What changed in this filing

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Item 1. Financial Statements

2025-05-07 compared with 2024-11-07 · 513 added, 625 removed, 743 unchanged (60% 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,

2025 December 31,

9 unchanged sentences

Operating lease assets 714,091 777,536

Deferred income taxes – 435

Deferred charges and other assets 55,537 50,011

8 unchanged sentences

Other accrued liabilities 90,566 117,802

Current asset retirement obligations 77,452 48,080

Total current liabilities 1,008,523 942,814

16 unchanged sentences

Total liabilities and equity $ 9,820,323 $ 9,667,479

See Notes to Consolidated Financial Statements, page 7 .

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

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

4 unchanged sentences

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

Gain on sale of assets and other income 6,506 5,879 9,834 9,365

Gain on sale of assets and other operating income 2,440 1,564

Total revenues and other income 665,711 796,412

8 unchanged sentences

Accretion of asset retirement obligations 14,045 12,774

Other operating expense 5,450 4,385 10,497 21,333

Impairment of assets — 34,528

Other operating expense 5,629 7,266

Total costs and expenses 521,817 642,355

1 unchanged sentence

Other income (loss)

Other (loss) income ( 3,926 ) 8,811 33,870 1,044

Other income 2,402 11,551

Interest expense, net ( 23,523 ) ( 20,021 )

7 unchanged sentences

NET INCOME ATTRIBUTABLE TO MURPHY $ 73,036 $ 90,002

INCOME (LOSS) PER COMMON SHARE – BASIC

NET INCOME (LOSS) PER COMMON SHARE – BASIC

Continuing operations $ 0.51 $ 0.60

1 unchanged sentence

Net income $ 0.51 $ 0.59

INCOME (LOSS) PER COMMON SHARE – DILUTED

NET INCOME (LOSS) PER COMMON SHARE – DILUTED

Continuing operations $ 0.50 $ 0.60

5 unchanged sentences

Diluted 145,072 153,817

See Notes to Consolidated Financial Statements, page 7 .

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024

7 unchanged sentences

Comprehensive income including noncontrolling interest 88,615 80,040

Comprehensive income (loss) attributable to noncontrolling interest 12,018 22,462 65,197 38,701

Comprehensive income attributable to noncontrolling interest 16,382 24,656

COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY $ 72,233 $ 55,384

See Notes to Consolidated Financial Statements, page 7 .

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended

September 30,

Three Months Ended

(Thousands of dollars) 2025 2024

3 unchanged sentences

Depreciation, depletion and amortization 194,160 211,134

Impairment of assets 34,528 –

Unsuccessful exploration well costs and previously suspended exploration costs 69,548 107,825

Deferred income tax expense 16,343 19,478

1 unchanged sentence

Long-term non-cash compensation 9,905 9,851

Amortization of undeveloped leases 7,707 8,215

Mark-to-market loss on derivative instruments

Amortization of undeveloped leases 1,654 2,793

Loss from discontinued operations

Contingent consideration payment – ( 139,574 )

Mark-to-market loss on contingent consideration

Unsuccessful exploration well costs and previously suspended exploration costs 190 32,437

Impairment of assets — 34,528

Other operating activities, net ( 11,799 ) ( 15,381 )

Net decrease (increase) in noncash working capital

Net (increase) in non-cash working capital

( 22,784 ) ( 24,353 )

3 unchanged sentences

Acquisition of oil and natural gas properties ( 1,364 ) —

Proceeds from sales of property, plant and equipment – 102,913

Net cash required by investing activities ( 369,785 ) ( 249,085 )

2 unchanged sentences

Repayment of revolving credit facility ( 50,000 ) ( 100,000 )

Retirement of debt ( 50,000 ) ( 248,675 )

Repurchase of common stock ( 100,072 ) ( 50,000 )

3 unchanged sentences

Finance lease obligation payments ( 116 ) ( 164 )

Contingent consideration payment – ( 60,243 )

Issue costs of debt facility – ( 20 )

Net cash required by financing activities ( 608,770 ) ( 547,359 )

Net cash provided (required) by financing activities

38,158 ( 144,208 )

Effect of exchange rate changes on cash and cash equivalents 291 858

Net decrease in cash and cash equivalents

Net (decrease) increase in cash and cash equivalents

( 30,655 ) 6,356

1 unchanged sentence

Cash and cash equivalents at end of period $ 392,914 $ 323,430

See Notes to Consolidated Financial Statements, page 7 .

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

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars except number of shares) 2025 2024

Common Stock – par $ 1.00 , authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2024 and 195,100,628 shares at September 30, 2023

Balance at beginning and end of period $ 195,101 $ 195,101 $ 195,101 $ 195,101

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

$ 195,101 $ 195,101

Capital in Excess of Par Value

10 unchanged sentences

Balance at beginning of period ( 628,072 ) ( 521,117 )

Foreign currency translation gain (loss), net of income taxes 17,764 ( 39,353 ) ( 34,588 ) ( 2,601 )

Foreign currency translation, net of income taxes ( 1,667 ) ( 35,528 )

Retirement and postretirement benefit plans, net of income taxes 864 910

13 unchanged sentences

Total Equity $ 5,277,279 $ 5,492,505

See Notes to Consolidated Financial Statements, page 7 .

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 unchanged sentence

Note A – Basis of Presentation

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all accruals necessary to present fairly the Company’s financial position as at September 30, 2024 and December 31, 2023, and the results of operations, statements of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2024 and 2023, 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, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2025 and 2024, in conformity with U.S.

generally accepted accounting principles (GAAP).

2 unchanged sentences

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

Financial results for the three-month and nine-month periods ended September 30, 2024 are not necessarily indicative of future results.

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

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

None affecting the Company.

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.

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

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

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

Refer to Note P .

Recent Accounting Pronouncements

Expense Disaggregation Disclosures.

In November 2024 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40):

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

Disaggregation of Income Statement Expenses.

2 unchanged sentences

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

Murphy is currently evaluating the impact of adopting the standard.

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 .

3 unchanged sentences

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

Murphy is currently evaluating the impact of adopting this standard.

Reportable Segment Disclosures.

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

Improvements to Reportable Segment Disclosures.

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

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

The standard does not affect our determination of reportable segments.

Murphy will adopt Update 2023-07 in the period required, and we do not expect the adoption to have a material impact on our consolidated financial position, operating results and cash flows.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

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

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

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

the United States (U.S.) and Canada.

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

crude oil and condensate, natural gas liquids (NGL), and natural gas.

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

crude oil, natural gas and 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.

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

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

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

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

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

Revenue recognized is largely index-based with price adjustments for floating market differentials.

6 unchanged sentences

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, 2024 and 2023 were as follows.

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Thousands of dollars) 2025 2024

12 unchanged sentences

United States - Onshore

8,134 9,953 23,281 24,763

United States - Offshore 1

9,812 10,908 29,523 37,078

Canada - Onshore

2,402 2,539 5,434 7,519

Total natural gas liquids revenue 19,483 19,647

1 unchanged sentence

United States - Onshore

4,265 6,035 11,893 15,623

United States - Offshore 1

6 unchanged sentences

Canada - Onshore

– 7,877 3,742 64,628

Total sales of purchased natural gas — 245

1 unchanged sentence

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

Gain on sale of assets and other income 6,506 5,879 9,834 9,365

Gain on sale of assets and other operating income 2,440 1,564

Total revenues and other income $ 665,711 $ 796,412

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.

Contract Balances and Asset Recognition

As of September 30, 2024, and December 31, 2023, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $ 165.1 million and $ 193.7 million, respectively.

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

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, 2024.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

Performance Obligations

1 unchanged sentence

Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities.

As a result of this assessment for the Company,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract.

2 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, 2024, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:

Long-Term Contracts Outstanding at September 30, 2024

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

Location Commodity End Date Description Approximate Volumes

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

Canada Natural Gas Q4 2024 Contracts to sell natural gas at USD index pricing 31 MMCFD

Canada Natural Gas Q4 2024 Contracts to sell natural gas at CAD fixed pricing 124 MMCFD

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

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

Natural Gas and NGLs Q2 2030 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 2025 Contracts to sell natural gas at CAD fixed pricing 40 MMCFD

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

Canada Natural Gas Q4 2026 Contracts to sell natural gas at CAD fixed pricing 50 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 NGL Q2 2025 Contracts to sell NGL at CAD index pricing As produced

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

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

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

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

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

Note D – Property, Plant and Equipment

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, 2024, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 51.1 million.

The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2024 and 2023.

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

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

(Thousands of dollars) 2025 2024

1 unchanged sentence

Additions pending the determination of proved reserves 24,790 11,538

Reclassifications to proved properties based on the

determination of proved reserves – ( 1,065 )

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

Balance at September 30 $ 51,099 $ 185,477

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

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

Capital additions of $ 28.5 million are mainly for Ocotillo #1 (Mississippi Canyon 40) exploratory well in the Gulf of Mexico and Hai Su Vang #1 (Block 15/2-17) and Lac Da Hong #1 (Block 15-1/05) exploratory wells in Vietnam.

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

The preceding table excludes well costs of $ 43.0 million and $ 81.7 million incurred and expensed directly to dry hole for the nine months ended September 30, 2024 and 2023, respectively.

In 2024, these costs primarily include $ 25.8 million for the Orange #1 (Mississippi Canyon 216) and $ 11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of Mexico.

In 2023, the amount primarily includes $ 80.3 million for the Chinook #7 (Walker Ridge 425) exploration well in the Gulf of Mexico.

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

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

September 30,

March 31, 2025.

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

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

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

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

(Thousands of dollars) Amount No.

of Projects Amount No.

of Wells Amount No.

Aging of capitalized well costs:

4 unchanged sentences

$ 96,845 8 $ 34,185 7

Of the $ 22.5 million of exploratory well costs capitalized more than one year at September 30, 2024, $ 15.1 million was in Vietnam, $ 4.7 million was in Canada, and $ 2.7 million was in Brunei.

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

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

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

There were pre-tax impairments of $ 34.5 million in the nine months ended September 30, 2024 r elated to the Calliope field, in the Gulf of Mexico, where operational issues led to a reserve reduction.

There were no impairments in the three and nine months en ded September 30, 2023.

On September 15, 2023, the Company completed the divestment of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada, effective March 1, 2023, for net cash proceeds of C$ 139.0 million.

No gain or loss was recorded related to this transaction.

Property Additions

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

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

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

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

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

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

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

Note E – Financing Arrangements and Debt

Revolving Credit Facility

As of September 30, 2024, the Company had an $ 800.0 million revolving credit facility (RCF).

The RCF is a senior unsecured guaranteed facility was set to expire on November 17, 2027.

At September 30, 2024, the Company had no 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, 2024, the interest rate in effect on borrowings under the RCF would have been 7.20 %.

At September 30, 2024, the Company was in compliance with all covenants related to the RCF.

Subsequent Event - Revolving Credit Facility

On October 7, 2024, the Company entered into a credit agreement governing a $ 1,200.0 million senior unsecured guaranteed revolving credit facility (New RCF) with a maturity date on October 7, 2029.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt (Continued)

RCF, which is effective October 2024, extends the borrowing term and increases the borrowing capacity of the previous RCF.

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

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

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

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

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

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

Government Securities Business Day, the immediately preceding U.S.

Government Securities Business Day) plus 1 %.

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

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

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

and Standard and Poor’s Rating Services, respectively, as set forth in the grid included in the full text of the credit agreement governing the New RCF.

The Company has incurred $ 12.4 million in transaction costs and will record the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which will be amortized to interest expense over the term of the New 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 September 2023, the Company redeemed the remaining $ 248.7 million principal amount outstanding of its 5.750 % senior notes due 2025 (2025 Notes).

The non-cash costs of the debt extinguishment of $ 0.9 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2023.

Debt Offering

On September 19, 2024, the Company announced the public offering (the Offering) of $ 600.0 million aggregate principal amount of 6.000 % senior notes due 2032.

This Offering was pursuant to the 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.

Subsequent to quarter end, the shelf registration statement was renewed through October 15, 2027.

Subsequent Event - Debt Offering

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

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

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

The proceeds of the $ 600.0 million notes will be used to fund the repurchase and repayment of debt.

To date, the Company has repurchased and canceled an aggregate $ 521.1 million of its notes, comprised of:

$ 258.8 million of the 2027 Notes, $ 200.2 million of the 2028 Notes and $ 62.1 million of the 7.050 % senior notes due 2029 (2029 Notes).

The total cost of the debt extinguishment was $ 18.2 million:

consisting of cash costs of $ 14.9 million and non-cash costs of $ 3.3 million.

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

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

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

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

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

Nine Months Ended

September 30,

Supplemental Information to Statement of Cash Flows

Three Months Ended

(Thousands of dollars) 2025 2024

5 unchanged sentences

Increase (decrease) in income taxes payable 6,214 3,703

Net decrease (increase) in noncash working capital $ 31,835 $ ( 142,788 )

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

Supplementary disclosures:

Cash income taxes paid, net of refunds $ 12,519 $ 12,737

Net cash income taxes (refunded) paid $ ( 1,632 ) $ 405

Interest paid, net of amounts capitalized of $ 1.1 million in 2025 and $ 3.9 million in 2024

48,708 78,169

Non-cash investing activities:

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(Increase) decrease in capital expenditure accrual ( 42,442 ) ( 12,948 )

1 Excludes payable balances relating to contingent consideration for prior acquisitions.

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, 2024 and 2023 are shown in the following table.

(Thousands of dollars) September 30, 2024 September 30, 2023

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

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

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

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( 77,452 ) ( 17,797 )

Noncurrent portion of liability $ 929,965 $ 859,123

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

Non-current portion of liability $ 954,709 $ 916,815

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

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

Note H – Employee and Retiree Benefit Plans

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans (Continued)

The Company has defined benefit pension plans that are noncontributory and cover most full-time employees.

Note H – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees.

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

and Canadian nonqualified supplemental plan and the U.S.

director’s plan.

and Canadian nonqualified supplemental plans and the U.S.

directors’ plan.

tax qualified plans meet the funding requirements of federal laws and regulations.

Contributions to foreign plans meet the requirements of local laws and tax regulations.

The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S.

Contributions to foreign plans are based on local laws and tax regulations.

The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S.

The health care benefits are contributory;

the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2024 and 2023.

Three Months Ended September 30,

Pension Benefits Other Postretirement Benefits

(Thousands of dollars) 2024 2023 2024 2023

Service cost $ 1,706 $ 1,650 $ 135 $ 132

Interest cost 8,398 8,534 782 874

Expected return on plan assets ( 8,366 ) ( 8,223 ) – –

Estimated defined contribution provision 54 53 – –

Amortization of prior service cost (credit) 579 155 ( 133 ) ( 133 )

Recognized actuarial loss (gain) 2,363 2,407 ( 812 ) ( 767 )

Total net periodic benefit expense $ 4,734 $ 4,576 $ ( 28 ) $ 106

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, 2025 and 2024.

Three Months Ended March 31,

Pension Benefits Other Postretirement Benefits

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Total net periodic benefit expense $ 3,652 $ 4,734 $ ( 397 ) $ ( 28 )

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

During the nine-month period ended September 30, 2024, the Company made contributions of $ 31.3 million to its defined benefit pension and postretirement benefit plans.

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

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

Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 23.6 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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

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

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

The 2020 Long-Term Plan expires in 2030.

A total of five million shares are issuable during the term of the 2020 Long-Term Plan.

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

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

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

During the nine months ended September 30, 2024, the Committee granted the following awards from the 2020 Long-Term Plan:

Type of Award Number of Awards Granted Grant Date Grant Date

Fair Value Valuation Methodology

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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

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

Performance-based RSUs (TSR) 1

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

Performance-based RSUs (TSR) 1

5,830 April 1, 2024 $ 50.81 Monte Carlo

Performance-based RSUs (ROACE) 1

1,450 April 1, 2024 $ 45.98 Average Stock Price

Time-based RSUs (Stock-Settled) 2

4,840 April 1, 2024 $ 45.98 Average Stock Price

Time-based RSUs (Cash-Settled) 2

460 April 1, 2024 $ 45.98 Average Stock Price

Time-based RSUs (Stock-Settled) 2

22,990 August 19, 2024 $ 37.78 Average Stock Price

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

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

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

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

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

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

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

During the nine months ended September 30, 2024, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:

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

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

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

Time-Based RSUs 2

1,364 June 28, 2024 $ 41.24 Closing Stock Price

Time-Based RSUs 2

1,668 September 30, 2024 $ 33.74 Closing Stock Price

1 Non-employee directors time-based RSUs are scheduled to vest on the first anniversary of the date of grant.

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

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

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

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

2 Effective January 1, 2024, non-employee directors can elect to receive their annual cash retainers in the form of deferred RSUs.

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

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

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)

In 2017, the Company ceased granting stock options and SARs as a part of the Company’s long-term incentive compensation program.

As of September 30, 2024 there were no outstanding stock options or SARs remaining.

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) 2025 2024

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

Note J – Earnings Per Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month and nine-month periods ended September 30, 2024 and 2023.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note J – Net Income (Loss) Per Common Share

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

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

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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, 2024 and 2023, the Company’s effective income tax rates were as follows:

Three months ended September 30, 1.4 % 21.9 %

Nine months ended September 30, 13.3 % 22.2 %

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, 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 pre-tax income of the noncontrolling interest in MP GOM.

The effective tax rates for the three-month period and nine-month period ended September 30, 2023 were above the U.S.

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

Three months ended March 31, 26.7 % 20.6 %

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

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

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state tax expense;

stock-based compensation;

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 pre-tax 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.

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

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

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

Federal rate;

state tax expense;

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

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

These audits often take years to complete and settle.

Although the Company believes that recorded liabilities for unsettled issues

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.

Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.

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, 2024, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:

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

Canada – 2016;

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

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

For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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

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, 2024 and 2023.

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

Commodity Price Risks

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

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

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

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.

During the third quarter of 2023, the Company did no t have any crude oil or natural gas derivative contracts.

At September 30, 2024, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

NYMEX HENRY HUB swap contracts:

Volumes (MMCF/d):

Price per MCF:

At September 30, 2024 and December 31, 2023, the fair value of derivative instruments not designated as hedging instruments are presented in the following table:

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

NYMEX Henry Hub

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

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

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

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

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

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

Type of Derivative Contract Balance Sheet Location September 30, 2024 December 31, 2023

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

Commodity swaps Accounts payable $ ( 8,916 ) $ ( 1,707 )

For the three-month and nine-month periods ended September 30, 2024 and 2023, 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:

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Gain (Loss) Gain (Loss)

(Thousands of dollars) Three Months Ended September 30, Nine Months Ended September 30,

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

(Thousands of dollars) Three Months Ended March 31,

Type of Derivative Contract Statement of Operations Location 2025 2024

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

The fair value measurements for these assets and liabilities at September 30, 2024 and December 31, 2023, are shown in the following table:

September 30, 2024 December 31, 2023

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

March 31, 2025 December 31, 2024

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

2 unchanged sentences

$ 18,479 $ 8,916 $ — $ 27,394 $ 19,469 $ 1,707 $ — $ 21,176

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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

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

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

As of December 31, 2023, there were no outstanding commodity WTI crude oil or HH natural gas swaps and collars contracts subject to fair value measurement, no r were there any commodity swaps and collars liabilities.

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

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

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

and LLOG Bluewater Holdings, L.L.C.

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

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

The revenue threshold was not exceeded for 2019 or 2020;

however, the threshold was met in 2021 and 2022.

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

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

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

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

Malo field if certain enhanced oil recovery projects were undertaken.

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

however, the thresholds were met in 2021 and 2022.

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

As of the end of the second quarter of 2023, the Company had no remaining liabilities relating to prior acquisitions from PAI and LLOG.

During the nine months ended September 30, 2023, the Company paid a total of $ 199.8 million in contingent consideration payments.

In the Consolidated Statements of Cash Flows, $ 139.6 million is shown in “Operating Activities” and $ 60.2 million is shown in “Financing Activities”.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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, 2024 and December 31, 2023.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2024 and December 31, 2023.

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

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

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

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

September 30, December 31,

March 31, December 31,

(Thousands of dollars) Carrying

3 unchanged sentences

$ 1,475,720 $ 1,379,962 $ 1,275,374 $ 1,185,961

Fair Values – Nonrecurring

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

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

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

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

Three Months Ended March 31, 2024

Impairment Total

( Thousands of dollars )

Level 1 Level 2 Level 3

Impaired proved properties

United States - Offshore

$ — $ — $ 437 $ 34,965 $ 34,528

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2023 and September 30, 2024 and the changes during the nine-month period ended September 30, 2024 are presented net of taxes in the following table.

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

(Thousands of dollars) Foreign

Gains (Losses) Retirement

Gains (Losses) Retirement and

Postretirement

Adjustments Total

Balance at December 31, 2024 $ ( 516,324 ) $ ( 111,748 ) $ ( 628,072 )

3 unchanged sentences

Net other comprehensive income (loss) ( 1,667 ) 864 ( 803 )

Balance at September 30, 2024 $ ( 416,220 ) $ ( 136,487 ) $ ( 552,707 )

1 Reclassifications before taxes of $ 4.0 million are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2024.

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

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

See Note H for additional information.

Related income taxes of $ 1.0 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2024.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

Note N – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the U.S.

and throughout the world.

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.

Examples of such governmental action include, but are by no means limited to:

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

trade policies, tariffs and other trade restrictions;

royalty and revenue sharing increases;

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expropriation of property;

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

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

restrictions on drilling and/or production;

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

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

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

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

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

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

wildlife, habitat and water protection;

water access, use and disposal;

the placement, operation and decommissioning of production equipment;

and the health and safety of our employees, contractors and communities where our operations are located.

the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities;

and the causes and impacts of climate change.

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

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

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

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

For example, federal methane regulations currently pending or enacted that would, among other things, require increased leak detection monitoring and repairs, stringent restrictions on venting and flaring, a new third-party monitoring program, and new fees on methane emissions from petroleum and natural gas facilities.

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

economy by 2050.

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

Pursuant to SEC amendments to this

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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

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).

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.

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 was disapproved by a joint Congressional resolution in March 2025.

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

The Paris Agreement entered into force in November 2016.

Although the U.S.

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

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

on February 19, 2021.

rejoined the Paris Agreement in 2021.

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

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

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

1 unchanged sentence

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.

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

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

6 unchanged sentences

The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.

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

2 unchanged sentences

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note O – Common Stock Issued and Outstanding

Activity in the number of shares of common stock issued and outstanding for the nine-month periods ended September 30, 2024 and 2023 is shown below.

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

( Number of shares outstanding )

September 30, 2024 September 30, 2023

March 31, 2025 March 31, 2024

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

Stock options exercised 1

Restricted stock awards 1

3 unchanged sentences

End of period 142,716,062 152,576,156

1 Shares issued upon exercise of stock options and award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.

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

1 Shares issued upon award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $ 1,100.0 million of its common stock.

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

During the nine months ended September 30, 2024, the Company repurchased 8.0 million shares of its common stock under the share repurchase program for $ 300.0 million ($ 302.7 million including excise taxes and fees).

As of September 30, 2024, the Company had $ 650.1 million of its common stock remaining available to repurchase under the program.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

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

Note P – Business Segments

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

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

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

2 unchanged sentences

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

Total Assets at September 30, 2024 Three Months Ended September 30, 2024 Three Months Ended September 30, 2023

(Millions of dollars) External

Revenues Income

(Loss) External

Revenues Income

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

Hambly, acts as the Chief Operating Decision Maker (CODM).

“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

United States 2

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations

Three Months Ended March 31, 2025

Revenue from production

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

Canada 2,043.0 157.9 24.2 129.3 10.5

Other 266.6 ( 0.8 ) 22.4 3.4 ( 12.5 )

Total exploration and production 9,397.9 754.1 185.4 956.4 308.3

Corporate 317.6 4.2 ( 33.7 ) 3.2 ( 30.1 )

Continuing operations 9,715.5 758.3 151.7 959.6 278.2

Discontinued operations, net of tax 0.9 – ( 0.6 ) – ( 0.4 )

Total $ 9,716.4 $ 758.3 $ 151.1 $ 959.6 $ 277.8

Nine Months Ended September 30, 2024 Nine Months Ended September 30, 2023

(Millions of dollars) External

Revenues Income

(Loss) External

Revenues Income

Exploration and production ¹

United States 2

Sales of purchased natural gas

Gain on sales of assets and other operating income

2.1 0.4 — 2.5 ( 9.5 ) ( 7.0 )

Canada 413.8 52.5 403.3 34.9

Other 3.4 1.5 7.1 ( 50.0 )

Total exploration and production 2,353.3 513.0 2,612.6 690.1

Corporate 4.2 ( 88.9 ) 3.3 ( 105.4 )

Continuing operations 2,357.5 424.1 2,615.9 584.7

Discontinued operations, net of tax – ( 2.1 ) – ( 0.7 )

Total $ 2,357.5 $ 422.0 $ 2,615.9 $ 584.0

1 Additional detail about the results of oil and natural gas operations is presented in the Exploration and Production Continuing Operations table on page 26 .

2 Includes revenue and income attributable to noncontrolling interest in MP GOM.

Revenues from external customers 509.5 165.7 — 675.2 ( 9.5 ) 665.7

Lease operating expenses

Lease operating expenses and taxes other than income

100.3 45.2 0.4 145.9 — 145.9

Repair and maintenance

10.2 1.6 — 11.8 — 11.8

Workovers 47.1 0.3 — 47.4 — 47.4

Total lease operating expenses

157.6 47.1 0.4 205.1 — 205.1

Severance and ad valorem taxes 8.4 0.3 — 8.7 — 8.7

Transportation, gathering and processing 28.7 20.2 — 48.9 — 48.9

Costs of purchased natural gas

Selling and general expenses 2.0 6.0 1.9 9.9 21.0 30.9

Exploration Expenses

Geological and geophysical 3.2 — 0.3 3.5 — 3.5

Dry holes and previously suspended exploration costs

0.2 — — 0.2 — 0.2

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

2.7 0.1 8.0 10.8 — 10.8

Total exploration expenses 6.1 0.1 8.3 14.5 — 14.5

Depreciation, depletion and amortization 159.4 32.4 0.1 191.9 2.3 194.2

Accretion of asset retirement obligations 11.3 2.5 0.2 14.0 — 14.0

Other operating expenses

2.6 0.9 0.1 3.6 2.0 5.6

Interest Income ( 0.4 ) — — ( 0.4 ) ( 3.3 ) ( 3.7 )

Interest (expense), net of capitalization — — — — 23.5 23.5

Income tax expense

Current income tax expense

0.5 13.7 — 14.2 2.1 16.3

Deferred income tax expense (benefit)

24.5 0.6 — 25.1 ( 8.7 ) 16.4

Total income tax expense

25.0 14.3 — 39.3 ( 6.6 ) 32.7

Other segment costs (income)

0.9 0.4 0.2 1.5 0.4 1.9

Segment income (loss) - including NCI 1

$ 107.9 $ 41.5 $ ( 11.2 ) $ 138.2 $ ( 48.8 ) $ 89.4

Additions to property, plant, equipment $ 317.1 $ 55.4 $ 35.3 $ 407.8 $ 4.2 $ 412.0

Total assets at quarter-end

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 gas field equipment.

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

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

Purchase options also exist for certain leases.

During the second quarter of 2024, 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 $ 254.1 million (discounted) to our right-of-use assets and operating lease liabilities at June 30, 2024.

Maturity of Lease Liabilities

(Thousands of dollars) Operating Leases Finance Leases Total

Note P – Business Segments (Continued)

Exploration and Production

( Millions of dollars )

Canada Other Total

E&P Corporate,

Other, and Discontinued Operations Consolidated

Three Months Ended March 31, 2024

Revenue from production

$ 658.4 $ 136.3 $ ( 0.1 ) $ 794.6 $ — $ 794.6

Sales of purchased natural gas

— 0.2 — 0.2 — 0.2

Gain on sales of assets and other operating income

1.2 0.4 — 1.6 — 1.6

Revenues from external customers 659.6 136.9 ( 0.1 ) 796.4 — 796.4

Lease operating expenses

Lease operating expenses and taxes other than income

120.2 46.7 0.2 167.1 — 167.1

Repair and maintenance

11.0 0.6 — 11.6 — 11.6

Remaining 490,391 267 490,658

Total future minimum lease payments 1,109,331 4,808 1,114,139

Less imputed interest ( 235,937 ) ( 1,277 ) ( 237,214 )

Present value of lease liabilities 1

Workovers 55.4 0.2 — 55.6 — 55.6

Total lease operating expenses

186.6 47.5 0.2 234.3 — 234.3

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

Lease Term and Discount Rate

September 30, 2024 December 31, 2023

Weighted average remaining lease term:

Operating leases 8 years 10 years

Finance leases 5 years 5 years

Weighted average discount rate:

Operating leases 5.7 % 5.9 %

Finance leases 4.7 % 4.7 %

Severance and ad valorem taxes 9.8 0.3 — 10.1 — 10.1

Transportation, gathering and processing 36.6 19.9 — 56.5 0.1 56.6

Costs of purchased natural gas

— 0.2 — 0.2 — 0.2

Selling and general expenses ( 0.2 ) 5.1 1.2 6.1 25.0 31.1

Exploration Expenses

Geological and geophysical 0.6 — 0.8 1.4 — 1.4

Dry holes and previously suspended exploration costs

31.2 — 1.2 32.4 — 32.4

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

3.4 0.1 7.1 10.6 — 10.6

Total exploration expenses 35.2 0.1 9.1 44.4 — 44.4

Depreciation, depletion and amortization 174.0 34.3 — 208.3 2.8 211.1

Impairment of assets 34.5 — — 34.5 — 34.5

Accretion of asset retirement obligations 10.4 2.1 0.3 12.8 — 12.8

Other operating expenses

6.3 0.9 0.1 7.3 — 7.3

Interest Income ( 0.7 ) — — ( 0.7 ) ( 2.9 ) ( 3.6 )

Interest expense, net of capitalization

— 0.1 — 0.1 19.9 20.0

Income tax expense

Current income tax expense

1.0 5.8 — 6.8 3.9 10.7

Deferred income tax expense (benefit)

29.8 1.1 ( 0.3 ) 30.6 ( 11.2 ) 19.4

Total income tax expense (benefit)

30.8 6.9 ( 0.3 ) 37.4 ( 7.3 ) 30.1

Other segment costs (income)

1.8 0.1 0.1 2.0 ( 9.2 ) ( 7.2 )

Segment income (loss) - including NCI 1

$ 134.5 $ 19.4 $ ( 10.8 ) $ 143.1 $ ( 28.4 ) $ 114.7

Additions to property, plant, equipment $ 155.3 $ 67.2 $ 2.9 $ 225.4 $ 4.2 $ 229.6

Total assets at quarter-end

7,030.7 2,059.1 210.2 9,300.0 368.7 9,668.7

1 Includes results attributable to a 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, 2024 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, 2023.

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

This MD&A includes forward-looking statements that involve certain risks and uncertainties.

See “ Forward-Looking Statements ” at the end of this section.

Murphy Oil Corporation is a global oil and gas exploration and production company, with both onshore and offshore operations and properties.

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

and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide.

Our production in the U.S.

is primarily from offshore fields in the Gulf of Mexico and onshore in the Eagle Ford Shale area of South Texas.

In Canada, we produce from the onshore fields Tupper Montney and Kaybob Duvernay, in British Columbia and Alberta, and we produce from the Hibernia and Terra Nova fields, located offshore Newfoundland in the Jeanne d’Arc Basin.

Significant Company financial and operational highlights during the third quarter of 2024 were as follows:

• Produced 191,273 barrels of oil equivalent per day (including NCI)

• Maintained quarterly dividend of $0.30 per share or $1.20 per share annualized

• Repurchased $194.1 million ($196.2 million including excise taxes and fees) of common stock, or 5,374,191 shares, at an average price of $36.12 per share

Subsequent to the third quarter of 2024:

• Issued $600.0 million of 6.000% senior notes due 2032, and used proceeds to tender an aggregate $521.1 million of senior notes due 2027, 2028 and 2029

• Entered into new five-year, $1.2 billion senior unsecured credit facility, representing a 50 percent increase from previous facility size

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended September 30, 2024, was $151.7 million, a decrease of $126.5 million compared to the same period in 2023.

Lower net income from continuing operations was driven primarily by lower revenues from production ($192.7 million), higher lease operating expenses ($29.5 million), and lower other income ($12.7 million), and was partially offset by lower income tax expense ($76.0 million), lower transportation, gathering and processing expenses ($14.1 million), and lower depreciation, depreciation, depletion and amortization expenses ($13.9 million).

Lower revenues were primarily driven by lower oil production in the U.S., combined with lower oil prices.

Higher lease operating expenses relate primarily to workover projects in the Gulf of Mexico.

Lower other income represents unrealized foreign exchange losses.

Lower income tax expense in the current period is driven primarily by lower operating income, in addition to an income tax deduction for prior years’ Australia exploration spend.

Lower transportation, gathering and processing expenses and lower depreciation, depletion and amortization expenses were both driven by lower production in the U.S.

For the three months ended September 30, 2024 total hydrocarbon production was 191,273 barrels of oil equivalent per day, a decrease of 8% compared to the third quarter of 2023.

The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico, due to workover activities and downtime, and in the Eagle Ford Shale, due primarily to the timing of new wells.

Decreases in the U.S.

were offset by increases in Canada at both Terra Nova, which restarted production in late 2023.

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

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

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

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 first quarter of 2025 were as follows:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Overview (Continued)

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2024 was $424.1 million, a decrease of $160.6 million compared to the same period of 2023.

Lower net income from continuing operations was largely driven by lower revenues from production ($196.7 million), higher lease operating expenses ($129.2 million), and higher impairment of assets ($34.5 million).

These were partially offset by lower income tax expense ($102.0 million), lower exploration expenses ($34.1 million), higher other income ($32.8 million), lower interest expense on long-term debt ($26.4 million), and lower transportation, gathering and processing expenses ($17.8 million).

Lower revenues from production were primarily driven by downtime in the Gulf of Mexico and Eagle Ford Shale and lower natural gas prices, partially offset by higher year-to-date oil prices, higher production in Canada due to the restart of production at Terra Nova in late 2023, and well performance, combined with lower royalty rates at Tupper Montney.

Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico and higher production activity in Canada at Terra Nova, partially offset by lower production handling (PHA) fees in the Gulf of Mexico.

Impairment charges related to the Calliope field were recorded in the first quarter of 2024.

The decrease in income tax expense primarily relates to lower income tax expenses driven by lower overall income, in addition to an income tax deduction for prior years’ Australia exploration spend.

Exploration expense in the current period was primarily due to dry hole expense recorded for multiple wells in the Gulf of Mexico, including Sebastian #1 (Mississippi Canyon 387) and Orange #1 (Mississippi Canyon 216), additional costs related to the Oso #1 (Atwater Valley 138) well, and for previously suspended exploration costs related to an expired lease at Hoffe Park #1 (Mississippi Canyon 166).

Higher other income related to unrealized foreign exchange gains and interest income on several outstanding joint interest receivables.

Lower interest expense was due to lower debt levels and lower transportation, gathering and processing expenses related to lower production in the U.S.

For the nine months ended September 30, 2024 total hydrocarbon production was 185,286 barrels of oil equivalent per day, a decrease of 4% compared to the same period in 2023.

The decrease was principally due to lower production in the U.S., primarily in the Gulf of Mexico due to downtime for workovers, and in the Eagle Ford Shale, due to timing of new wells.

Decreases in the U.S.

were partially offset by increases in Canada at both Tupper Montney, due to new wells online, and Terra Nova, which restarted production in late 2023.

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

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.

Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company.

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

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

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

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

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

Reductions in commodity prices will reduce 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) 2025 2024

4 unchanged sentences

Total exploration and production

185.4 308.3 513.0 690.1

Corporate (33.7) (30.1) (88.9) (105.4)

Corporate and other (48.2) (27.5)

Income from continuing operations 90.0 115.6

Discontinued operations ¹ (0.6) (0.4) (2.1) (0.7)

Loss from discontinued operations ¹ (0.6) (0.9)

Net income including noncontrolling interest 89.4 114.7

Net income attributable to noncontrolling interest

12.0 22.5 65.2 38.7

Net income attributable to Murphy $ 73.0 $ 90.0

5 unchanged sentences

The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted.

The following are summarized income statements for E&P continuing operations:

The following is a summarized statement of operations for E&P continuing operations:

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

3 unchanged sentences

Sales of purchased natural gas

– 7.9 3.7 64.6

0.9 2.6 4.3 6.0

Total revenues and other income

754.1 956.4 2,353.3 2,612.6

Cost and Expenses

6 unchanged sentences

Accretion of asset retirement obligations 14.0 12.7

Total exploration expenses 31.2 26.4 118.4 152.5

Total exploration expenses, including undeveloped lease amortization

Selling and general expenses 9.9 6.1

2 unchanged sentences

Income tax provisions

9.6 85.5 87.4 196.1

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, 2024 and 2023.

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Weighted average sales prices) 2025 2024

3 unchanged sentences

United States - Offshore 1

75.65 82.94 78.42 76.73

Canada - Onshore 2

66.18 76.33 68.62 73.01

Canada - Offshore 2

80.06 94.85 82.83 84.13

– 77.19 78.20 82.87

Natural gas liquids – dollars per barrel

1 unchanged sentence

United States - Offshore 1

22.50 20.16 23.20 22.01

Canada - Onshore 2

34.00 37.72 34.64 39.08

Natural gas – dollars per thousand cubic feet

1 unchanged sentence

United States - Offshore 1

2.28 2.84 2.30 2.82

Canada - Onshore 2

1.34 1.93 1.56 2.07

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, 2024 and 2023.

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Average price for the period) 2025 2024

2 unchanged sentences

AECO (C$/MCF)

0.69 2.60 1.45 2.75

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

1 unchanged sentence

Production Volumes

The following table contains hydrocarbons produced during the three-month and nine-month periods ended September 30, 2024 and 2023.

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

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

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) 2025 2024

5 unchanged sentences

Canada - Onshore

3,425 2,935 2,888 3,104

Canada - Offshore

7,880 2,956 7,219 2,778

Other 255 245

3 unchanged sentences

United States - Onshore

United States - Offshore 1

Canada - Onshore

Total net natural gas liquids

Net natural gas – thousands of cubic feet per day

United States - Onshore

26,190 24,231

3 unchanged sentences

346,892 355,455

Total net natural gas liquids

Total net natural gas

424,232 432,847

Total net hydrocarbons - including NCI 2,3

163,374 176,671

Noncontrolling interest

Net crude oil and condensate – barrels per day (5,779) (6,499)

Net natural gas liquids – barrels per day (170) (211)

Net natural gas – thousands of cubic feet per day (1,234) (2,074)

Total noncontrolling interest 2,3

(6,154) (7,056)

Total net hydrocarbons - excluding NCI 2,3

157,220 169,615

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

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

Results of Operations (Continued)

Sales Volumes

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

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

Three Months Ended

(Barrels per day unless otherwise noted) 2025 2024

Net crude oil and condensate

United States - Onshore

3 unchanged sentences

Canada - Onshore

Canada - Offshore

Total net crude oil and condensate

84,819 97,704

Net natural gas liquids

United States - Onshore

United States - Offshore 1

Canada - Onshore

Total net natural gas liquids

Net natural gas – thousands of cubic feet per day

United States - Onshore

26,190 24,231

United States - Offshore 1

51,150 53,161

Canada - Onshore

346,892 355,455

Total net natural gas

19 unchanged sentences

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

3 unchanged sentences

United States - Natural gas liquids

17.9 20.9 52.8 61.8

United States - Natural gas

16.6 24.4 47.6 70.9

101.1 42.9 232.6 125.1

Canada - Natural gas liquids

2.4 2.5 5.4 7.5

Canada - Natural gas

54.1 75.7 170.9 205.0

(0.8) 3.4 3.4 7.1

Total revenue from production

$ 672.7 $ 794.6

Revenues from production for the three months ended September 30, 2024 decreased $192.7 million compared to the same period in 2023.

Revenue was lower in the Gulf of Mexico, mostly driven by downtime at the Samurai field, as well as hurricane related downtime.

Additionally, Eagle Ford Shale revenues decreased due to the natural decline of wells and fewer wells brought online.

These decreases were partially offset by new production at Terra Nova in Canada, which restarted production in late 2023.

Lower pricing across all products also contributed to the decrease during the period.

Revenues from production for the nine months ended September 30, 2024 decreased $196.7 million compared to the same period in 2023.

Lower revenue was driven primarily by workover activities, downtime and timing of new wells in the Gulf of Mexico, fewer new wells brought online in the Eagle Ford Shale, and lower realized natural gas prices in Tupper Montney.

These effects were partially offset by production restarting at Terra Nova in late 2023, and higher oil prices.

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

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

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

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

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

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

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

Sales of purchased natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 26 .

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

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

1 unchanged sentence

Lease Operating and Transportation, Gathering and Processing Expenses

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

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)

(Millions of dollars)

(Dollars per equivalent barrel)

12 unchanged sentences

$ 205.1 $ 234.3 $ 13.90 $ 14.37

Transportation, gathering and processing

United States - Onshore

6 unchanged sentences

1.8 1.9 1.80 3.03

Total TGP expenses

Total transportation, gathering and processing

$ 48.9 $ 56.5 $ 3.31 $ 3.47

For the three months ended September 30, 2024 lease operating expenses increased by $29.5 million and TGP expenses decreased by $14.0 million compared to the same period in 2023.

Higher lease operating expenses were due to workover activity in the Gulf of Mexico and higher production at Terra Nova and were partially offset by lower PHA fees in the Gulf of Mexico.

Lower TGP expenses during the quarter were a result of lower production volumes in the Gulf of Mexico.

For the nine months ended September 30, 2024, lease operating expenses increased by $129.2 million and TGP expenses decreased by $17.8 million compared to the same period in 2023.

Higher lease operating expenses were primarily due to workovers in the Gulf of Mexico, primarily at the Neidermeyer field, and higher production at Terra Nova, and were partially offset by lower PHA fees in the Gulf of Mexico.

Lower TGP expenses resulted primarily from lower production volumes in the Gulf of Mexico.

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

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

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

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

Depreciation, Depletion and Amortization Expense

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

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

(Millions of dollars)

(Dollars per equivalent barrel)

11 unchanged sentences

$ 191.8 $ 208.3 $ 13.00 $ 12.77

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

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

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

Results of Operations (Continued)

DD&A expense for the three months ended September 30, 2024 decreased by $12.6 million compared to the same period in 2023.

The decrease is primarily due to lower volumes in the Gulf of Mexico and at Eagle Ford Shale, partially offset by higher volumes in Canada Offshore and Onshore and higher rates in the U.S.

due to development drilling.

DD&A expense for the nine months ended September 30, 2024 increased by $2.9 million compared to the same period in 2023.

Higher DD&A expense from Canada E&P primarily related to increased volumes at Terra Nova, partially offset by lower volumes in the U.S.

and higher rates in the U.S., primarily due to development drilling at various offshore platforms.

Impairment of Assets

For the three months ended September 30, 2024, there were no impairments.

For the nine months ended September 30, 2024, the Company impaired assets for $34.5 million, related to the Calliope field in the Gulf of Mexico, as a result of operational issues that led to a reserve reduction.

There were no impairments in the three and nine months ended September 30, 2023.

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

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

Exploration Expenses

1 unchanged sentence

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

4 unchanged sentences

Undeveloped lease amortization 1.6 2.8

Total exploration expenses

Total exploration expenses, including undeveloped lease amortization

$ 14.5 $ 44.4

Exploration expenses for the three months ended September 30, 2024 increased by $4.8 million compared to the prior year, primarily as a result of higher geological and geophysical costs in the Gulf of Mexico in the current period.

Dry hole costs in the current period represented costs associated with the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the U.S.

Gulf of Mexico that encountered non-commercial hydrocarbons in the third quarter of 2024.

In the third quarter of 2023, we recorded dry hole costs related to the Chinook #7 (Walker Ridge 425) exploration well in the U.S.

Gulf of Mexico.

Exploration expenses for the nine months ended September 30, 2024 decreased by $34.1 million compared to the same period in 2023.

In the current period, dry hole costs were recorded for the Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and for the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the U.S.

Gulf of Mexico.

In 2023, we recorded previously suspended exploration costs for the Cholula-1EXP well in Mexico and dry hole costs for the Chinook #7 (Walker Ridge 425) exploration well in the U.S.

Gulf of Mexico.

Other expenses for the three and nine months ended September 30, 2024 decreased by $1.1 million and $33.7 million, respectively, compared to the same periods in 2023.

For the three months ended September 30, 2024 the decrease is primarily due to the absence of other operating expenses in Canada related to the Terra Nova life extension project.

For the nine months ended September 30, 2024 the decrease was due to a combination of interest income received and a favorable state tax settlement related to U.S.

Onshore activities.

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

Results of Operations (Continued)

Income taxes for the three and nine months ended September 30, 2024 decreased by $75.9 million and $108.7 million, respectively, compared to the same periods in 2023.

Lower income taxes for each period, respectively, were primarily the result of lower year-to-date pre-tax income, and an income tax deduction for prior years’ Australia exploration spend.

Corporate activities included interest expense and income, foreign exchange effects and corporate overhead not allocated to E&P.

Corporate activities reported a loss of $33.7 million for the three months ended September 30, 2024, an unfavorable variance of $3.6 million compared to the same period of 2023.

The unfavorable variance was primarily due to unrealized foreign exchange losses ($14.0 million), partially offset by decreased interest expense ($8.8 million).

Lower interest expense for the current period was primarily due to lower overall debt levels.

Corporate activities reported a loss of $88.9 million for the nine months ended September 30, 2024, a favorable variance of $16.5 million compared to the same period of 2023.

The favorable variance was primarily due to lower interest expense ($26.6 million) and unrealized foreign exchange gains ($10.1 million) and was partially offset by increased selling and general expense ($15.6 million) and lower income tax benefits ($6.7 million).

Lower interest expense for the current period was primarily due to lower overall debt levels.

Higher selling and general expenses for the nine months ended September 30, 2024 were primarily attributable to timing of corporate donations.

Lower income tax benefit was the result of lower pre-tax losses.

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

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

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

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

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

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

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

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

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 the New RCF.

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

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

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

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

Nine Months Ended

September 30,

(Thousands of dollars) 2024 2023

Net cash provided by (required by):

Three Months Ended

(Millions of dollars)

Net cash provided (required) by:

Net cash provided by continuing operations activities $ 300.7 $ 398.8

1 unchanged sentence

(369.8) (249.1)

Net cash required by financing activities

(608.8) (547.4)

Net cash provided (required) by financing activities

Effect of exchange rate changes on cash and cash equivalents 0.3 0.9

Net decrease in cash and cash equivalents

Net (decrease) increase in cash and cash equivalents

$ (30.7) $ 6.4

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the nine months ended September 30, 2024 was $89.7 million higher compared to the same period in 2023.

The increase in cash flows from operations activities was primarily attributable to a decrease in non-cash working capital in the current period, compared to an increase in the prior period ($174.6 million), no contingent consideration payments related to prior Gulf of

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

Financial Condition (Continued)

Mexico acquisitions in 2024 (2023:

$139.6 million), changes in other operating activities, net ($59.1 million), an increase in other income ($32.8 million), and a decrease in interest expense ($26.4 million).

These were partially offset by lower revenue from production ($196.7 million), and an increase in lease operating expenses ($129.2 million).

The increase due to changes in non-cash working capital is primarily due to lower accounts receivable, partially offset by lower accounts payable.

The decreases in accounts receivable and accounts payable are primarily due to lower overall production volumes and gas prices, other receivable settlements, and exploration activities in the Gulf of Mexico.

The increase due to changes in other operating activities is primarily due to spend on asset retirement obligations in the prior period.

Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements of Cash Flows;

amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition.

Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.

During the nine months ended September 30, 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statements of Cash Flows.

As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.

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

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

Cash Required by Investing Activities

Net cash required by investing activities for the nine months ended September 30, 2024 was $88.9 million lower compared to the same period in 2023.

The decrease was due to lower property additions and dry hole costs ($169.0 million), partially offset by cash inflows from the sale of certain non-core operated Kaybob Duvernay assets and all of our non-operated Placid Montney assets Kaybob properties ($102.9 million) in 2023.

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

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

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) 2025 2024

Property additions and dry hole costs per cash flow statements $ 733.3 $ 902.3

Property additions and dry hole costs per the cash flow statements

$ 368.4 $ 249.1

Acquisition of oil properties per the cash flow statements

3 unchanged sentences

Total accrual basis capital expenditures are shown below.

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2025 2024

3 unchanged sentences

Total capital expenditures $ 424.8 $ 271.3

Lower capital expenditures in the nine months ended September 30, 2024 compared to the same period of 2023 was primarily attributable to lower exploration expenditures in the Gulf of Mexico, lower field development costs due to the Terra Nova asset life extension project ending in 2023, and lower development drilling costs at Eagle Ford Shale and Tupper Montney, partially offset by higher development expenditures at various Gulf of Mexico fields.

Capital expenditures in 2024 primarily relate to development drilling and field development activities at Eagle Ford Shale ($246.8 million), at the Khaleesi, Mormont and Samurai fields, and the non-operated St.

Malo and Lucius fields in the Gulf of Mexico ($235.7 million), and at Tupper Montney ($75.4 million), Kaybob Duvernay

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

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

Financial Condition (Continued)

($26.3 million), and the non-operated Hibernia field ($15.2 million) in Canada.

Other international field development activities were ($30.6 million), and total exploration costs were $123.4 million.

Exploration costs in 2024 were primarily comprised of activities in the Gulf of Mexico related to the Sebastian #1 (Mississippi Canyon 387), Orange #1 (Mississippi Canyon 216), and Oso #1 (Atwater Valley 138) exploration wells.

Sebastian #1 and Orange #1 encountered non-commercial hydrocarbons during 2024.

Oso #1 encountered non-commercial hydrocarbons in 2023, and operations completed in 2024.

Additional exploratory costs relate to the Ocotillo #1 (Mississippi Canyon 40) exploration well.

Cash Required by Financing Activities

Net cash required by financing activities for the nine months ended September 30, 2024 increased by $61.4 million compared to the same period in 2023.

In 2024, the cash used in financing activities was principally for the repurchase of common shares ($300.1 million), cash dividends to shareholders of $0.90 per share ($136.2 million), withholding tax on stock-based incentive awards ($25.3 million), distributions to the noncontrolling interest in the Gulf of Mexico ($96.6 million), and debt repurchases of $50.0 million.

In 2023, there were debt repurchases ($248.7 million), cash dividends to shareholders ($128.7 million), the repurchase of common shares ($75.0 million), withholding tax on stock-based incentive awards ($14.2 million), distributions to the noncontrolling interest in the Gulf of Mexico ($20.1 million), and contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the “Cash Provided by Continuing Operations Activities” section.

At September 30, 2024 the Company had approximately $1.1 billion of liquidity consisting of $271.2 million in cash and cash equivalents and $799.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $800.0 million senior unsecured RCF was set to expire in November 2027 and as of September 30, 2024 the Company had no outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the facility.

At September 30, 2024 the interest rate in effect on borrowings under the facility would have been 7.20%.

At September 30, 2024 the Company was in compliance with all covenants related to the RCF.

Subsequent to quarter end, on October 7, 2024, the Company entered into a New RCF, a credit agreement governing a $1,200.0 million senior unsecured revolving credit facility with a maturity date in October 2029, which replaced the prior RCF.

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

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

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

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

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

Cash Provided by Financing Activities

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

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

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

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

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

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

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

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

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

As of September 30, 2024 cash and cash equivalents held outside the U.S.

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

included U.S.

dollar equivalents of approximately $101.6 million, the majority of which was held in Canada ($72.3 million).

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

($7.8 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, 2024 December 31, 2023

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

Working capital

3 unchanged sentences

$ (237.1) $ (157.5)

As of September 30, 2024 net working capital decreased by $160.9 million compared to December 31, 2023.

The decrease was primarily attributable to lower accounts receivable ($80.9 million), lower cash balance ($45.9 million), and higher operating lease liabilities ($45.5 million), and was partially offset by lower accounts payable ($17.1 million).

Lower accounts receivable was primarily due to lower revenues.

Higher operating lease liabilities were primarily attributable to the current portion of lease extensions recorded during the period related to a drill ship in the

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

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

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

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

Offshore in the next 12 months.

Lower other accrued liabilities were due to incentive payments

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

Financial Condition (Continued)

Gulf of Mexico (See Note Q for additional detail).

Lower accounts payable were primarily due to lower revenue related payables and other timing of cash payments.

and operating lease payments made in 2025.

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

Capital Employed

A summary of capital employed at September 30, 2024 and December 31, 2023 follows.

September 30, 2024 December 31, 2023

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

March 31, 2025 December 31, 2024

(Millions of dollars) Amount % Amount %

3 unchanged sentences

Total capital employed $ 6,595.1 100.0 % $ 6,468.8 100.0 %

At September 30, 2024 long-term debt of $1,279.3 million decreased by $49.1 million compared to December 31, 2023, primarily as a result of the open market repurchase of $50.0 million.

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

The total of the fixed-rate notes had a weighted average maturity of 9.1 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $113.1 million in 2024, primarily due to shares repurchased ($302.7 million, including excise tax), cash dividends paid ($136.2 million) and unrealized foreign currency translation losses ($34.6 million), partially offset by net income earned ($356.8 million).

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

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

Critical Accounting Estimates

As of September 30, 2024 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, 2023.

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

Accounting Changes and Recent Accounting Pronouncements

3 unchanged sentences

The Company uses other operational performance and income metrics to review operational performance.

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

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

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

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

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

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

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

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

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars, except per share amounts)

2024 2023 2024 2023

Net income attributable to Murphy (GAAP) 1

2 unchanged sentences

Net income from continuing operations attributable to Murphy 73.6 90.9

139.7 255.7 358.9 546.0

Mark-to-market loss on derivative instruments 8.9 —

Impairment of assets — 34.5

Write-off of previously suspended exploration well — 26.1

Foreign exchange loss (gain) 5.4 (8.6) (10.6) (0.3)

Mark-to-market loss on derivative instruments 1.3 – 1.3 –

Mark-to-market loss on contingent consideration – – – 7.1

Foreign exchange (gain) — (10.5)

Total adjustments, before taxes 8.9 50.1

Income tax (benefit) expense related to adjustments

(1.7) 2.2 (10.5) (1.4)

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

Income tax (benefit) related to adjustments

Total adjustments after taxes 7.1 39.9

Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) $ 80.7 $ 130.8

$ 110.7 $ 249.3 $ 365.7 $ 568.5

Net income from continuing operations per average diluted share (GAAP) $ 0.50 $ 0.60

$ 0.93 $ 1.63 $ 2.35 $ 3.47

Adjusted net income from continuing operations per average diluted share (Non-GAAP) $ 0.56 $ 0.85

$ 0.74 $ 1.59 $ 2.40 $ 3.62

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

1 unchanged sentence

Other Key Performance Metrics (Continued)

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

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

Three Months Ended

September 30, Nine Months Ended

September 30,

(Millions of dollars) 2025 2024

4 unchanged sentences

Depreciation, depletion and amortization expense 1

215.7 231.5 625.8 630.8

EBITDA attributable to Murphy (Non-GAAP) 316.6 342.8

Impairment of asset – – 34.5 –

Write-off of previously suspended exploration well – – 26.1 17.1

Exploration expenses

EBITDAX attributable to Murphy (Non-GAAP) $ 331.1 $ 387.2

EBITDA attributable to Murphy (Non-GAAP) $ 316.6 $ 342.8

Accretion of asset retirement obligations 1

11.7 10.4 34.9 30.4

Foreign exchange loss (gain) 5.4 (8.6) (10.6) (0.3)

Mark-to-market loss on derivative instruments

Mark-to-market loss on contingent consideration – – – 7.1

Impairment of assets

Write-off of previously suspended exploration well — 26.1

Foreign exchange (gain)

Discontinued operations loss 0.6 0.9

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 338.6 $ 405.2

Other exploration expenses 2

Adjusted EBITDAX attributable to Murphy (Non-GAAP) $ 353.1 $ 423.5

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)

The oil and 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 natural gas pricing during the third quarter of 2024 compared to same period in 2023 directly impacted the Company’s product sales revenue.

As of close on November 5, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:

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

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

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

WTI ($/BBL) 56.46 57.23

1 unchanged sentence

AECO (US$ Equivalent/MCF) 1.94 2.44

Similar to the overall inflation in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations.

Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing.

Lower prices, should they occur, will result in lower profits and operating cash flows.

For the fourth quarter of 2024, production is expected to average between 181.5 and 189.5 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

In April 2025, the U.S.

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

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

Additionally, the U.S.

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

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

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

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

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

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

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

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

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

1 unchanged sentence

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

If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or 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 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 framework designed to allow for additional shareholder returns and debt reduction.

Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022 and August 8, 2024.

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

Subsequent to quarter end, on October 3, 2024, the Company closed the Offering of $600.0 million aggregate principal amount of new senior notes that bear interest at a rate of 6.000% per annum and mature on October 1, 2032, the proceeds of which will be used for the repayment of debt.

To date, the Company has repurchased and canceled $258.8 million of the 2027 Notes, $200.2 million of the 2028 Notes and $62.1 million of the 2029 Notes.

In addition, on October 7, 2024, the Company entered into a credit agreement governing a $1,200.0 million New RCF with a maturity date on October 7, 2029.

Further details of these transactions can be found in the Company’s Form 8-K filed on October 3, 2024 and October 7, 2024, respectively.

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

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

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

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

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

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

Outlook (Continued)

As of November 5, 2024, 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:

Price/MCF Remaining Period

Area Commodity Type Start Date End Date

Canada Natural Gas Fixed price forward sales 162 C$2.39 10/1/2024 12/31/2024

Canada Natural Gas Fixed price forward sales 40 C$2.75 1/1/2025 12/31/2025

Canada Natural Gas Fixed price forward sales 50 C$3.03 1/1/2026 12/31/2026

Canada Natural Gas Fixed price forward sales 25 US$1.98 10/1/2024 10/31/2024

Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024

Price/MCF Remaining Period

Area Commodity Type Start Date End Date

United States Natural Gas Fixed price derivative swap 20 US$3.20 1/1/2025 12/31/2025

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