

United States - Natural gas

24.8 13.9 52.7 31.0

58.3 62.9 147.5 131.6

Canada - Natural gas liquids

1.5 1.6 3.3 3.0

Canada - Natural gas

68.1 50.6 142.4 116.8

2.9 4.3 2.9 4.2

Total revenue from production

$ 683.0 $ 797.5 $ 1,355.8 $ 1,592.1

Revenues from production for the three months ended March 31, 2025 decreased by $121.9 million compared to the same period in 2024.

Revenue was lower in the Gulf of America, mostly driven by workover and turnaround-related downtime, well performance, and lower sales volumes at Cascade and Chinook fields as a result of the timing of sales cargos, partially offset by new well production at the Mormont field.

Lower crude oil pricing was partially offset by higher natural gas pricing in the Gulf of America.

Eagle Ford Shale revenues decreased due to natural decline, as well as lower crude oil prices.

Revenues in Canada Offshore increased due to higher sales volumes at non-operated Terra Nova as a result of lower production in the first quarter of 2024 with production build-up after the completion of the asset life extension project, lower crude oil pricing, and the timing of sales cargos in 2025.

Canada Onshore revenues increased due to higher pricing on natural gas at Tupper Montney and additional new well production volumes, partially offset by higher royalty rates.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments.

“Sales of purchased natural gas” is included in “Total revenues and other income” and “Cost of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 25 .

Revenues from production for the three months ended June 30, 2025, decreased by $114.4 million compared to the same period in 2024.

Lower revenues were primarily driven by lower crude oil prices, combined with decreased oil production in the Gulf of America due to downtime related to workovers, planned turnarounds and well issues, primarily at the Samurai and Cascade & Chinook fields.

These items were partially offset by higher natural gas prices, new wells online in the Eagle Ford Shale at the Karnes field, new wells online at Mormont in the Gulf of America, wells back online from downtime in the Gulf of America, and timing of deliveries in Canada Offshore.

Revenues from production for the six months ended June 30, 2025, decreased $236.3 million compared to the same period in 2024.

These items were partially offset by higher natural gas prices, new wells online in the Eagle Ford Shale and Gulf of America, as well as wells back online from downtime in the Gulf of America, and timing of deliveries in Canada Offshore.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

3 unchanged sentences

Three Months Ended

(Millions of dollars)

June 30, Six Months Ended

(Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars)

(Dollars per equivalent barrel)

23 unchanged sentences

$ 54.0 $ 53.5 $ 3.00 $ 3.14 $ 102.9 $ 110.0 $ 3.14 $ 3.30

For the three months ended March 31, 2025, lease operating expenses decreased by $29.2 million and transportation, gathering and processing expenses decreased by $7.6 million compared to the same period in 2024.

Lower lease operating expenses in the Gulf of America were largely driven by lower sales volumes.

Operating expenses at Canada Offshore decreased by $9.02 per barrel due to lower production and higher restart costs in the first quarter of 2024 associated the non-operated Terra Nova field.

Lower transportation, gathering and processing expenses during the quarter were a result of overall lower production volumes in the Gulf of America.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization (DD&A) expense by geographic area were as follows:

For the three months ended June 30, 2025, lease operating expenses decreased by $44.1 million and transportation, gathering and processing expenses increased by $0.5 million compared to the same period in 2024.

In the Gulf of America, current quarter workovers at Marmalard, Khaleesi (completed in Q3 2025) and Samurai (completed in Q2 2025) were lower than expenditures at Neidermeyer in the prior year.

In the Eagle Ford Shale, there were lower operating costs resulting from cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization.

The Company also realized lower operating costs at the U.S.

Offshore Cascade & Chinook fields that resulted from the purchase of the FPSO.

In addition, lower Gulf of America production handling fees, resulting from lower production, contributed to the decrease in the quarter.

These decreases were partially offset by higher production volumes from both the U.S.

Onshore and Canada Onshore areas.

For the six months ended June 30, 2025, lease operating expenses decreased by $73.3 million, and transportation, gathering and processing expenses decreased by $7.1 million compared to the same period in 2024.

In the Gulf of America, workover costs at the Khaleesi, Mormont and Samurai fields were lower than expenditures at the Neidermeyer field in the prior year.

In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization.

The Company also realized lower operating costs at the U.S.

Offshore Cascade & Chinook fields that resulted from the purchase of the FPSO.

In addition, lower Gulf of America production handling fees, resulting from lower production, contributed to the decrease in the period.

These decreases were partially offset by higher production volumes from both the U.S.

Onshore and Canada Onshore areas.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Depreciation, Depletion and Amortization Expenses

The Company’s DD&A by geographic area were as follows:

Three Months Ended

(Millions of dollars)

June 30, Six Months Ended

(Millions of dollars) (Dollars per equivalent barrel) (Millions of dollars)

(Dollars per equivalent barrel)

9 unchanged sentences

Other 1.2 0.9 28.38 20.69 1.3 0.9 31.02 20.68

Total DD&A expense

$ 257.6 $ 212.9 $ 14.28 $ 12.52 $ 449.4 $ 421.2 $ 13.70 $ 12.64

DD&A expense for the three months ended March 31, 2025 decreased by $16.5 million compared to the same period in 2024.

The decrease is primarily due to lower sales volumes in the Gulf of America and at Eagle Ford Shale and lower rates at Canada Offshore resulting from ARO adjustments, partially offset by higher sales volumes in Canada Offshore and higher rates in the Gulf of America resulting from increased drilling, completions and facilities developments costs.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

DD&A for the three months ended June 30, 2025 increased by $44.7 million compared to the same period in 2024.

The increase was primarily due to higher sales volumes at both U.S.

and Canada Onshore areas, in addition to higher rates at U.S.

DD&A for the six months ended June 30, 2025 increased by $28.2 million.

The increase was primarily due to higher sales volumes in the Eagle Ford Shale as a result of new wells and higher rates at U.S.

Offshore, partially offset by lower production in the Gulf of America.

Impairment of Assets

For the three months ended March 31, 2025, there were no impairments.

Impairment of assets for the three months ended March 31, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

There were no impairments for the three and six months ended June 30, 2025, as well as no impairments for the three months ended June 30, 2024.

Impairment of assets for the six months ended June 30, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

Exploration Expenses

1 unchanged sentence

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

6 unchanged sentences

$ 10.4 $ 42.8 $ 24.9 $ 87.2

Exploration expenses for the three months ended March 31, 2025 decreased by $29.9 million compared to the same period in 2024.

In 2024, there were dry holes and previously suspended exploration costs relating to the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) exploration well and additional costs related to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

Income taxes for the three months ended March 31, 2025 increased by $1.9 million compared to the same period in 2024.

Higher income taxes were primarily the result of higher taxes in foreign jurisdictions, partially offset by lower year-to-date pretax income.

Exploration expenses for the three months ended June 30, 2025 decreased by $32.4 million compared to the same period in 2024, primarily as a result of lower dry hole costs in the current period.

In the second quarter of 2024, the dry hole costs related to the Orange #1 (Mississippi Canyon 216) non-operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

Exploration expenses for the six months ended June 30, 2025 decreased by $62.3 million compared to the same period in 2024.

In 2024, there were dry holes and previously suspended exploration costs relating to the Orange

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

#1 (Mississippi Canyon 216) non-operated exploration well and for the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America.

Income taxes for the three and six months ended June 30, 2025 decreased by $22.8 million and $20.9 million, respectively, compared to the same periods in 2024.

Lower income tax for each period is primarily the result of lower net income.

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge commodity price) and corporate overhead not allocated to E&P.

Realized and unrealized losses on derivative instruments result from increases in market oil and natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

Corporate activities reported a loss of $48.2 million for the three months ended March 31, 2025, an unfavorable variance of $20.7 million compared to the same period of 2024.

The unfavorable variance was primarily due to lower unrealized foreign exchange gains ($10.2 million) and unrealized losses on derivative instruments ($8.9 million).

Realized and unrealized losses on derivative instruments result from increases in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

For the three months ended June 30, 2025, the Corporate segment reported a loss of $55.9 million, an unfavorable variance of $28.2 million, compared to the same period in 2024.

The unfavorable variance was primarily due to higher unrealized foreign exchange losses ($39.8 million) primarily relating to our Canadian subsidiary, partially offset by unrealized gains on derivative instruments ($10.3 million).

The Corporate segment reported a loss of $104.1 million for the six months ended June 30, 2025, an unfavorable variance of $48.9 million, compared to the same period in 2024.

The unfavorable variance was primarily due to higher unrealized foreign exchange losses ($50.0 million).

Financial Condition

2 unchanged sentences

The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months and the foreseeable future.

The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months and the foreseeable future.

The following table presents the Company’s cash flows for the periods presented:

Three Months Ended

Six Months Ended

(Millions of dollars)

3 unchanged sentences

(679.4) (516.9)

Net cash provided (required) by financing activities

Net cash required by financing activities

(22.4) (334.3)

Effect of exchange rate changes on cash and cash equivalents (0.9) 1.3

2 unchanged sentences

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the three months ended March 31, 2025 was $98.1 million lower compared to the same period in 2024.

The decrease in cash flows from operations activities was primarily attributable to lower revenue from production ($121.9 million), partially offset by lower lease operating expenses ($29.2 million).

Net cash provided by continuing operations activities for the six months ended June 30, 2025 was $207.7 million lower compared to the same period in 2024.

The decrease in cash flows from operations activities was primarily

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

due to lower revenue from production ($236.3 million), partially offset by lower lease operating expenses ($73.3 million).

Cash Required by Investing Activities

Net cash required by investing activities for the three months ended March 31, 2025 was $120.7 million higher compared to the same period in 2024.

The increase was primarily due to higher property additions and dry hole costs ($119.3 million), which included a gross payment of $100.0 million for the purchase of a FPSO in the Gulf of America.

Net cash required by investing activities for the six months ended June 30, 2025 was $162.6 million higher compared to the same period in 2024.

The increase was primarily due to a gross payment of $125.0 million for the purchase of an FPSO in the Gulf of America and higher development drilling at Eagle Ford Shale, partially offset by lower development drilling at Gulf of America.

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

Three Months Ended

Six Months Ended

(Millions of dollars) 2025 2024

6 unchanged sentences

Total accrual basis capital expenditures are shown below.

Three Months Ended

Six Months Ended

(Millions of dollars) 2025 2024

3 unchanged sentences

Total capital expenditures $ 678.4 $ 564.7

Higher capital expenditures in the three months ended March 31, 2025 compared to the same period of 2024 was primarily attributable to higher field development costs in the Gulf of America, including the purchase of a

Higher capital expenditures in the six months ended June 30, 2025 compared to the same period of 2024 were primarily attributable to higher field development costs in the Gulf of America attributable to the FPSO purchase and higher development drilling in the Eagle Ford Shale related to new wells online.

Higher exploratory drilling in Vietnam and other development drilling in the Gulf of America also contributed to the increase.

These increases were partially offset by lower exploration costs and development drilling costs in the Gulf of America due to prior year spend on the non-operated Ocotillo #1 (Mississippi Canyon 40) and Orange #1 (Mississippi Canyon 216) exploration wells, and Khaleesi development costs, respectively.

Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($248.1 million), Eagle Ford Shale ($230.2 million), Tupper Montney and Kaybob Duvernay ($92.0 million), and in Vietnam ($29.6 million).

Exploration costs in 2025 were $57.2 million, primarily comprised of activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05, and Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration wells, and activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

FPSO, increased exploratory drilling in Vietnam, and higher development drilling at Eagle Ford Shale.

The purchased FPSO in the Gulf of America will remain at its current location, and continue supporting operations at the Cascade and Chinook fields.

Capital expenditures in 2025 primarily relate to development drilling and field development activities at Eagle Ford Shale ($92.7 million), the Gulf of America ($214.8 million), Tupper Montney and Kaybob Duvernay ($50.2 million), and the non-operated Hibernia field ($4.6 million) in Canada.

Other international field development activities were largely in Vietnam ($18.6 million).

Exploration costs in 2025 were $39.1 million, primarily comprised of activities in Vietnam for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells and activities in the Gulf of America related to long lead equipment purchases for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2025 increased by $182.4 million compared to the same period in 2024.

In 2025, the cash provided by financing activities was due to net borrowings on the senior unsecured RCF ($200.0 million), partially offset by the repurchase of common shares ($100.1 million), cash dividends to shareholders of $0.33 per share ($47.0 million), withholding tax on stock-based incentive awards ($7.7 million), and distributions to the noncontrolling interest in MP GOM ($7.0 million).

In 2024, cash required by financing activities was for the repurchase of common shares ($50.0 million), cash dividends to shareholders ($45.8 million), withholding tax on stock-based incentive awards ($25.3 million), and distributions to the noncontrolling interest in MP GOM ($23.0 million).

At March 31, 2025, the Company had approximately $1.5 billion of liquidity consisting of $392.9 million in cash and cash equivalents and $1,149.6 million available on its committed senior unsecured RCF with a major banking consortium.

Financial Condition (Continued)

Cash Required by Financing Activities

Net cash required by financing activities for the six months ended June 30, 2025 decreased by $311.9 million compared to the same period in 2024.

In 2025, the cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.65 per share ($93.4 million), and distributions to the noncontrolling interest in MP GOM ($18.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($200.0 million).

In 2024, cash required by financing activities was for the repurchase of common shares ($105.9 million), cash dividends to shareholders ($91.5 million), distributions to the noncontrolling interest in MP GOM ($61.2 million), debt repurchases ($50.0 million), and withholding tax on stock-based incentive awards ($25.3 million).

At June 30, 2025, the Company had approximately $1.5 billion of liquidity consisting of $379.6 million in cash and cash equivalents and $1,149.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029.

As of March 31, 2025, the Company had $200.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At March 31, 2025, the interest rate in effect on borrowings under the RCF was 6.67%.

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

As of June 30, 2025, the Company had $200.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At June 30, 2025, the interest rate in effect on borrowings under the RCF was 6.67%.

At June 30, 2025, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S.

As of March 31, 2025, cash and cash equivalents held outside the U.S.

As of June 30, 2025, cash and cash equivalents held outside the U.S.

included U.S.

dollar equivalents of approximately $83.1 million, the majority of which was held in Canada ($48.5 million), Vietnam ($9.0 million), and the U.K.

dollar equivalents of approximately $112.4 million, the majority of which was held in Canada ($73.6 million), Vietnam ($9.0 million), Mexico ($8.0 million), and the U.K.

($7.7 million).

3 unchanged sentences

Working Capital

(Millions of dollars) March 31, 2025 December 31, 2024

(Millions of dollars) June 30, 2025 December 31, 2024

Working capital

3 unchanged sentences

$ (147.2) $ (157.5)

As of March 31, 2025, net working capital decreased by $79.6 million compared to December 31, 2024.

The decrease was primarily attributable to higher accounts payable ($66.1 million), lower cash balance ($30.7 million), and higher current asset retirement obligations ($29.4 million), partially offset by lower other accrued liabilities ($27.2 million) and higher inventory balances ($16.2 million).

Higher accounts payable was primarily due to the timing of drilling and completions work and accruals relating to the purchase of the FPSO in the Gulf of America.

Higher current asset retirement obligations were primarily attributable to planned abandonment activities in U.S.

As of June 30, 2025, net working capital increased by $10.4 million compared to December 31, 2024.

The increase was primarily attributable to lower current operating lease obligations ($62.5 million), lower other accrued liabilities ($33.5 million), and higher prepaid expenses ($11.6 million).

These items were partially offset by lower cash and equivalents ($43.9 million), higher accounts payable ($37.1 million) and higher current asset retirement obligations ($22.0 million).

Lower lease obligations were due to lower day rates on the Noble Stanley Lafosse drilling rig and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America.

Lower other accrued liabilities were related to lower incentive award obligations in the current year, and higher prepaid expenses were primarily due to the renewal of insurance policies.

Lower cash and equivalents were due to lower net income, the BW Pioneer FPSO purchase, and returns to shareholders in the form of share repurchases and dividends.

Higher accounts payable related to higher production in the Eagle Ford Shale.

Higher current asset retirement obligations related to planned abandonment activities in U.S.

Offshore in the next 12 months.

Lower other accrued liabilities were due to incentive payments

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

and operating lease payments made in 2025.

Inventory balances increased primarily due to timing of sales cargos at U.S.

Financial Condition (Continued)

Capital Employed

A summary of capital employed at March 31, 2025 and December 31, 2024 follows.

March 31, 2025 December 31, 2024

A summary of capital employed at June 30, 2025 and December 31, 2024 follows.

June 30, 2025 December 31, 2024

(Millions of dollars) Amount % Amount %

3 unchanged sentences

Total capital employed $ 6,673.5 100.0 % $ 6,468.8 100.0 %

At March 31, 2025, long-term debt of $1,474.8 million increased by $200.3 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF.

At June 30, 2025, long-term debt of $1,475.0 million increased by $200.5 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF.

The total of the fixed-rate notes had a weighted average maturity of 8.9 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $74.0 million in 2025, primarily due to shares repurchased ($100.9 million, including excise tax) and cash dividends paid ($47.0 million), partially offset by net income earned ($73.0 million).

Murphy shareholders’ equity increased by $4.2 million in 2025, primarily due to foreign currency translation ($88.6 million) and awarded restricted stock ($20.1 million), partially offset by shares repurchased ($100.9 million, including excise tax).

A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity ” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of March 31, 2025, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2024.

As of June 30, 2025, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2024.

Accounting Changes and Recent Accounting Pronouncements

9 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Millions of dollars, except per share amounts)

2025 2024 2025 2024

Net income attributable to Murphy (GAAP) 1

$ 22.3 $ 127.7 $ 95.3 $ 217.7

Discontinued operations loss 0.6 0.9

Discontinued operations (income) loss (1.3) 0.6 (0.7) 1.5

Net income from continuing operations attributable to Murphy 21.0 128.3 94.6 219.2

Mark-to-market loss on derivative instruments 8.9 —

Foreign exchange loss (gain) 34.3 (5.5) 34.3 (16.0)

Mark-to-market (gain) on derivative instruments (10.3) — (1.4) —

Impairment of assets — — — 34.5

Write-off of previously suspended exploration well — — — 26.1

Foreign exchange (gain) — (10.5)

Total adjustments, before taxes 24.0 (5.5) 32.9 44.6

Income tax (benefit) related to adjustments

Income tax (benefit) expense related to adjustments

(6.5) 1.4 (8.3) (8.8)

Total adjustments, after taxes 17.5 (4.1) 24.6 35.8

7 unchanged sentences

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

4 unchanged sentences

Depreciation, depletion and amortization expense 1

250.8 207.3 438.2 410.1

EBITDA attributable to Murphy (Non-GAAP) 299.3 388.7 615.9 731.5

Exploration expenses

10.3 42.7 24.8 87.1

EBITDAX attributable to Murphy (Non-GAAP) $ 309.6 $ 431.4 $ 640.7 $ 818.6

EBITDA attributable to Murphy (Non-GAAP) $ 299.3 $ 388.7 $ 615.9 $ 731.5

Foreign exchange loss (gain)

34.3 (5.4) 34.3 (15.9)

Accretion of asset retirement obligations 1

Mark-to-market loss on derivative instruments

12.9 11.7 25.4 23.1

Mark-to-market (gain) on derivative instruments

(10.3) — (1.4) —

Impairment of assets

Write-off of previously suspended exploration well — — — 26.1

Foreign exchange (gain)

Discontinued operations loss 0.6 0.9

Discontinued operations (income) loss

(1.3) 0.6 (0.7) 1.5

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 334.9 $ 395.6 $ 673.5 $ 800.8

Other exploration expenses 2

10.3 42.7 24.8 61.0

Adjusted EBITDAX attributable to Murphy (Non-GAAP) $ 345.2 $ 438.3 $ 698.3 $ 861.8

2 unchanged sentences

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy.

As discussed in the “ Results of Operations ” section discussing revenues, on page 29 , lower average crude oil and higher natural gas pricing during the first quarter of 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on May 5, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the table below:

WTI ($/BBL) 56.46 57.23

NYMEX ($/MMBTU) 4.08 4.38

AECO (US$ Equivalent/MCF) 1.94 2.44

In April 2025, the U.S.

government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits.

Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions.

Additionally, the U.S.

government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions.

Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate.

Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations.

Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.

For the second quarter of 2025, production is expected to average between 177.0 and 185.0 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

The Company’s capital expenditure spend for 2025 is expected to be between $1,135 million and $1,285 million, excluding noncontrolling interest.

This includes net acquisition capital of $104 million for the BW Pioneer FPSO in the Gulf of America.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year.

Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

The Company will primarily fund its capital program in 2025 using operating cash flow and available cash.

If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company plans to utilize any surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation plan designed to allow for additional shareholder returns and debt reduction.

Details of the plan can be found in the “Capital Allocation” section of the Company’s Form 8-K filed on May 7, 2025.

On August 8, 2024, the Company’s Board of Directors has authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available as of March 31, 2025.

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note E ).

Other Key Performance Metrics (Continued)

Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities.

Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time.

Adjusted FCF excludes certain items that management believes affect the comparability of results between periods.

FCF and Adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.

The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2025 2024 2025 2024

Net cash provided by continuing operations activities (GAAP) $ 358.1 $ 467.7 $ 658.7 $ 866.4

increase (decrease) in non-cash working capital

(30.7) (25.5) (7.9) (1.1)

Operating cash flow excluding working capital adjustments 327.4 442.2 650.8 865.3

property additions and dry hole costs 1

(309.6) (267.8) (678.0) (516.9)

Free cash flow (Non-GAAP) $ 17.8 $ 174.4 $ (27.2) $ 348.4

cash dividends paid

(46.4) (45.8) (93.4) (91.5)

distributions to noncontrolling interest

(11.2) (38.2) (18.2) (61.2)

withholding tax on stock-based incentive awards — — (7.7) (25.3)

acquisition of oil and natural gas properties

Adjusted free cash flow (Non-GAAP) $ (39.8) $ 90.4 $ (147.9) $ 170.4

1 Property additions for the 2025 period include a payment of $125.0 million for the purchase of a floating production, storage, and offloading vessel in the U.S Offshore, including amounts attributable to a noncontrolling interest in MP GOM.

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-Q

Item 1. Financial Statements