What changed in this filing

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Item 1. Financial Statements

2025-11-05 compared with 2025-08-06 · 411 added, 329 removed, 1187 unchanged (38% of the section changed)

2 unchanged sentences

CONSOLIDATED BALANCE SHEETS

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

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

2025 December 31,

28 unchanged sentences

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

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

Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2025 and 195,100,628 shares at December 31, 2024

195,101 195,101

11 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

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

3 unchanged sentences

Total revenue from sales to customers 720,966 753,169 2,076,761 2,349,024

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

Gain (loss) on derivative instruments 5,722 ( 1,344 ) 7,071 ( 1,344 )

Gain on sale of assets and other operating income 6,297 6,506 10,434 9,834

10 unchanged sentences

Impairment of assets 115,002 — 115,002 34,528

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

Other operating expense 5,902 5,450 13,364 10,497

Total costs and expenses 727,192 579,305 1,852,368 1,840,109

3 unchanged sentences

Interest expense, net ( 24,726 ) ( 21,258 ) ( 73,302 ) ( 62,265 )

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

Total other loss

( 9,455 ) ( 25,184 ) ( 87,933 ) ( 28,395 )

Income (loss) from continuing operations before income taxes ( 3,662 ) 153,842 153,965 489,010

Income tax expense 4,157 2,122 37,911 64,855

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

Income (loss) from continuing operations ( 7,819 ) 151,720 116,054 424,155

Income (loss) from discontinued operations, net of income taxes ( 497 ) ( 608 ) 172 ( 2,123 )

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

Net income attributable to noncontrolling interest 12,844 28,523 29,226 53,179

NET INCOME ATTRIBUTABLE TO MURPHY $ 22,280 $ 127,739 $ 95,316 $ 217,741

Net income (loss) including noncontrolling interest ( 8,316 ) 151,112 116,226 422,032

Net income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197

NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY $ ( 2,973 ) $ 139,094 $ 92,343 $ 356,835

NET INCOME (LOSS) PER COMMON SHARE – BASIC

1 unchanged sentence

Discontinued operations — — — ( 0.01 )

Net income $ 0.16 $ 0.84 $ 0.66 $ 1.43

Net income (loss) $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.36

NET INCOME (LOSS) PER COMMON SHARE – DILUTED

1 unchanged sentence

Discontinued operations — — — ( 0.01 )

Net income $ 0.16 $ 0.83 $ 0.66 $ 1.42

Net income (loss) $ ( 0.02 ) $ 0.93 $ 0.64 $ 2.34

Cash dividends per common share $ 0.325 $ 0.300 $ 0.975 $ 0.900

6 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024 2025 2024

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

Net income (loss) including noncontrolling interest $ ( 8,316 ) $ 151,112 $ 116,226 $ 422,032

Other comprehensive income (loss), net of tax

5 unchanged sentences

Comprehensive income including noncontrolling interest ( 45,469 ) 170,050 169,367 390,442

Comprehensive income attributable to noncontrolling interest 12,844 28,523 29,226 53,179

Comprehensive income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197

COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ ( 40,126 ) $ 158,032 $ 145,484 $ 325,245

2 unchanged sentences

CONSOLIDATED STATEMENTS OF CASH FLOWS

Six Months Ended

Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024

Operating Activities

Net income including noncontrolling interest $ 124,542 $ 270,920

Net income (loss) including noncontrolling interest $ 116,226 $ 422,032

Adjustments to reconcile net income to net cash provided by continuing operations activities

4 unchanged sentences

Amortization of undeveloped leases 6,907 7,707

Mark-to-market loss on derivative instruments

Unrealized (gain) loss on derivative instruments ( 3,904 ) 1,344

Unsuccessful exploration well costs and previously suspended exploration costs 83 69,548

3 unchanged sentences

Other operating activities, net ( 47,428 ) ( 38,260 )

Net decrease in non-cash working capital

Net decrease (increase) in non-cash working capital

( 20,473 ) 31,835

Net cash provided by continuing operations activities 998,162 1,295,430

16 unchanged sentences

Effect of exchange rate changes on cash and cash equivalents ( 499 ) 778

Net (decrease) increase in cash and cash equivalents

Net increase (decrease) in cash and cash equivalents

2,391 ( 45,851 )

5 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(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 June 30, 2025 and June 30, 2024, issued 195,100,628 shares at June 30, 2025 and June 30, 2024

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

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

6 unchanged sentences

Balance at beginning of period 6,775,193 6,672,275 6,773,289 6,546,079

Net income attributable to Murphy 22,280 127,739 95,316 217,741

Net income (loss) attributable to Murphy ( 2,973 ) 139,094 92,343 356,835

Cash dividends paid ( 46,387 ) ( 44,663 ) ( 139,799 ) ( 136,208 )

9 unchanged sentences

Awarded restricted stock, net of forfeitures 243 41 20,314 45,229

Balance at end of period – 52,374,883 shares of common stock in 2025 and 43,884,080 shares of common stock in 2024, at cost

Balance at end of period – 52,368,808 shares of common stock at September 30, 2025 and 49,257,269 shares of common stock at September 30, 2024, at cost

( 2,075,580 ) ( 1,995,018 ) ( 2,075,580 ) ( 1,995,018 )

2 unchanged sentences

Balance at beginning of period 158,654 178,828 147,593 186,859

Net income attributable to noncontrolling interest 12,844 28,523 29,226 53,179

Net income (loss) attributable to noncontrolling interest ( 5,343 ) 12,018 23,883 65,197

Distributions to noncontrolling interest owners ( 25,046 ) ( 35,408 ) ( 43,211 ) ( 96,618 )

5 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 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.

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

generally accepted accounting principles (GAAP).

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

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

Note B – New Accounting Principles and Recent Accounting Pronouncements

22 unchanged sentences

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

The Company evaluates the applicability and impact of all ASUs.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

18 unchanged sentences

Note C - Revenue from Contracts with Customers (Continued)

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

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

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024 2025 2024

29 unchanged sentences

Canada - Onshore

— 3,497 — 3,742

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

Total revenue from sales to customers 720,966 753,169 2,076,761 2,349,024

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

Gain (loss) on derivative instruments 5,722 ( 1,344 ) 7,071 ( 1,344 )

Gain on sale of assets and other operating income 6,297 6,506 10,434 9,834

5 unchanged sentences

Contract Balances and Asset Recognition

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.

As of September 30, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 180.2 million and $ 178.3 million, respectively.

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

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

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

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

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

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 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:

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

Location Commodity End Date Description Approximate Volumes

12 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 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.

As of September 30, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 115.1 million.

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

(Thousands of dollars) 2025 2024

2 unchanged sentences

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

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.

Balance at September 30 $ 115,146 $ 51,099

Capital additions of $ 43.1 million, for the nine months ended September 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17;

and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam.

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

Capital additions also included long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

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.

exploration wells in the Gulf of America and long-lead equipment for Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire.

Capital additions of $ 28.5 million, for the nine months ended September 30, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17;

and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam.

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

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

The preceding table excludes well costs of $ 43.0 million incurred and expensed directly to dry hole for the nine months ended September 30, 2024.

These costs primarily included $ 25.8 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America.

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

September 30,

(Thousands of dollars) Amount No.

6 unchanged sentences

$ 115,146 11 $ 51,099 6

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.

Of the $ 97.6 million of exploration well costs capitalized and classified as more than one year at September 30, 2025, $ 68.2 million was in Vietnam, $ 22.1 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei.

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

Property Additions

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.

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

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

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

1 unchanged sentence

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 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.

There were pretax impairments of $ 115.0 million ($ 92.0 million excluding NCI) in the three and nine months ended September 30, 2025.

The impairment related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

There were no impairments in the three months ended September 30, 2024.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt

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

Revolving Credit Facility

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

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

At 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)

At September 30, 2025, the Company had $ 150.0 million of outstanding borrowings under the RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48 %.

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

Debt Extinguishment

In May 2024, the Company paid a total of $ 50.5 million to complete the open market repurchases of $ 26.5 million aggregate principal of its 5.875 % senior notes due 2027 (2027 Notes) and $ 23.5 million aggregate principal of its 6.375 % senior notes due 2028 (2028 Notes).

The cash costs of the debt extinguishment of $ 0.5 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2024.

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

2 unchanged sentences

Supplemental Information to Statement of Cash Flows

Six Months Ended

Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024

5 unchanged sentences

Increase (decrease) in income taxes payable 1,984 771

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

Net decrease (increase) in non-cash working capital $ ( 20,473 ) $ 31,835

Supplementary disclosures:

Net cash income taxes (refunded) paid $ 423 $ 3,236

Net cash income taxes paid $ 9,217 $ 12,519

Interest paid, net of amounts capitalized of $ 5.3 million in 2025 and $ 10.8 million in 2024

3 unchanged sentences

(Increase) decrease in capital expenditure accrual 34,210 ( 2,177 )

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note G – Asset Retirement Obligations

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

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

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

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

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

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

11 unchanged sentences

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans

8 unchanged sentences

the life insurance benefits are noncontributory.

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,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans (Continued)

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

Three Months Ended September 30,

Pension Benefits Other Postretirement Benefits

4 unchanged sentences

Estimated defined contribution provision 62 54 — —

Amortization of prior service cost (credit) 492 579 ( 133 ) ( 133 )

Recognized actuarial loss (gain) 1,914 2,361 ( 1,057 ) ( 812 )

Amortization of prior service (credit) cost 492 579 ( 133 ) ( 133 )

Recognized actuarial (gain) loss 1,918 2,363 ( 1,057 ) ( 812 )

Total net periodic benefit expense $ 3,683 $ 4,734 $ ( 398 ) $ ( 28 )

Six Months Ended June 30,

Nine Months Ended September 30,

Pension Benefits Other Postretirement Benefits

4 unchanged sentences

Estimated defined contribution provision 184 163 — —

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

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

Amortization of prior service (credit) cost 1,475 1,737 ( 399 ) ( 399 )

Recognized actuarial (gain) loss 5,723 7,084 ( 3,170 ) ( 2,436 )

Total net periodic benefit expense $ 11,015 $ 14,202 $ ( 1,193 ) $ ( 84 )

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

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

During the nine-month period ended September 30, 2025, the Company made contributions of $ 26.4 million to its defined benefit pension and postretirement benefit plans.

Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 4.5 million.

1 unchanged sentence

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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.

4 unchanged sentences

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.

These grants may be in the form of stock

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents and other stock-based incentives.

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

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

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

During the nine months ended September 30, 2025, the Committee granted the following awards from the 2020 Long-Term Plan and the 2025 Long-Term Plan:

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

7 unchanged sentences

771,390 February 4, 2025 $ 25.98 Average Stock Price

Performance-based RSUs (TSR) 1

6,070 August 11, 2025 $ 19.65 Monte Carlo

Performance-based RSUs (ROACE) 1

1,520 August 11, 2025 $ 23.09 Average Stock Price

Time-based RSUs (Stock-Settled) 2

5,060 August 11, 2025 $ 23.09 Average Stock Price

1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) and Return on Average Capital Employed (ROACE) performance goals and are scheduled to vest three years from the date of grant if performance conditions are met.

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

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

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

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

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

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:

During the nine months ended September 30, 2025, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:

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

5 unchanged sentences

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.

NEDs may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.

Time-Based RSUs 2

2,112 September 30, 2025 $ 28.41 Closing Stock Price

1 Non-Employee Directors’ time-based RSUs are scheduled to vest on the first anniversary of the date of grant.

Non-Employee Directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.

These unvested time-based RSUs are included in the table above, will vest in one year , and become deferred RSUs.

2 Effective January 1, 2024, NEDs can elect to receive their annual retainers in the form of deferred RSUs.

Director fees which are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter.

2 Effective January 1, 2024, Non-Employee Directors can elect to receive their annual retainers in the form of deferred RSUs.

Director fees that are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter.

Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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

Six Months Ended

Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024

4 unchanged sentences

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 and six-month periods ended June 30, 2025 and 2024.

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

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

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Weighted-average shares) 2025 2024 2025 2024

1 unchanged sentence

Dilutive restricted stock units 1

— 968,428 730,291 1,036,653

Diluted method 142,730,808 150,352,782 143,975,510 152,437,379

1 Due to a net loss recognized by the Company for the three months ended September 30, 2025, no unvested stock awards were included in the computation of the diluted net income (loss) per common share as the effect would have been antidilutive.

The following table reflects the dilutive restricted stock units during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.

Three Months Ended September 30, Nine Months Ended

September 30,

2025 2024 2025 2024

Antidilutive restricted stock units excluded from diluted shares 908,021 — — —

Note K – Income Taxes

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

For the three-month and 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 %

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

Three months ended September 30, ( 113.5 )% 1.4 %

Nine months ended September 30, 24.6 % 13.3 %

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

statutory tax rate of 21% due to the impact of the Company's reported pre-tax loss.

Several factors affect the rate including:

certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available, foreign currency translation adjustments, no tax benefit applied to the pretax loss of the noncontrolling interest in MP GOM, and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S.

federal rate.

The negative impact on the effective tax rate was partially offset by the tax effect of stock-based compensation and U.S.

state tax expense.

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.

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

statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend, which resulted in an income tax benefit of $ 33.7 million.

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

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

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stock-based compensation;

foreign currency translation adjustments;

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

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

The effective tax rate for the 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.

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

statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend and no tax applied to the pretax income of the noncontrolling interest in MP GOM.

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

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

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

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

Canada – 2016;

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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.

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.

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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.

The Company evaluated the effects of the OBBBA in accordance with ASC 740, Income Taxes, and determined that the legislation did not have a material impact on its consolidated financial statements for the period ended September 30, 2025.

The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA.

Note L – Financial Instruments and Risk Management

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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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Foreign Currency Exchange Risks

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

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

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

Commodity Price Risks

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

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

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

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

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

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

NYMEX Henry Hub

1 unchanged sentence

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

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:

During the nine months ended September 30, 2025 and September 30, 2024, the Company did no t have any crude oil derivative contracts.

At September 30, 2024, the Company had natural gas derivative contracts outstanding for 20 MMCF/d at an average price of $ 3.20 /MCF.

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

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

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

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

Commodity swaps Accounts receivable $ 2,197 $ —

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

For the three-month and 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:

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

Gain (Loss) Gain (Loss)

(Thousands of dollars) Three Months Ended

June 30, Six Months Ended June 30,

September 30, Nine Months Ended September 30,

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Commodity swaps Gain (loss) on derivative instruments $ 5,722 $ ( 1,344 ) $ 7,071 $ ( 1,344 )

Fair Values – Recurring

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

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

June 30, 2025 December 31, 2024

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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

September 30, 2025 December 31, 2024

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

Commodity swaps $ — $ 2,197 $ — $ 2,197 $ — $ — $ — $ —

$ — $ 2,197 $ — $ 2,197 $ — $ — $ — $ —

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

Nonqualified employee savings plan 21,168 — — 21,168 19,469 — — 19,469

$ 21,168 $ — $ — $ 21,168 $ 19,469 $ 1,707 $ — $ 21,176

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

The commodity swaps receivable as of September 30, 2025 was $ 2.2 million and recorded as “Accounts receivable” in the Consolidated Balance Sheets.

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

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

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

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.

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

There were no offsetting positions recorded at June 30, 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.

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

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

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

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

June 30, 2025 December 31, 2024

September 30, 2025 December 31, 2024

(Thousands of dollars) Carrying

3 unchanged sentences

$ 1,426,153 $ 1,366,561 $ 1,275,374 $ 1,185,961

Fair Values – Nonrecurring

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)

Fair Values – Nonrecurring

For the three and nine months ended September 30, 2025, an impairment charge of $ 115.0 million ($ 92.0 million excluding NCI) was triggered for the Dalmatian field in the Gulf of America due to reserve reductions, as certain projects in the field were less competitive for capital allocation.

There were no impairment expenses incurred in the three months ended September 30, 2024.

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

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

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

Six Months Ended June 30, 2024

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

Nine Months Ended September 30, 2025

Impairment Total

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United States - Offshore $ — $ — $ 42,397 $ 157,399 $ 115,002

Nine Months Ended September 30, 2024

Impairment Total

( Thousands of dollars )

Level 1 Level 2 Level 3

Property, plant and equipment:

Impaired proved properties

United States - Offshore

$ — $ — $ 437 $ 34,965 $ 34,528

Note M – Accumulated Other Comprehensive Loss

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

(Thousands of dollars) Foreign

6 unchanged sentences

Net other comprehensive income (loss) 50,528 2,613 53,141

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.

Balance at September 30, 2025 $ ( 465,796 ) $ ( 109,135 ) $ ( 574,931 )

1 Reclassifications before taxes of $ 3.1 million are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2025.

See Note H for additional information.

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

Related income taxes of $ 0.5 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2025.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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 products, wastewater and hazardous materials;

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

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

However, the U.S.

EPA has since published an interim final rule extending several compliance deadlines associated with the new methane rules.

In November 2024, the U.S.

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

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

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

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

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

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

Hazardous substances may have been disposed of or released on

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal.

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

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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

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.

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

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

1 unchanged sentence

Note O – Common Stock Issued and Outstanding

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.

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

( Number of shares outstanding )

June 30, 2025 June 30, 2024

September 30, 2025 September 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 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.

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments

15 unchanged sentences

Other, and Discontinued Operations

Three Months Ended June 30, 2025

Three Months Ended September 30, 2025

Revenue from production

13 unchanged sentences

Transportation, gathering and processing 23.3 24.8 — 48.1 — 48.1

Costs of purchased natural gas

Selling and general expenses 1.9 5.4 2.2 9.5 21.4 30.9

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Depreciation, depletion and amortization 242.1 39.3 — 281.4 2.1 283.5

Impairment of assets 115.0 — — 115.0 — 115.0

Accretion of asset retirement obligations 11.8 2.6 0.2 14.6 0.1 14.7

26 unchanged sentences

Other, and Discontinued Operations Consolidated

Three Months Ended June 30, 2024

Three Months Ended September 30, 2024

Revenue from production

$ 596.5 $ 157.6 $ ( 0.8 ) $ 753.1 $ — $ 753.1

Sales of purchased natural gas

— 3.5 — 3.5 — 3.5

Gain on sales of assets and other operating income

11 unchanged sentences

Transportation, gathering and processing 26.3 21.2 — 47.5 — 47.5

Costs of purchased natural gas

— 3.0 — 3.0 — 3.0

Selling and general expenses ( 1.7 ) 4.7 1.9 4.9 20.0 24.9

12 unchanged sentences

Interest income

( 0.8 ) — — ( 0.8 ) ( 3.1 ) ( 3.9 )

Interest expense, net of capitalization 0.3 — — 0.3 21.0 21.3

21 unchanged sentences

Other, and Discontinued Operations

Six Months Ended June 30, 2025

Nine Months Ended September 30, 2025

Revenue from production

13 unchanged sentences

Transportation, gathering and processing 82.4 68.7 — 151.1 — 151.1

Costs of purchased natural gas

Selling and general expenses 8.7 17.1 6.7 32.5 66.2 98.7

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Depreciation, depletion and amortization 619.7 109.8 1.2 730.7 6.2 736.9

Impairment of assets 115.0 — — 115.0 — 115.0

Accretion of asset retirement obligations 34.8 7.7 0.6 43.1 0.1 43.2

26 unchanged sentences

Other, and Discontinued Operations Consolidated

Six Months Ended June 30, 2024

Nine Months Ended September 30, 2024

Revenue from production

47 unchanged sentences

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note Q – Leases

Nature of Leases

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

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

Early lease terminations are at the Company’s discretion and/or the mutual agreement between the Company and lessor.

Purchase options also exist for certain leases.

During the third quarter of 2025, the Company exercised an option to extend an operating lease pertaining to a drill ship used in our offshore business.

This resulted in an increase of $ 167.1 million (discounted) to our right-of-use assets and operating lease liabilities at September 30, 2025.

Maturity of Lease Liabilities

(Thousands of dollars) Operating Leases Finance Leases Total

2025 $ 60,970 $ 319 $ 61,289

2026 248,750 1,274 250,024

2027 141,648 1,274 142,922

2028 62,259 1,275 63,534

2029 59,471 464 59,935

Remaining 419,202 958 420,160

Total future minimum lease payments 992,300 5,564 997,864

Less imputed interest ( 199,449 ) ( 1,352 ) ( 200,801 )

Present value of lease liabilities 1

$ 792,851 $ 4,212 $ 797,063

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

Lease Term and Discount Rate

September 30, 2025 December 31, 2024

Weighted average remaining lease term:

Operating leases 8 years 8 years

Finance leases 5 years 6 years

Weighted average discount rate:

Operating leases 5.5 % 5.7 %

Finance leases 4.9 % 4.9 %

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 June 30, 2025 included under “ Item 1 .

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

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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 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.

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

• Increased production to 206,936 barrels of oil equivalent (BOE) per day (including NCI), up from 191,273 BOE per day in the third quarter of 2024, and up from 196,315 BOE per day in the second quarter of 2025

• Paid down $50.0 million of debt under the RCF and returned $46.4 million ($0.325 per share, or $1.30 per share annualized) to shareholders through a quarterly dividend

Subsequent to the third quarter, Murphy completed the installation of the LDV-A platform jacket and initiated development drilling at the Lac Da Vang (Golden Camel) development project in Vietnam.

Murphy Oil Corporation’s net loss from continuing operations, including noncontrolling interest, for the three months ended September 30, 2025, was $7.8 million compared to net income of $151.7 million for the same period in 2024.

The results for 2025 were impacted by higher impairment expense ($115.0 million), higher depreciation, depletion and amortization expenses (DD&A) ($59.8 million), and lower revenues from production ($32.2 million).

These changes were partially offset by lower lease operating expenses ($38.5 million) and higher other income ($19.2 million).

The impairment expense during the quarter related to the Dalmatian field in the Gulf of America that resulted from reserve reductions, as certain projects in the field were less competitive for capital allocation.

The increase in DD&A resulted from higher total production levels and elevated rates in the Gulf of America.

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

Lower lease operating expenses were primarily due to lower workover costs and production handling fees in the Gulf of America and cost-savings initiatives in the Eagle Ford Shale, and were partially offset by higher production in the Eagle Ford Shale.

Higher other income was the result of unrealized foreign exchange gains.

For the three months ended September 30, 2025, total hydrocarbon production was 206,936 barrels of oil equivalent per day, an increase of 8% compared to the third quarter of 2024.

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

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

Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year at Karnes and Catarina.

Higher production in Canada Onshore relates to better well performance at Tupper Montney.

Lower production in the Gulf of America and Canada Offshore was due to natural decline and both planned and unplanned downtime for mechanical issues.

Net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2025, was $116.1 million, a decrease of $308.1 million compared to the same period in 2024.

Lower net income from continuing operations was largely driven by lower revenues from production ($268.5

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

Overview (Continued)

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.

million), higher DD&A ($86.6 million), higher impairment expense ($80.5 million), and lower other income ($48.5 million).

These changes were partially offset by lower lease operating expenses ($111.8 million), lower exploration expenses ($61.0 million), and lower income tax expenses ($26.9 million).

Lower revenues were primarily due to the lower price of oil, combined with lower production in the Gulf of America, and were partially offset by higher production in the Eagle Ford Shale, and the higher price of natural gas.

Higher DD&A was due to higher production in the Eagle Ford Shale and higher rates in the Gulf of America, partially offset by lower production volumes in the Gulf of America.

Higher impairment expense was related to the Dalmatian field in the Gulf or America.

Lower other income was primarily the result of unrealized foreign exchange losses.

Lower lease operating expenses related to lower workover costs and production handling fees in the Gulf of America, combined with lower operating costs due to the acquisition of the BW Pioneer FPSO earlier this year.

Cost reduction activities in the Eagle Ford Shale also contributed to overall lower lease operating expenses.

Lower exploration expenses were primarily due to no dry hole expense recorded in 2025 (2024:

Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America).

Lower dry hole costs were partially offset by higher exploration activity in Côte d'Ivoire.

Lower income tax expense was due to lower net income for the period.

For the nine months ended September 30, 2025, total hydrocarbon production was 189,035 barrels of oil equivalent per day, an increase of 2% compared to the same period in 2024.

Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year in Karnes and Catarina.

Higher production in Canada Onshore relates to better well performance at Tupper Montney.

Lower production in the Gulf of America related to planned and unplanned downtime, and was partially offset by new wells online.

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

2 unchanged sentences

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.

At September 30, 2025, the West Texas Intermediate (WTI) crude oil price was $62.37 per barrel, whereas the crude oil price at the end of October 2025 was $60.98, reflecting a 2% decrease in price.

As of November 3, 2025 closing, the NYMEX WTI forward curve price for the remainder of 2025 was $61.05 per barrel.

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

4 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024 2025 2024

6 unchanged sentences

Corporate and other (18.6) (33.7) (122.7) (88.9)

Income from continuing operations 33.8 156.8 123.8 272.4

Income (loss) from continuing operations (7.8) 151.7 116.0 424.1

Discontinued operations, net of tax 1

(0.5) (0.6) 0.2 (2.1)

Net income including noncontrolling interest 35.1 156.2 124.5 270.9

Net income attributable to noncontrolling interest

Net income (loss) including noncontrolling interest (8.3) 151.1 116.2 422.0

Net income (loss) attributable to noncontrolling interest

(5.3) 12.0 23.9 65.2

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

Net income (loss) attributable to Murphy

$ (3.0) $ 139.1 $ 92.3 $ 356.8

1 The Company has presented its former U.K., Malaysia and U.S.

6 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024 2025 2024

6 unchanged sentences

721.8 754.1 2,081.7 2,353.3

Cost and Expenses

Costs and expenses

Lease operating expenses 184.4 222.9 605.0 716.8

3 unchanged sentences

Depreciation, depletion and amortization 281.4 222.1 730.7 643.3

Impairments of assets — — — 34.5

Impairment of assets

115.0 — 115.0 34.5

Accretion of asset retirement obligations 14.6 13.2 43.1 39.0

Total exploration expenses, including undeveloped lease amortization

Exploration expenses, including undeveloped lease amortization

32.5 31.2 57.4 118.4

9 unchanged sentences

Results of Operations (Continued)

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

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

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Weighted average sales prices) 2025 2024 2025 2024

23 unchanged sentences

dollar equivalent.

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

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

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Average price for the period) 2025 2024 2025 2024

2 unchanged sentences

AECO (C$/MCF) 0.63 0.69 1.50 1.45

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 and six-month periods ended June 30, 2025 and 2024.

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

For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 .

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

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

45 unchanged sentences

Sales Volumes

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

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

For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 .

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

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

48 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024 2025 2024

14 unchanged sentences

$ 721.0 $ 753.2 $ 2,076.8 $ 2,345.3

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.

Revenues from production for the three months ended September 30, 2025, decreased by $32.2 million compared to the same period in 2024.

Revenues decreased primarily due to lower crude oil prices, reduced oil production in the Gulf of America from downtime relating to planned maintenance and ongoing workovers, and downtime in offshore Canada at Terra Nova and Hibernia related to well issues in the quarter.

These reductions were partially offset by higher production at Karnes and Catarina in the Eagle Ford Shale related to better well performance and new wells online, and higher sales volumes at Cascade & Chinook in the Gulf of America.

Revenues from production for the nine months ended September 30, 2025, decreased $268.5 million compared to the same period in 2024.

Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline of new wells, and downtime for maintenance at Khaleesi.

These decreases were partially offset by increased production in Eagle Ford Shale due to new wells at Karnes and Catarina, as well as in the Gulf of America at Mormont and Neidermeyer.

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

3 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

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

24 unchanged sentences

$ 48.1 $ 47.5 $ 2.51 $ 2.68 $ 151.1 $ 157.5 $ 2.91 $ 3.09

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.

For the three months ended September 30, 2025, lease operating expenses decreased by $38.5 million and transportation, gathering and processing expenses increased by $0.6 million compared to the same period in 2024.

In the Gulf of America, decreases in lease operating expenses primarily related to lower production volumes and handling fees and lower operating charges as a result of the acquisition of the BW Pioneer FPSO.

In addition, current quarter workover costs at Marmalard, Khaleesi and Samurai were lower than expenditures at Neidermeyer and Dalmatian in the prior year.

In the Eagle Ford Shale, lower operating expenses were due to cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization throughout the year, and were largely offset by higher production.

For the nine months ended September 30, 2025, lease operating expenses decreased by $111.8 million, and transportation, gathering and processing expenses decreased by $6.4 million compared to the same period in 2024.

In the Gulf of America, decreases primarily related to lower workover costs due to expenditures at Neidermeyer and Dalmatian in the prior year, which were partially offset by current year workovers at Marmalard, Khaleesi and Samurai.

Lower operating charges also occured as a result of the acquisition of the BW Pioneer FPSO earlier in the year.

In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, were partially offset by higher volume related costs.

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

3 unchanged sentences

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

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

11 unchanged sentences

$ 281.4 $ 222.1 $ 14.67 $ 12.56 $ 730.7 $ 643.3 $ 14.06 $ 12.61

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.

DD&A for the three months ended September 30, 2025 increased by $59.3 million compared to the same period in 2024.

The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S.

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

DD&A for the nine months ended September 30, 2025 increased by $87.4 million.

The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S.

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

Impairment of Assets

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.

For the three and nine months ended September 30, 2025, the Company impaired assets for $115.0 million related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions in the quarter, as certain projects in the field were less competitive for capital allocation.

There were no impairments for the three months ended September 30, 2024.

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

Exploration Expenses

1 unchanged sentence

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024 2025 2024

6 unchanged sentences

$ 32.5 $ 31.2 $ 57.4 $ 118.4

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

Exploration expenses for the three months ended September 30, 2025 increased by $1.3 million compared to the same period in 2024 due to higher geological and geophysical costs in the Gulf of America, and were partially offset by lower dry hole costs in the current period.

Dry hole costs in 2024 related to the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

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.

Exploration expenses for the nine months ended September 30, 2025 decreased by $61.0 million compared to the same period in 2024.

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

This was partially offset by higher exploration activity in Côte d'Ivoire.

Other expenses from E&P continuing operations for the three months ended September 30, 2025 decreased by $0.1 million compared to the same period in 2024.

Other expenses for the nine months ended September 30, 2025 increased by $17.7 million compared to the same period in 2024 due to no interest income received in the current year.

Income taxes for the three and nine months ended September 30, 2025 decreased by $3.0 million and $24.0 million, respectively, compared to the same periods in 2024.

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

Corporate 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 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).

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

For the three months ended September 30, 2025, the Corporate segment reported a loss of $18.6 million, a favorable variance of $15.1 million, compared to the same period in 2024.

The favorable variance was primarily due to a foreign exchange gain ($18.4 million) for the period, primarily relating to our Canadian subsidiary, combined with gains on derivative instruments ($3.9 million), and partially offset by higher income tax expense of $5.1 million.

The Corporate segment reported a loss of $122.7 million for the nine months ended September 30, 2025, an unfavorable variance of $33.8 million, compared to the same period in 2024.

The unfavorable variance was primarily due to higher foreign exchange losses ($31.5 million) and higher interest expense ($11.4 million) due to the timing of interest payments on long-term debt, and was partially offset by gains on derivative instruments ($8.4 million) due to fixed price sales contracts.

Financial Condition

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.

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

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

Financial Condition (Continued)

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

Six Months Ended

Nine Months Ended

September 30,

(Millions of dollars)

6 unchanged sentences

Effect of exchange rate changes on cash and cash equivalents (0.5) 0.8

Net (decrease) increase in cash and cash equivalents

$ (43.9) $ 16.5

Net increase (decrease) in cash and cash equivalents $ 2.4 $ (45.9)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the 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).

Net cash provided by continuing operations activities for the nine months ended September 30, 2025 was $297.3 million lower compared to the same period in 2024.

The decrease in cash flows from operations activities was primarily due to lower revenue from production ($268.5 million), timing of non-cash working capital ($52.3 million) settlements, and an increase in selling and general expenses ($19.8 million), partially offset by lower lease operating expenses ($111.8 million).

Cash Required by Investing Activities

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

Net cash required by investing activities for the nine months ended September 30, 2025 was $118.1 million higher compared to the same period in 2024.

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

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

Six Months Ended

Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

6 unchanged sentences

Total accrual basis capital expenditures are shown below.

Six Months Ended

Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

3 unchanged sentences

Total capital expenditures $ 867.6 $ 776.6

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.

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

Also contributing to the increase were higher exploratory drilling and field development in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign.

These increases were partially offset by lower exploration costs and development drilling

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

Financial Condition (Continued)

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

Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($257.6 million), Eagle Ford Shale ($296.4 million), Tupper Montney and Kaybob Duvernay ($113.0 million), and in Vietnam ($57.7 million).

Exploration costs in 2025 were $90.9 million, primarily comprised of activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05;

and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d'Ivoire related to long lead equipment purchases for the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.

Cash Required by Financing Activities

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

Net cash required by financing activities for the nine months ended September 30, 2025 decreased by $464.9 million compared to the same period in 2024.

In 2025, the cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.975 per share ($139.8 million), and distributions to the noncontrolling interest in MP GOM ($43.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($150.0 million).

In 2024, cash required by financing activities was for the repurchase of common shares ($300.1 million), cash dividends to shareholders ($136.2 million), distributions to the noncontrolling interest in MP GOM ($96.6 million), debt repurchases ($50.0 million), and withholding tax on stock-based incentive awards ($25.3 million).

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.

At September 30, 2025, the Company had approximately $1.6 billion of liquidity consisting of $426.0 million in cash and cash equivalents and $1,199.6 million available on its committed senior unsecured RCF with a major banking consortium.

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

As of 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.

As of September 30, 2025, the Company had $150.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48%.

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

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

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

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

included U.S.

dollar equivalents of approximately $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).

dollar equivalents of approximately $67.4 million, the majority of which was held in Canada ($28.9 million), Mexico ($8.0 million), the U.K.

($7.4 million) and Vietnam ($6.7 million).

In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S.

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Working Capital

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

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

Working capital

3 unchanged sentences

$ (50.2) $ (157.5)

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.

As of September 30, 2025, net working capital increased by $107.3 million compared to December 31, 2024.

The increase was primarily attributable to lower current operating lease obligations ($42.4 million), lower accounts payable ($42.5 million), and higher accounts receivable ($11.2 million).

Lower lease obligations were due to lower day rates related to an offshore drilling rig, ongoing lease amortization and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America.

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

Financial Condition (Continued)

Higher accounts receivable were due to higher tax receivables related to increased Vietnam development and exploration expenditures.

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

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

Capital Employed

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

June 30, 2025 December 31, 2024

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

September 30, 2025 December 31, 2024

(Millions of dollars) Amount % Amount %

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Total capital employed $ 6,546.6 100.0 % $ 6,468.8 100.0 %

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.

At September 30, 2025, long-term debt of $1,425.2 million increased by $150.7 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF.

The total of the fixed-rate notes had a weighted average maturity of 8.6 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity 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).

Murphy shareholders’ equity decreased by $72.9 million in 2025, primarily due to dividends ($139.8 million) and shares repurchased ($100.9 million), including excise tax, partially offset by net income ($92.3 million), foreign currency translation ($50.5 million), and awarded restricted stock ($20.3 million).

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

Critical Accounting Estimates

As of 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.

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

Accounting Changes and Recent Accounting Pronouncements

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Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

Adjusted net income and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods.

Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods.

Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results.

Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

The following table reconciles net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars, except per share amounts)

2025 2024 2025 2024

Net income attributable to Murphy (GAAP) 1

Net income (loss) attributable to Murphy (GAAP) 1

$ (3.0) $ 139.1 $ 92.3 $ 356.8

Discontinued operations (income) loss 0.5 0.6 (0.2) 2.1

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

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

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

Net income (loss) from continuing operations attributable to Murphy

(2.5) 139.7 92.1 358.9

Impairment of assets 1

92.0 — 92.0 34.5

Foreign exchange (gain) loss (13.4) 5.4 20.9 (10.6)

Unrealized (gain) loss on derivative instruments (2.5) 1.3 (3.9) 1.3

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

Total adjustments, before taxes 76.1 6.7 109.0 51.3

Income tax (benefit) expense related to adjustments

Income tax benefit related to adjustments

(15.5) (1.7) (23.8) (10.5)

Tax benefits on investments in foreign areas — (34.0) — (34.0)

Total adjustments, after taxes 60.6 (29.0) 85.2 6.8

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 58.1 $ 110.7 $ 177.3 $ 365.7

Net income from continuing operations per average diluted share (GAAP) $ 0.15 $ 0.83 $ 0.66 $ 1.43

Net income (loss) from continuing operations per average diluted share (GAAP)

$ ( 0.02 ) $ 0.93 $ 0.64 $ 2.35

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 0.41 $ 0.74 $ 1.23 $ 2.40

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Other Key Performance Metrics (Continued)

The following table reconciles net income attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.

The following table reconciles net income (loss) attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.

Three Months Ended

June 30, Six Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024 2025 2024

Net income attributable to Murphy (GAAP) 1

Net income (loss) attributable to Murphy (GAAP) 1

$ (3.0) $ 139.1 $ 92.3 $ 356.8

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EBITDA attributable to Murphy (Non-GAAP) $ 300.8 $ 378.3 $ 916.7 $ 1,109.8

Foreign exchange loss (gain)

Impairment of assets 1

92.0 — 92.0 34.5

Accretion of asset retirement obligations 1

Foreign exchange (gain) loss

(13.4) 5.4 20.9 (10.6)

Mark-to-market (gain) on derivative instruments

Accretion of asset retirement obligations 1

13.2 11.7 38.6 34.9

Impairment of assets

Unrealized (gain) loss on derivative instruments (2.5) 1.3 (3.9) 1.3

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

Discontinued operations (income) loss 0.5 0.6 (0.2) 2.1

(1.3) 0.6 (0.7) 1.5

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 390.6 $ 397.3 $ 1,064.1 $ 1,198.1

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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

Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

Net cash provided by continuing operations activities (GAAP) $ 998.2 $ 1,295.4

increase (decrease) in non-cash working capital

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

(decrease) increase in non-cash working capital

Operating cash flow excluding working capital adjustments 1,018.7 1,263.6

11 unchanged sentences

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