What changed in this filing

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Item 1. Financial Statements

2026-05-06 compared with 2025-11-05 · 394 added, 700 removed, 898 unchanged (55% of the section changed)

2 unchanged sentences

CONSOLIDATED BALANCE SHEETS

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

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

2026 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 at September 30, 2025 and 195,100,628 shares at December 31, 2024

Common Stock, par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2026 and 195,100,628 shares at December 31, 2025

195,101 195,101

11 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars, except per share amounts) 2026 2025

1 unchanged sentence

Revenue from production $ 732,354 $ 672,730

Sales of purchased natural gas — — — 3,742

Total revenue from sales to customers 732,354 672,730

6 unchanged sentences

Transportation, gathering and processing 47,061 48,851

Costs of purchased natural gas — — — 3,147

Exploration expenses, including undeveloped lease amortization 82,815 14,488

2 unchanged sentences

Accretion of asset retirement obligations 14,514 14,045

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

Other operating expense 4,441 5,629

2 unchanged sentences

Other income (loss)

Other income (loss) 15,271 ( 3,926 ) ( 14,631 ) 33,870

Other income 9,852 2,402

Interest expense, net ( 28,977 ) ( 23,523 )

1 unchanged sentence

( 19,125 ) ( 21,121 )

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

Income from continuing operations before income taxes 119,140 122,773

Income tax expense 49,945 32,722

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 (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

Income from continuing operations 69,195 90,051

Loss from discontinued operations, net of income taxes ( 542 ) ( 633 )

Net income including noncontrolling interest 68,653 89,418

Net income attributable to noncontrolling interest 15,667 16,382

NET INCOME ATTRIBUTABLE TO MURPHY $ 52,986 $ 73,036

NET INCOME PER COMMON SHARE – BASIC

Continuing operations $ 0.37 $ 0.51

Discontinued operations — —

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

NET INCOME (LOSS) PER COMMON SHARE – DILUTED

Net income $ 0.37 $ 0.51

NET INCOME PER COMMON SHARE – DILUTED

Continuing operations $ 0.37 $ 0.50

Discontinued operations — —

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

Net income $ 0.37 $ 0.50

Cash dividends per common share $ 0.350 $ 0.325

6 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2026 2025

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

Net income including noncontrolling interest $ 68,653 $ 89,418

Other comprehensive income (loss), net of tax

10 unchanged sentences

CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended

September 30,

Three Months Ended

(Thousands of dollars) 2026 2025

Operating Activities

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

Net income including noncontrolling interest $ 68,653 $ 89,418

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

Depreciation, depletion and amortization 254,376 194,160

Unsuccessful exploration well costs and previously suspended exploration costs 67,043 190

Deferred income tax expense 36,864 16,343

Accretion of asset retirement obligations 14,514 14,045

Long-term non-cash compensation 15,433 9,905

Deferred income tax expense 23,305 45,136

Amortization of undeveloped leases 2,270 1,654

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

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

(Income) loss from discontinued operations

( 172 ) 2,123

Impairment of assets 115,002 34,528

Loss from discontinued operations 542 633

Unrealized loss on derivative instruments — 8,916

Other operating activities, net ( 30,539 ) ( 11,799 )

Net decrease (increase) in non-cash working capital

( 20,473 ) 31,835

Net increase in non-cash working capital ( 107,972 ) ( 22,784 )

Net cash provided by continuing operations activities 321,184 300,681

4 unchanged sentences

Financing Activities

Retirement of debt ( 227,489 ) —

Early redemption of debt cost ( 2,369 ) —

Debt issuance 500,000 —

Debt issuance cost

Borrowings on revolving credit facility 175,000 250,000

Repayment of revolving credit facility ( 275,000 ) ( 50,000 )

Retirement of debt — ( 50,000 )

Repurchase of common stock ( 102,620 ) ( 300,132 )

Issue costs of revolving credit facility

Repurchase of common stock, including excise tax ( 777 ) ( 100,072 )

Cash dividends paid ( 50,173 ) ( 47,026 )

Withholding tax on stock-based incentive awards ( 7,669 ) ( 25,310 )

Distributions to noncontrolling interest — ( 6,955 )

Withholding tax on stock-based incentive awards ( 7,849 ) ( 7,673 )

Finance lease obligation payments ( 419 ) ( 116 )

Issue costs of revolving debt facility

Net cash required by financing activities

Net cash provided by financing activities

90,892 38,158

8 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars except number of shares) 2026 2025

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

Balance at beginning and end of period – par $ 1.00 , authorized 450,000,000 shares at March 31, 2026 and March 31, 2025, issued 195,100,628 shares at March 31, 2026 and March 31, 2025

$ 195,101 $ 195,101

6 unchanged sentences

Balance at beginning of period 6,691,318 6,773,289

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

Net income attributable to Murphy 52,986 73,036

Cash dividends paid ( 50,173 ) ( 47,026 )

9 unchanged sentences

Awarded restricted stock, net of forfeitures 22,354 19,683

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

Balance at end of period – 51,751,915 shares of common stock at March 31, 2026 and 52,384,566 shares of common stock at March 31, 2025, at cost

( 2,051,091 ) ( 2,076,211 )

2 unchanged sentences

Balance at beginning of period 118,317 147,593

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

Net income attributable to noncontrolling interest 15,667 16,382

Distributions to noncontrolling interest owners — ( 6,955 )

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 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.

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at March 31, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2026 and 2025, 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 2025 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.

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

Financial results for the three-month period ended March 31, 2026 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Reportable Segment Disclosures.

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

Improvements to Reportable Segment Disclosures .

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

Income Tax Disclosures .

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

Improvements to Income Tax Disclosures.

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

The Company adopted this standard in the fourth quarter of 2025.

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

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

Refer to Note P .

Interim period disclosures are largely unaffected by this update.

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

Recent Accounting Pronouncements

5 unchanged sentences

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

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

Income Tax Disclosures .

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

Improvements to Income Tax Disclosures.

The standard becomes effective for annual periods beginning after December 15, 2024.

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

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

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

The Company evaluates the applicability and impact of all ASUs.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

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

The Company explores for and produces oil and natural gas in select basins around the world.

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

2 unchanged sentences

crude oil, natural gas and natural gas liquids (NGLs).

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

owner and recognizes revenue only for its own share of the commingled production.

The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.

7 unchanged sentences

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

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

The Company’s revenues and other income for the three-month periods ended March 31, 2026 and 2025 were as follows.

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2026 2025

1 unchanged sentence

United States - Onshore $ 188,348 $ 109,458

$ 209,051 $ 161,965 $ 484,610 $ 450,463

United States - Offshore 1

1 unchanged sentence

Canada - Onshore 17,391 14,730

18,115 20,852 45,428 54,305

Canada - Offshore 53,336 74,469

35,211 80,226 155,421 178,327

Other 2,909 —

2 unchanged sentences

United States - Onshore 9,275 8,487

13,736 8,134 32,117 23,281

United States - Offshore 1

8,353 9,812 25,913 29,523

Canada - Onshore 1,318 1,747

1,094 2,402 4,363 5,434

Total natural gas liquids revenue 16,956 19,483

1 unchanged sentence

United States - Onshore 11,128 7,967

9,571 4,265 25,637 11,893

United States - Offshore 1

1 unchanged sentence

Canada - Onshore 82,695 74,320

53,103 54,057 195,483 170,871

Total natural gas revenue 119,973 102,228

Revenue from production 720,966 753,169 2,076,761 2,345,282

Sales of purchased natural gas 2

Canada - Onshore

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

Total revenue from sales to customers 732,354 672,730

2 unchanged sentences

Total revenues and other income $ 733,552 $ 665,711

1 Includes revenue attributable to noncontrolling interest in MP GOM.

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

Sales of purchased natural gas are reported when the contractual performance obligations are satisfied.

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

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

Contract Balances and Asset Recognition

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.

As of March 31, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 222.1 million and $ 165.3 million, respectively.

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

Based on a forward-looking expected loss model 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 September 30, 2025.

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

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

Based on a forward-looking expected loss model

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

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

The Company has not entered into any revenue contracts that have financing components as of March 31, 2026.

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

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

Performance Obligations

6 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 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:

As of March 31, 2026, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:

Location Commodity End Date Description Approximate Volumes

Natural Gas and NGLs Q1 2031 Deliveries from dedicated acreage in Eagle Ford Shale As produced

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

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

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

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

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

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

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

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

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

Canada Natural Gas Q4 2029

Contracts to sell natural gas at USD index pricing 25 MMCF/D

Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 MMCF/D

Canada Natural Gas Q4 2027 Contracts to sell natural gas at CAD fixed pricing 9 MMCF/D

Canada NGLs Q4 2026

1 unchanged sentence

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment

1 unchanged sentence

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 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.

As of March 31, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 266.8 million.

The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2026 and 2025.

(Thousands of dollars) 2026 2025

2 unchanged sentences

Capitalized exploratory well costs charged to expense ( 9,610 ) —

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)

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,

Balance at March 31 $ 266,810 $ 96,845

Capital additions of $ 84.6 million, for the three months ended March 31, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire;

the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in Vietnam;

and the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America.

In the first quarter of 2026, Murphy announced the successful discoveries of the Banjo #1 and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, which encountered 50 feet and 30 feet of net pay, respectively.

In addition, the Company also announced a successful appraisal well Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, in the Cuu Long Basin, located approximately 40 miles offshore of Vietnam.

Capital additions of $ 24.8 million, for the three months ended March 31, 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.

In the first quarter of 2026, the Company also announced the results of two exploration wells in Côte d’Ivoire;

the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and the Caracal-1X (Block CI-102) exploration well, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows.

Capitalized well costs charged to dry hole expense of $ 9.6 million, for the three months ended March 31, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire.

There were no capitalized well costs charged to dry hole expense for the three months ended March 31, 2025.

The preceding table excludes well costs of $ 57.5 million incurred and expensed directly to dry hole for the three months ended March 31, 2026.

In 2026, these costs primarily related to the Caracal-1X (Block CI-102) and Civette-1X (Block CI-502) exploration wells in Côte d’Ivoire.

The following table provides an aging of capitalized exploration well costs based on the date the drilling operations were initiated for each individual project.

(Thousands of dollars) Amount No.

of Wells Amount No.

Aging of capitalized well costs:

4 unchanged sentences

$ 266,810 9 $ 96,845 8

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

Of the $ 208.3 million of exploration well costs capitalized and classified as more than one year at March 31, 2026, $ 107.0 million was in Vietnam, $ 94.0 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei.

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

Property Additions

On July 1, 2025, the Company purchased additional working interests in 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.

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

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

There were 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)

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

BW Offshore (UK) Limited continues to provide operations and maintenance services under a five-year contract that began in 2025.

There were no impairments in the three months ended March 31, 2026 and 2025.

Note E – Financing Arrangements and Debt

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 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.

In the first quarter of 2026, the Company entered into an amended credit agreement governing a $ 2.0 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031.

All terms of the Amended RCF are substantially similar to the previous senior unsecured guaranteed revolving credit facility (RCF) credit agreement, with an exception for the following:

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

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

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

and Standard and Poor’s Rating Services, respectively.

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

At March 31, 2026, the Company had no outstanding borrowings under the Amended RCF and $ 0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF.

At March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91 %.

At March 31, 2026, the Company was in compliance with all covenants related to the Amended RCF.

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

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

Debt Offering

In the first quarter of 2026, the Company closed a public offering of $ 500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.50 % per annum and mature on February 15, 2034.

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

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

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

Debt Extinguishment

In the first quarter of 2026, the Company redeemed the remaining $ 78.9 million principal amount outstanding of its 5.875 % senior notes due 2027 (2027 Notes) and the remaining $ 148.6 million principal amount outstanding of its 6.375 % senior notes due 2028 (2028 Notes), for an aggregate $ 227.5 million.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows

Nine Months Ended

September 30,

Three Months Ended

(Thousands of dollars) 2026 2025

5 unchanged sentences

Increase (decrease) in income taxes payable 1,481 6,214

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

Net (increase) decrease in non-cash working capital $ ( 107,972 ) $ ( 22,784 )

Supplementary disclosures:

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

Interest paid, net of amounts capitalized of $ 3.9 million in 2026 and $ 1.1 million in 2025

3 unchanged sentences

(Increase) decrease in capital expenditure accrual ( 54,000 ) ( 42,442 )

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 nine-month periods ended September 30, 2025 and 2024 are shown in the following table.

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

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the three-month periods ended March 31, 2026 and 2025 are shown in the following table.

(Thousands of dollars) March 31, 2026 March 31, 2025

Balance at beginning of year $ 1,012,867 $ 1,008,884

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All pension plans are funded except for the U.S.

and Canadian nonqualified supplemental plans and the U.S.

and Canadian nonqualified supplemental plans and

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans (Continued)

directors’ plan.

4 unchanged sentences

the life insurance benefits are noncontributory.

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

(Thousands of dollars) 2025 2024 2025 2024

Service cost $ 1,683 $ 1,706 $ 84 $ 135

Interest cost 8,495 8,398 708 782

Expected return on plan assets ( 8,967 ) ( 8,366 ) — —

Estimated defined contribution provision 62 54 — —

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 )

Nine Months Ended September 30,

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2026 and 2025.

Three Months Ended March 31,

Pension Benefits Other Postretirement Benefits

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Estimated defined contribution provision 70 60 — —

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

Amortization of prior service cost (credit) 432 491 ( 133 ) ( 133 )

Recognized actuarial (gain) loss 1,644 1,891 ( 387 ) ( 1,056 )

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

Total net periodic benefit cost (credit) $ 2,971 $ 3,652 $ 332 $ ( 397 )

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

During the three-month period ended March 31, 2026, the Company made contributions of $ 7.0 million to its defined benefit pension and postretirement benefit plans.

Remaining funding in 2026 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 22.5 million.

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

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

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

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

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

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

These grants may be in the form of stock

The 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) authorizes the Committee to grant shares of the Company’s common stock and stock-based awards to employees.

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

The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term.

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

Shares underlying awards that have been canceled, expired, are forfeited, or otherwise not issued under an award shall not count as shares issued under the Plan.

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

During the three months ended March 31, 2026, the Committee granted the following awards from the 2025 Long-Term Plan:

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

Performance-based RSUs (TSR) 1

Performance-based RSUs 1

412,560 February 3, 2026 $ 32.67 Monte Carlo

Performance-based RSUs (ROACE) 1

129,990 February 4, 2025 $ 25.98 Average Stock Price

Time-based RSUs (Stock-Settled) 2

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661,960 February 3, 2026 $ 30.05 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.

1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) performance goals, measured over a three-year performance period based on (i) the Company’s TSR relative to a peer group and (ii) the Company’s absolute TSR performance, and are scheduled to vest at the end of the period subject to achievement of these conditions.

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

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All awards granted on or after May 12, 2021 were made 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:

During the three months ended March 31, 2026, 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

3 unchanged sentences

2,150 March 31, 2026 $ 41.25 Closing Stock Price

Time-Based RSUs 2

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

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.

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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.

Nine Months Ended

September 30,

Three Months Ended

(Thousands of dollars) 2026 2025

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income tax deduction under the current tax law.

Note J – Net Income (Loss) Per Common Share

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note J – Net Income Per Common Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month periods ended March 31, 2026 and 2025.

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Weighted-average shares) 2025 2024 2025 2024

(Weighted-average shares, except per share amounts)

Basic method 143,081,801 144,283,946

2 unchanged sentences

Diluted method 144,380,590 145,072,088

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,

NET INCOME PER COMMON SHARE – BASIC

$ 0.37 $ 0.51

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

NET INCOME PER COMMON SHARE – DILUTED

$ 0.37 $ 0.50

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 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.

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

For the three-month periods ended March 31, 2026 and 2025, the Company’s effective income tax rates were as follows:

Three months ended March 31, 41.9 % 26.7 %

The effective tax rate for the three-month period ended March 31, 2026 was above the U.S.

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

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

state tax expense;

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

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.

stock-based compensation;

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

federal rate.

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

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

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

3 unchanged sentences

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 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.

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

For the three-month period ended March 31, 2026, the Company received $ 0.1 million in net cash income tax refunds, compared to $ 1.6 million in net cash income tax refunds for the three-month period ended March 31, 2025.

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

As of March 31, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:

Canada – 2021.

and Malaysia – 2018.

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

On July 4, 2025, the current U.S.

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

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

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

The Company 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

Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.

The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.

The use of derivative instruments for risk management is covered by

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

operating policies and is closely monitored by the Company’s senior management.

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

2 unchanged sentences

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 September 30, 2025 and 2024.

The Company had no foreign currency exchange derivative instruments outstanding at March 31, 2026 and 2025.

Commodity Price Risks

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

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

During the first quarter of 2025, the Company entered into 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 September 30, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

During the three months ended March 31, 2026, the Company did no t have any crude oil or natural gas derivative contracts.

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

NYMEX Henry Hub

1 unchanged sentence

Fixed price derivative swap United States Natural Gas 40 $ 3.58 4/1/2025 6/30/2025

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 September 30, 2025 December 31, 2024

Commodity swaps Accounts receivable $ 2,197 $ —

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

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)

Fixed price derivative swap United States Natural Gas 60 $ 3.65 7/1/2025 9/30/2025

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

For the three-month periods ended March 31, 2026 and 2025, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:

(Thousands of dollars) Three Months Ended

September 30, Nine Months Ended September 30,

Type of Derivative Contract Statement of Operations Location 2026 2025

6 unchanged sentences

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

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

The fair value measurements for these assets and liabilities at March 31, 2026 and December 31, 2025, are shown in the following table.

March 31, 2026 December 31, 2025

(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 $ 21,947 $ — $ — $ 21,947 $ 22,205 $ — $ — $ 22,205

$ 21,947 $ — $ — $ 21,947 $ 22,205 $ — $ — $ 22,205

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 “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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.

2 unchanged sentences

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

There were no offsetting positions recorded at 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.

There were no offsetting positions recorded at March 31, 2026 and December 31, 2025.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at March 31, 2026 and December 31, 2025.

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

4 unchanged sentences

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

September 30, 2025 December 31, 2024

March 31, 2026 December 31, 2025

(Thousands of dollars) Carrying

3 unchanged sentences

$ 1,550,694 $ 1,468,657 $ 1,385,080 $ 1,326,101

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 tables.

Nine Months Ended September 30, 2025

Impairment Total

( Thousands of dollars )

Level 1 Level 2 Level 3

Property, plant and equipment:

Impaired proved properties

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

There were no impairment charges incurred in the three months ended March 31, 2026 and 2025.

Note M – Accumulated Other Comprehensive Loss

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.

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and March 31, 2026, and the changes during the three-month period ended March 31, 2026, are presented net of taxes in the following table.

(Thousands of dollars) Foreign

6 unchanged sentences

Net other comprehensive income (loss) ( 23,746 ) 1,401 ( 22,345 )

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.

Balance at March 31, 2026 $ ( 466,077 ) $ ( 110,495 ) $ ( 576,572 )

1 Reclassifications before taxes of $ 1.7 million are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2026.

See Note H for additional information.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Related income taxes of $ 0.3 million are included in "Income tax expense” on the Consolidated Statements of Operations for the three-month period ended March 31, 2026.

Note N – Environmental and Other Contingencies

5 unchanged sentences

import and export controls;

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

price controls;

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

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

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

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

Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and 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, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034.

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

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

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

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

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

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

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

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

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

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

Hazardous substances may have been disposed of or released on

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

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

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

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

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

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

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.

regulation over time.

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

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

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

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

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Note O – Common Stock Issued and Outstanding

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.

Activity in the number of shares of common stock issued and outstanding for the three-month periods ended March 31, 2026 and 2025 is shown below.

( Number of shares outstanding )

September 30, 2025 September 30, 2024

March 31, 2026 March 31, 2025

Beginning of period 142,785,152 145,845,124

7 unchanged sentences

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 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.

During the three months ended March 31, 2026, the Company did no t repurchase any shares of its common stock.

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

As of March 31, 2026, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

2 unchanged sentences

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

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

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

The Company has accounted for its former United Kingdom (U.K.), Malaysia and U.S.

3 unchanged sentences

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations

Three Months Ended September 30, 2025

Revenue from production

$ 613.4 $ 107.5 $ 0.1 $ 721.0 $ — $ 721.0

Gain on sales of assets and other operating income

0.3 0.5 — 0.8 11.4 12.2

Revenues from external customers 613.7 108.0 0.1 721.8 11.4 733.2

Lease operating expenses

Lease operating expenses and taxes other than income

95.6 41.2 0.4 137.2 — 137.2

Repair and maintenance

13.9 1.4 — 15.3 — 15.3

Workovers 31.8 0.1 — 31.9 — 31.9

Total lease operating expenses

141.3 42.7 0.4 184.4 — 184.4

Severance and ad valorem taxes 11.9 0.4 — 12.3 — 12.3

Transportation, gathering and processing 23.3 24.8 — 48.1 — 48.1

Selling and general expenses 1.9 5.4 2.2 9.5 21.4 30.9

Exploration Expenses

Geological and geophysical 19.1 0.1 1.1 20.3 — 20.3

Dry holes and previously suspended exploration costs

( 0.1 ) — 0.9 0.8 — 0.8

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

3.5 0.1 7.8 11.4 — 11.4

Total exploration expenses 22.5 0.2 9.8 32.5 — 32.5

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

Other operating expenses

5.7 0.1 0.2 6.0 ( 0.1 ) 5.9

Interest Income ( 0.4 ) — — ( 0.4 ) ( 2.7 ) ( 3.1 )

Interest expense, net of capitalization

— 0.1 — 0.1 24.6 24.7

Income tax expense

Current income tax expense (benefit)

1.0 ( 1.7 ) — ( 0.7 ) 2.8 2.1

Deferred income tax expense (benefit)

7.9 ( 0.2 ) ( 0.4 ) 7.3 ( 5.2 ) 2.1

Total income tax expense (benefit)

8.9 ( 1.9 ) ( 0.4 ) 6.6 ( 2.4 ) 4.2

Other segment costs (income)

0.8 0.4 ( 0.3 ) 0.9 ( 12.5 ) ( 11.6 )

Segment income (loss) - including NCI 1

$ 28.9 $ ( 6.1 ) $ ( 12.0 ) $ 10.8 $ ( 19.1 ) $ ( 8.3 )

Additions to property, plant, equipment $ 111.6 $ 26.0 $ 41.1 $ 178.7 $ 2.3 $ 181.0

Total assets at quarter-end

6,848.1 1,981.8 411.8 9,241.7 491.1 9,732.8

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

“Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income attributed to the Canada segment.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

3 unchanged sentences

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

Three Months Ended September 30, 2024

E&P Corporate and Discontinued Operations

Three Months Ended March 31, 2026

Revenue from production

$ 574.7 $ 154.8 $ 2.9 $ 732.4 $ — $ 732.4

Gain on sales of assets and other operating income

0.5 0.3 — 1.0 4.2 5.2

Revenues from external customers 597.0 157.9 ( 0.8 ) 754.1 4.2 758.3

Lease operating expenses

Lease operating expenses and taxes other than income

108.0 51.7 0.3 160.0 — 160.0

Repair and maintenance

15.1 1.8 — 16.9 — 16.9

Workovers 45.7 0.3 — 46.0 — 46.0

Total lease operating expenses

168.8 53.8 0.3 222.9 — 222.9

Severance and ad valorem taxes 10.1 0.3 — 10.5 — 10.5

Transportation, gathering and processing 26.3 21.2 — 47.5 — 47.5

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

Exploration Expenses

Geological and geophysical 9.9 0.1 2.8 12.8 — 12.8

Dry holes and previously suspended exploration costs

10.8 — 0.4 11.2 — 11.2

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

2.5 0.2 4.7 7.3 — 7.3

Total exploration expenses 23.2 0.3 7.9 31.3 — 31.3

Depreciation, depletion and amortization 179.3 42.8 — 222.1 1.5 223.6

Impairment of assets — — — — — —

Accretion of asset retirement obligations 10.9 2.1 0.2 13.2 — 13.2

Other operating expenses

4.8 0.1 0.5 5.4 0.1 5.5

Interest income

( 0.8 ) — — ( 0.8 ) ( 3.1 ) ( 3.9 )

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

Income tax expense

Current income tax expense (benefit)

0.8 8.2 ( 0.1 ) 8.9 2.1 11.0

Deferred income tax expense (benefit)

34.4 0.2 ( 34.0 ) 0.6 ( 9.5 ) ( 8.9 )

Total income tax expense (benefit)

35.2 8.4 ( 34.1 ) 9.5 ( 7.4 ) 2.1

Other segment costs (income)

1.8 — 0.1 1.9 6.4 8.3

Segment income (loss) - including NCI 1

$ 138.8 $ 24.2 $ 22.4 $ 185.4 $ ( 34.3 ) $ 151.1

Additions to property, plant, equipment $ 130.2 $ 13.5 $ 20.5 $ 164.2 $ 8.0 $ 172.2

Total assets at quarter-end

7,088.3 2,043.0 266.6 9,397.9 318.5 9,716.4

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations

Nine Months Ended September 30, 2025

Revenue from production

Gain on sale of assets and other operating income

0.8 0.4 — 1.2 — 1.2

Gain on sales of assets and other operating income

Total revenues and other income

575.5 155.2 2.9 733.6 — 733.6

Revenues from external customers 1,676.7 402.0 3.0 2,081.7 15.0 2,096.7

Lease operating expenses

17 unchanged sentences

Depreciation, depletion and amortization 216.9 34.0 1.1 252.0 2.4 254.4

Impairment of assets 115.0 — — 115.0 — 115.0

Accretion of asset retirement obligations 11.6 2.6 0.2 14.4 0.1 14.5

5 unchanged sentences

Income tax expense

Current income tax expense (benefit)

Current income tax expense

1.0 9.6 0.3 10.9 2.2 13.1

3 unchanged sentences

38.3 11.2 3.7 53.2 ( 3.3 ) 49.9

Other segment cost

Other segment costs (income)

1.1 0.4 0.3 1.8 ( 8.6 ) ( 6.8 )

4 unchanged sentences

6,916.5 1,980.3 660.7 9,557.5 478.1 10,035.6

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

3 unchanged sentences

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

Nine Months Ended September 30, 2024

E&P Corporate and Discontinued Operations

Three Months Ended March 31, 2025

Revenue from production

$ 507.4 $ 165.3 $ — $ 672.7 $ — $ 672.7

Sales of purchased natural gas

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

2.1 0.4 — 2.5 ( 9.5 ) ( 7.0 )

Gain on sales of assets and other operating income

Total revenues and other income

509.5 165.7 — 675.2 ( 9.5 ) 665.7

Revenues from external customers 1,936.1 413.8 3.4 2,353.3 4.2 2,357.5

Lease operating expenses

8 unchanged sentences

Transportation, gathering and processing 28.7 20.2 — 48.9 — 48.9

Costs of purchased natural gas

— 3.1 — 3.1 — 3.1

Selling and general expenses 2.0 6.0 1.9 9.9 21.0 30.9

7 unchanged sentences

Depreciation, depletion and amortization 159.4 32.4 0.1 191.9 2.3 194.2

Impairment of assets 34.5 — — 34.5 — 34.5

Accretion of asset retirement obligations 11.3 2.5 0.2 14.0 — 14.0

10 unchanged sentences

25.0 14.3 — 39.3 ( 6.6 ) 32.7

Other segment costs (income)

Other segment costs

0.9 0.4 0.2 1.5 0.4 1.9

4 unchanged sentences

7,046.3 1,963.4 345.7 9,355.4 464.9 9,820.3

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 %

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

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 September 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, 2025.

5 unchanged sentences

Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire.

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

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 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

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

Significant Company financial and operational highlights during the first quarter of 2026 were as follows:

• Increased production to 180,053 barrels of oil equivalent (BOE) per day (including NCI), up from 163,374 BOE per day in the first quarter of 2025;

• Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced dry holes at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire;

• Issued $500.0 million of 6.50% senior notes due 2034 (2034 Notes) and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;

• Upsized senior unsecured revolving credit facility from $1.35 billion to $2.0 billion and extended maturity from 2029 to 2031;

• Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.

Subsequent to the first quarter, the Company’s offer for four exploration blocks in offshore Cameroon was accepted, with finalization of the terms pending further discussions with the Republic of Cameroon.

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2026, was $69.2 million compared to net income of $90.1 million for the same period in 2025.

The results for 2026 were impacted by higher exploration expense ($68.3 million), higher depreciation, depletion and amortization expenses (DD&A) ($60.2 million), and higher income tax expense ($17.2 million) and were partially offset by higher revenues from production ($59.6 million), lower lease operating expenses ($61.6 million), and lower losses from derivative instruments ($9.5 million).

Higher exploration expenses in the current quarter were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons.

Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S.

and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S.

and offshore Canada.

Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period.

In addition, certain exploration expenses did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.

Higher volumes in the Eagle Ford Shale and onshore Canada were the primary contributors to higher revenues for the period and were partially offset by lower volumes in other segments.

Higher realized prices onshore U.S.

and both onshore and offshore Canada also contributed to the increase but were partially offset by lower realized prices offshore U.S.

Lower lease operating expenses are due to lower

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

Overview (Continued)

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.

workover costs in the current quarter.

Lower losses from derivative instruments were due to having no open derivative contracts during the first quarter of 2026.

For the three months ended March 31, 2026, total hydrocarbon production was 180,053 barrels of oil equivalent per day, an increase of 10% compared to the first quarter of 2025.

The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in the Gulf of America.

Higher production in the Eagle Ford Shale and Canada Onshore was primarily the result of new wells online in the current year at Karnes and Catarina in the U.S., and at Tupper Montney in Canada.

Lower offshore U.S.

production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

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

1 unchanged sentence

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

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

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.

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

International conflicts and 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 March 31, 2026, the West Texas Intermediate (WTI) crude oil futures price were $82.75 per barrel, whereas the crude oil futures price at the end of April 2026 was $90.56, reflecting a 9% increase in price.

As of May 4, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $93.58 per barrel.

Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.

Results of Operations

2 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2026 2025

4 unchanged sentences

Total exploration and production

10.8 185.4 238.7 513.0

Corporate and other (36.4) (48.2)

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

Income from continuing operations 69.2 90.0

Discontinued operations, net of tax 1

(0.5) (0.6) 0.2 (2.1)

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 (loss) attributable to Murphy

Net income including noncontrolling interest 68.7 89.4

Net income attributable to noncontrolling interest

Net income attributable to Murphy

$ 53.0 $ 73.0

7 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2026 2025

2 unchanged sentences

$ 732.4 $ 672.7

Sales of purchased natural gas

0.8 0.9 4.9 4.3

Total revenues and other income

721.8 754.1 2,081.7 2,353.3

Costs and expenses

2 unchanged sentences

Transportation, gathering and processing 47.1 48.9

Costs of purchased natural gas — — — 3.1

Depreciation, depletion and amortization 252.0 191.8

Impairment of assets

115.0 — 115.0 34.5

Accretion of asset retirement obligations 14.4 14.0

Exploration expenses, including undeveloped lease amortization

32.5 31.2 57.4 118.4

Selling and general expenses 15.1 9.9

2 unchanged sentences

Income tax provisions

6.6 9.6 63.4 87.4

Results of operations (excluding Corporate segment) 1

3 unchanged sentences

Results of Operations (Continued)

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

The following table contains the weighted average sales prices for the three-month periods ended March 31, 2026 and 2025:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Weighted average sales prices) 2026 2025

3 unchanged sentences

United States - Offshore 1

67.00 75.65 67.81 78.42

Canada - Onshore 2

56.33 66.18 59.46 68.62

Canada - Offshore 2

69.42 80.06 70.17 82.83

— — 72.97 78.20

Natural gas liquids – dollars per barrel

1 unchanged sentence

United States - Offshore 1

20.18 22.50 21.85 23.20

Canada - Onshore 2

26.88 34.00 32.54 34.64

Natural gas – dollars per thousand cubic feet

1 unchanged sentence

United States - Offshore 1

3.39 2.28 3.73 2.30

Canada - Onshore 2

1.22 1.34 1.68 1.56

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

dollar equivalent.

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

The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2026 and 2025:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Average price for the period) 2026 2025

5 unchanged sentences

Production Volumes

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

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2026 and 2025.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 29 .

Three Months Ended

September 30, Nine Months Ended

September 30,

(Barrels per day unless otherwise noted) 2026 2025

5 unchanged sentences

Canada - Onshore

3,495 3,425 2,799 2,888

Canada - Offshore

5,518 7,880 6,658 7,219

Other 224 255

3 unchanged sentences

United States - Onshore

8,042 4,640 5,905 4,312

United States - Offshore 1

4,500 4,739 4,344 4,644

Canada - Onshore

442 768 491 572

Total net natural gas liquids

12,984 10,147 10,740 9,528

Net natural gas – thousands of cubic feet per day

23 unchanged sentences

Sales Volumes

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

The following table contains hydrocarbons sold during the three-month periods ended March 31, 2026 and 2025.

For further discussion on volumes, please see the “ Revenues from Production ” section on page 29 .

Three Months Ended

September 30, Nine Months Ended

September 30,

(Barrels per day unless otherwise noted) 2026 2025

5 unchanged sentences

Canada - Onshore

3,495 3,425 2,799 2,888

Canada - Offshore

5,513 10,892 8,114 7,857

Other — — 152 159

Total net crude oil and condensate

2 unchanged sentences

United States - Onshore

8,042 4,640 5,905 4,312

United States - Offshore 1

4,500 4,739 4,344 4,644

Canada - Onshore

442 768 491 572

Total net natural gas liquids

12,984 10,147 10,740 9,528

Net natural gas – thousands of cubic feet per day

26 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2026 2025

3 unchanged sentences

United States - Natural gas liquids

22.1 17.9 58.0 52.8

United States - Natural gas

25.3 16.6 78.0 47.6

53.3 101.1 200.9 232.6

Canada - Natural gas liquids

1.1 2.4 4.4 5.4

Canada - Natural gas

53.1 54.1 195.5 170.9

0.1 (0.8) 3.0 3.4

Total revenue from production

$ 732.4 $ 672.7

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)

Results of Operations (Continued)

Revenues from production for the three months ended March 31, 2026, increased $59.6 million compared to the same period in 2025.

New wells in the Karnes and Catarina fields in the Eagle Ford Shale were the primary contributor to higher revenues for the period, contributing both higher volumes and realized prices.

Canada also realized higher prices, but overall revenues were lower due to fewer cargoes offshore Canada compared to 2025.

In the Gulf of America, both production and realized prices were lower compared to the first quarter of 2025.

Lower offshore U.S.

production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

Lease Operating and Transportation, Gathering and Processing Expenses

The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:

Three Months Ended

September 30, Nine Months Ended

September 30,

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

Three Months Ended March 31,

(Millions of dollars)

(Dollars per equivalent barrel)

23 unchanged sentences

$ 47.1 $ 48.9 $ 2.92 $ 3.31

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)

Results of Operations (Continued)

For the three months ended March 31, 2026, lease operating expenses decreased by $61.6 million, and transportation, gathering and processing expenses decreased by $1.8 million compared to the same period in 2025.

Lower lease operating expenses are due to lower workover costs in the Gulf of America in the current quarter, particularly at the Samurai field.

Further decreases in the Gulf of America are attributable to lower vessel rental costs as a result of the purchase of the Pioneer FPSO in 2025.

Offshore Canada realized lower operating costs in the current quarter due to fewer cargoes in 2026 compared to 2025.

Depreciation, Depletion and Amortization Expenses

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

Three Months Ended

September 30, Nine Months Ended

September 30,

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

Three Months Ended March 31,

(Millions of dollars)

(Dollars per equivalent barrel)

10 unchanged sentences

$ 252.0 $ 191.8 $ 15.62 $ 13.00

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

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.

DD&A for the three months ended March 31, 2026 increased by $60.2 million.

Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S.

and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S.

and offshore Canada.

Exploration Expenses

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2026 2025

6 unchanged sentences

$ 82.8 $ 14.5

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.

Exploration expenses for the three months ended March 31, 2026 increased by $68.3 million compared to the same period in 2025.

Income taxes for the three months ended March 31, 2026 increased by $13.9 million compared to the same period in 2025.

Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period.

In addition, higher exploration expenses, mainly due to dry hole expenses recognized related to Côte d’Ivoire, did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.

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

Results of Operations (Continued)

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 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.

The Corporate segment reported a loss of $36.4 million for the three months ended March 31, 2026, a favorable variance of $11.8 million, compared to the same period in 2025.

The favorable variance was primarily due to no losses on derivative instruments ($9.5 million) in the current quarter and higher foreign exchange gains ($8.8 million).

These changes were partially offset by higher interest expense ($5.3 million) due to costs related to the redemption of the 2027 Notes and 2028 Notes.

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured RCF.

The Company’s liquidity requirements, both in the short-term and long-term, consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF.

The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases.

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 twelve months and the foreseeable future.

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

Financial Condition (Continued)

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

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

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars)

3 unchanged sentences

(410.5) (369.8)

Net cash required by financing activities

(143.9) (608.8)

Net cash provided by financing activities

Effect of exchange rate changes on cash and cash equivalents — 0.3

1 unchanged sentence

Cash Provided by Continuing Operations Activities

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).

Net cash provided by continuing operations activities for the three months ended March 31, 2026 was $20.5 million higher compared to the same period in 2025.

The increase in cash flows from operations activities was primarily due to higher realized prices and volumes resulting in higher revenue from production ($59.6 million) and lower lease operating expenses ($61.6 million), partially offset by the timing of net non-cash working capital ($85.2 million) and changes in other operating activities, net ($18.7 million), primarily due to fluctuations in foreign exchange rates ($8.9 million) and higher expenditures for asset retirements ($8.8 million).

Cash Required by Investing Activities

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.

Net cash required by investing activities for the three months ended March 31, 2026 was $40.7 million higher compared to the same period in 2025.

The increase was primarily due to higher acquisition capital ($21.3 million) and higher property additions and dry hole costs ($19.4 million).

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

Financial Condition (Continued)

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

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2026 2025

Property additions and dry hole costs per the cash flow statements

$ 827.0 $ 733.3

Acquisition of oil properties per the cash flow statements

Property additions and dry hole costs $ 387.8 $ 368.4

Acquisition of oil and natural gas properties 22.7 1.4

Geophysical and other exploration expenses 13.4 11.6

2 unchanged sentences

Total accrual basis capital expenditures are shown below.

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2026 2025

3 unchanged sentences

Total capital expenditures $ 477.9 $ 424.8

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

Higher capital expenditures in the three months ended March 31, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory and development drilling in the Gulf of America, and higher development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign.

These increases were partially offset by lower field development costs in the Gulf of America due to the prior year spend on the Pioneer FPSO purchase in the Gulf of America.

Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($105.8 million), Eagle Ford Shale ($98.9 million), Tupper Montney and Kaybob Duvernay ($54.8 million), and in Vietnam ($24.0 million).

Exploration costs in 2026 were $178.1 million, primarily comprised of activities in Côte d'Ivoire related to exploration drilling for Bubale-1X (Block CI-709), Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells.

Exploration costs were also driven by activities in the Gulf of America including lease acquisitions and exploration drilling at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Vietnam for the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 exploration well.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2026 increased by $52.7 million compared to the same period in 2025.

In 2026, the cash provided by financing activities was principally from a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million.

The bond issuance was partially offset by the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), cash dividends to shareholders of $0.350 per share ($50.2 million), and $20.0 million in debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance.

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

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 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 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 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.

At March 31, 2026, the Company had approximately $2.4 billion of liquidity consisting of $378.8 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured Amended RCF with a major banking consortium.

The Company’s $2.0 billion senior unsecured Amended RCF expires in January 2031.

As of March 31, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF.

At March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%.

At March 31, 2026, the Company was in compliance with all covenants related to the Amended RCF.

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

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

As of March 31, 2026, cash and cash equivalents held outside the U.S.

included U.S.

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).

dollar equivalents of approximately $94.6 million, the majority of which was held in Canada ($35.2 million), Côte d'Ivoire ($24.8 million), Vietnam ($10.5 million), Mexico ($7.9 million), Brunei ($6.9 million), and the U.K.

($6.3 million) .

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

2 unchanged sentences

Working Capital

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

(Millions of dollars) March 31, 2026 December 31, 2025

Working capital

3 unchanged sentences

$ (197.2) $ (246.0)

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.

As of March 31, 2026, net working capital increased by $48.8 million compared to December 31, 2025.

The increase was primarily attributable to higher accounts receivable ($120.5 million) and lower current operating lease obligations ($8.6 million), partially offset by higher accounts payable ($73.6 million).

Higher accounts receivable and accounts payable were due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively.

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 Pioneer FPSO in the Gulf of America.

Capital Employed

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

September 30, 2025 December 31, 2024

A summary of capital employed at March 31, 2026 and December 31, 2025 follows.

March 31, 2026 December 31, 2025

(Millions of dollars) Amount % Amount %

3 unchanged sentences

Total capital employed $ 6,647.0 100.0 % $ 6,501.0 100.0 %

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.

At March 31, 2026, long-term debt of $1,548.1 million increased by $165.5 million compared to December 31, 2025, primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF.

The total of the fixed-rate notes had a weighted average maturity of 8.9 years and a weighted average coupon of 6.2%.

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).

Murphy shareholders’ equity decreased by $19.5 million in 2026, primarily due to dividends ($50.2 million), foreign currency translation ($23.7 million), partially offset by net income ($53.0 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.

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

Critical Accounting Estimates

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.

As of March 31, 2026, 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, 2025.

Accounting Changes and Recent Accounting Pronouncements

9 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars, except per share amounts)

2025 2024 2025 2024

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 (loss) from continuing operations attributable to Murphy

(2.5) 139.7 92.1 358.9

Impairment of assets 1

Net income attributable to Murphy (GAAP) 1

$ 53.0 $ 73.0

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

Discontinued operations loss 0.5 0.6

Net income from continuing operations attributable to Murphy

Foreign exchange gain (9.4) —

Unrealized loss on derivative instruments — 8.9

Total adjustments, before taxes (9.4) 8.9

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)

Income tax (benefit) expense related to adjustments

Total adjustments, after taxes (7.0) 7.1

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

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

Adjusted net income from continuing operations attributable to Murphy

$ 46.5 $ 80.7

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

$ 0.37 $ 0.50

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 0.32 $ 0.56

4 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2026 2025

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

Net income attributable to Murphy (GAAP) 1

$ 53.0 $ 73.0

2 unchanged sentences

Depreciation, depletion and amortization expense 1

275.0 215.7 713.2 625.8

EBITDA attributable to Murphy (Non-GAAP) 1

Exploration expenses

$ 378.8 $ 316.6

Exploration expenses 1

EBITDAX attributable to Murphy (Non-GAAP) 1

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

Impairment of assets 1

$ 461.6 $ 331.1

Foreign exchange (gain) loss

EBITDA attributable to Murphy (Non-GAAP) 1

$ 378.8 $ 316.6

Foreign exchange gain

Accretion of asset retirement obligations 1

13.2 11.7 38.6 34.9

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

Unrealized loss on derivative instruments — 8.9

Discontinued operations loss 0.5 0.6

Adjusted EBITDA attributable to Murphy (Non-GAAP) 1

Other exploration expenses 2

$ 382.9 $ 338.6

Exploration expenses 1

Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1

$ 465.7 $ 353.1

1 Excludes amounts attributable to a noncontrolling interest in MP GOM.

2 Other exploration expenses consist of exploration expenses as reported in the consolidated statement of operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.

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

4 unchanged sentences

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

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2026 2025

Net cash provided by continuing operations activities (GAAP) $ 321.2 $ 300.7

(decrease) increase in non-cash working capital

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

increase in non-cash working capital

Operating cash flow excluding working capital adjustments (Non-GAAP)

property additions and dry hole costs 1

2 unchanged sentences

cash dividends paid (50.2) (47.0)

(139.8) (136.2)

distributions to noncontrolling interest — (7.0)

(43.2) (96.6)

debt costs (22.4) —

withholding tax on stock-based incentive awards (7.8) (7.7)

1 unchanged sentence

Adjusted free cash flow (Non-GAAP) $ (61.7) $ (108.0)

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

1 Property additions for the three months ended March 31, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, including amounts attributable to a noncontrolling interest in MP GOM.

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

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

As discussed in the “ Results of Operations ” section discussing revenues, on page 29 , lower average crude oil and higher natural gas pricing during the first quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on May 4, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.

WTI ($/BBL) 93.58 76.88

NYMEX ($/MMBTU) 3.39 3.64

AECO (US$ Equivalent/MCF) 1.37 1.79

The regional conflict involving Iran has contributed to heightened geopolitical risk and significant volatility in global energy and shipping markets, primarily due to disruptions affecting transit through the Strait of Hormuz, which is a critical passage for oil, LNG, and other refined products.

Although these developments have led to higher commodity prices, these developments have also led to increased transportation and insurance costs, and broader uncertainty across global supply chains, which may indirectly affect the Company through fluctuations in oil and gas prices, changes in demand, and higher operating or input costs.

During the period, the Company has not experienced direct physical disruption to its operations, and the Company’s financial and operating results have been favorably impacted by price volatility.

Looking forward, a prolonged or escalating conflict could further disrupt global energy flows, exacerbate price volatility, constrain access to markets or services, and adversely affect macroeconomic conditions, which could materially impact the Company’s future operating results, cash flows, and financial position.

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

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

On July 4, 2025, the current U.S.

Administration signed into law the OBBBA legislation, which includes a broad range of tax reform provisions affecting corporations.

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

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

Similarly, we cannot predict the impact that political instability or armed conflict in oil and natural gas producing regions, such as in Russia and Ukraine, the Middle East, and Venezuela, may have on pricing, global supply and demand for oil and gas.

It is also uncertain how production quota decisions by OPEC and OPEC+, along with changes in membership, may influence pricing and the global supply–demand balance.

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

For the second quarter of 2026, production is expected to average between 161.0 and 169.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company’s capital expenditures for 2026 are expected to be between $1,200 million and $1,300 million, excluding noncontrolling interest.

This range excludes noncontrolling interest of $53.0 million.

In the Gulf of America, Murphy will continue developing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter.

In addition, the Company commenced drilling at the Chinook #8 (Walker Ridge 425) development well.

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

Outlook (Continued)

The Company commenced drilling on its third Côte d’Ivoire exploration well, Bubale-1X (Block CI-709), during the first quarter, with results expected in the second quarter.

The appraisal program at the Hai Su Vang (Golden Sea Lion) prospect in Vietnam is continuing on schedule following the successful completion of the Hai Su Vang-2X (Block 15-2/17) appraisal well in the first quarter.

Also in the first quarter, the Company began drilling the Hai Su Vang-3X (Block 15-1/05) appraisal well.

Hai Su Vang-3X is then expected to be followed by the Hai Su Vang-4X (Block 15-2/17) appraisal well.

Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with scheduled first oil anticipated in the fourth quarter of 2026.

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

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

The Company will primarily fund its capital program in 2026 using operating cash flow and available cash.

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

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

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

Based on current market conditions and our planned exploration and appraisal program, the Company is currently more likely to use available adjusted Free Cash Flow for share repurchases than bond repayment.

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of March 31, 2026.

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

As of May 4, 2026, the Company has entered into forward fixed price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

(MMCF/d) Price/MCF Remaining Period

Area Commodity Type 1

Start Date End Date

Canada Natural Gas Fixed price forward sales 78 C$2.94 4/1/2026 6/30/2026

Canada Natural Gas Fixed price forward sales 78 C$2.94 7/1/2026 9/30/2026

Canada Natural Gas Fixed price forward sales 59 C$3.00 10/1/2026 12/31/2026

Canada Natural Gas Fixed price forward sales 9.5 C$3.14 1/1/2027 12/31/2027

1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.

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