UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)
☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-200		77024
Houston,	Texas	(Zip Code)
(Address of principal executive offices)
(281)		675-9000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $1.00 Par Value	MUR	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

Number of shares of Common Stock, $1.00 par value, outstanding at October 31, 2025 was 142,738,809.

MURPHY OIL CORPORATION

TABLE OF CONTENTS

			Page
Part I – Financial Information			2
Item 1. Financial Statements			2
Consolidated Balance Sheets			2
Consolidated Statements of Operations			3
Consolidated Statements of Comprehensive Income			4
Consolidated Statements of Cash Flows			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Note A – Basis of Presentation			7
Note B – New Accounting Principles and Recent Accounting Pronouncements			7
Note C – Revenue from Contracts with Customers			8
Note D – Property, Plant and Equipment			10
Note E – Financing Arrangements and Debt			1112
Note F – Other Financial Information			12
Note G – Asset Retirement Obligations			1213
Note H – Employee and Retiree Benefit Plans			13
Note I – Incentive Plans			1314
Note J – Net Income (Loss) Per Common Share			1516
Note K – Income Taxes			1516
Note L – Financial Instruments and Risk Management			1617
Note M – Accumulated Other Comprehensive Loss			1920
Note N – Environmental and Other Contingencies			1921
Note O – Common Stock Issued and Outstanding			2122
Note P – Business Segments			2123
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Note Q – Leases			28
Item 3. Quantitative and Qualitative Disclosures About Market Risk			46
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 4. Controls and Procedures			46
Item 3. Quantitative and Qualitative Disclosures About Market Risk			49
Part II – Other Information			47
Item 4. Controls and Procedures			49
Item 1. Legal Proceedings			47
Part II – Other Information			50
Item 1A. Risk Factors			47
Item 1. Legal Proceedings			50
Item 5. Other Information			48
Item 1A. Risk Factors			50
Item 6. Exhibits			48
Item 5. Other Information			51
Signature			49
Item 6. Exhibits			51
Signature			52

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(Thousands of dollars, except share amounts)	~~June~~September 30,2025		December 31,2024
ASSETS
Current assets
Cash and cash equivalents	$	~~379~~425,~~631~~960	$	423,569
Accounts receivable, net	~~274~~283,~~033~~744		272,530
Inventories	62,~~515~~147		54,858
Prepaid expenses	4535,~~946~~629		34,322
Total current assets	~~762~~807,~~125~~480		785,279
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $14,436,980 in 2025 and $13,811,539 in 2024	8,347,423		8,054,653
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $14,762,292 in 2025 and $13,811,539 in 2024	8,085,731		8,054,653
Operating lease assets	~~673~~781,~~223~~291		777,536
Deferred charges and other assets	5658,~~744~~260		50,011
Total assets	$	9,~~839~~732,~~515~~762	$	9,667,479
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	~~910~~918	$	871
Accounts payable	~~509~~429,~~225~~658		472,165
Income taxes payable	2320,~~792~~987		19,003
Other taxes payable	3031,~~304~~573		31,685
Operating lease liabilities	~~190~~210,~~659~~769		253,208
Other accrued liabilities	84117,~~303~~965		117,802
Current asset retirement obligations	7045,~~104~~876		48,080
Total current liabilities	~~909~~857,~~297~~746		942,814
Long-term debt, including finance lease obligation	1,~~474~~425,~~959~~235		1,274,502
Asset retirement obligations	~~980~~1,~~109~~001,919		960,804
Deferred credits and other liabilities	~~254~~249,~~400~~521		274,345
Non-current operating lease liabilities	~~494~~582,~~561~~082		537,381
Deferred income taxes	~~369~~366,~~009~~607		335,790
Total liabilities	$	4,~~482~~483,~~335~~110	$	4,325,636
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	$	—	$	—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2025 and 195,100,628 shares in 2024	195,101		195,101
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at September 30, 2025 and 195,100,628 shares at December 31, 2024	195,101		195,101
Capital in excess of par value	~~841~~850,~~833~~964		848,950
Retained earnings	6,~~775~~725,~~193~~833		6,773,289
Accumulated other comprehensive loss	(~~537~~574,~~778~~931)		(628,072)
Treasury stock	(2,075,~~823~~580)		(1,995,018)
Murphy Shareholders' Equity	5,~~198~~121,~~526~~387		5,194,250
Noncontrolling interest	~~158~~128,~~654~~265		147,593
Total equity	5,~~357~~249,~~180~~652		5,341,843
Total liabilities and equity	$	9,~~839~~732,~~515~~762	$	9,667,479

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Thousands of dollars, except per share amounts)	2025		2024		2025		2024
Revenues and other income
Revenue from production	$	~~683~~720,~~065~~966	$	~~797~~753,~~510~~169	$	12,~~355~~076,~~795~~761	$	12,~~592~~345,~~113~~282
Sales of purchased natural gas	—		~~3,497~~—		—		3,742
Total revenue from sales to customers	~~683~~720,~~065~~966		~~801~~753,~~007~~169		12,~~355~~076,~~795~~761		12,~~595~~349,~~855~~024
Gain on derivative instruments	10,808		—		1,349		—
Gain (loss) on derivative instruments	5,722		(1,344)		7,071		(1,344)
Gain on sale of assets and other operating income	16,~~697~~297		16,~~764~~506		410,~~137~~434		39,~~328~~834
Total revenues and other income	~~695~~732,~~570~~985		~~802~~758,~~771~~331		12,~~361~~094,~~281~~266		12,~~599~~357,~~183~~514
Costs and expenses
Lease operating expenses	~~215~~184,~~554~~353		~~259~~222,~~628~~886		~~420~~604,~~633~~986		~~493~~716,~~892~~778
Severance and ad valorem taxes	1012,~~828~~288		10,~~417~~503		1931,~~478~~766		2031,~~503~~006
Transportation, gathering and processing	5448,~~070~~146		5347,~~470~~438		~~102~~151,~~921~~067		~~110~~157,~~023~~461
Costs of purchased natural gas	—		~~2,987~~—		—		3,147
Exploration expenses, including undeveloped lease amortization	1032,~~399~~502		4231,~~677~~284		2457,~~887~~389		87118,~~106~~390
Selling and general expenses	3630,~~919~~858		2224,~~893~~871		6798,~~834~~692		5478,~~054~~925
Depreciation, depletion and amortization	~~259~~283,~~324~~465		~~215~~223,~~543~~632		~~453~~736,~~484~~949		~~426~~650,~~677~~309
Accretion of asset retirement obligations	14,~~432~~676		13,~~053~~241		2843,~~477~~153		2539,~~827~~068
Impairment of assets	—115,002		—		—115,002		34,528
Other operating expense (income)	1,833		(2,219)		7,462		5,047
Other operating expense	5,902		5,450		13,364		10,497
Total costs and expenses	~~603~~727,~~359~~192		~~618~~579,~~449~~305		1,~~125~~852,~~176~~368		1,~~260~~840,~~804~~109
Operating income from continuing operations	925,~~211~~793		~~184~~179,~~322~~026		~~236~~241,~~105~~898		~~338~~517,~~379~~405
Other income (loss)
Other income (loss)	~~(32~~15,~~304)~~271		26(3,~~245~~926)		(2914,~~902~~631)		3733,~~796~~870
Interest expense, net	(2524,~~053~~726)		(2021,~~986~~258)		(4873,~~576~~302)		(4162,~~007~~265)
Total other income (loss)	(57,357)		5,259		(78,478)		(3,211)
Total other loss	(9,455)		(25,184)		(87,933)		(28,395)
Income from continuing operations before income taxes	34,854		189,581		157,627		335,168
Income (loss) from continuing operations before income taxes	(3,662)		153,842		153,965		489,010
Income tax expense	14,~~032~~157		322,~~676~~122		3337,~~754~~911		6264,~~733~~855
Income from continuing operations	33,822		156,905		123,873		272,435
Income (loss) from continuing operations	(7,819)		151,720		116,054		424,155
Income (loss) from discontinued operations, net of income taxes	~~1,302~~(497)		(~~643~~608)		~~669~~172		(12,~~515~~123)
Net income including noncontrolling interest	35,124		156,262		124,542		270,920
Net income (loss) including noncontrolling interest	(8,316)		151,112		116,226		422,032
Less: Net income attributable to noncontrolling interest	12,844		28,523		29,226		53,179
Less: Net income (loss) attributable to noncontrolling interest	(5,343)		12,018		23,883		65,197
NET INCOME ATTRIBUTABLE TO MURPHY	$	22,280	$	127,739	$	95,316	$	217,741
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	(2,973)	$	139,094	$	92,343	$	356,835
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	(0.1502)	$	0.8493	$	0.6664	$	12.4437
Discontinued operations	~~0.01~~—		—		—		(0.01)
Net income	$	0.16	$	0.84	$	0.66	$	1.43
Net income (loss)	$	(0.02)	$	0.93	$	0.64	$	2.36
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	(0.1502)	$	0.8393	$	0.6664	$	12.4335
Discontinued operations	~~0.01~~—		—		—		(0.01)
Net income	$	0.16	$	0.83	$	0.66	$	1.42
Net income (loss)	$	(0.02)	$	0.93	$	0.64	$	2.34
Cash dividends per common share	$	0.325	$	0.300	$	0.~~650~~975	$	0.~~600~~900
Average common shares outstanding (thousands)
Basic	142,~~721~~731		~~152~~149,~~153~~384		143,~~502~~245		~~152~~151,~~409~~401
Diluted	~~143~~142,~~216~~731		~~153~~150,~~144~~353		~~144~~143,~~144~~976		~~153~~152,~~480~~437

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Thousands of dollars)	2025		2024		2025		2024
Net income including noncontrolling interest	$	35,124	$	156,262	$	124,542	$	270,920
Net income (loss) including noncontrolling interest	$	(8,316)	$	151,112	$	116,226	$	422,032
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	90(38,~~222~~027)		~~(16~~17,~~824)~~764		8850,~~555~~528		(5234,~~352~~588)
Retirement and postretirement benefit plans	~~875~~874		~~914~~1,174		12,~~739~~613		12,~~824~~998
Other comprehensive income (loss)	91(37,~~097~~153)		~~(15~~18,~~910)~~938		9053,~~294~~141		(5031,~~528~~590)
Comprehensive income including noncontrolling interest	~~126~~(45,~~221~~469)		~~140~~170,~~352~~050		~~214~~169,~~836~~367		~~220~~390,~~392~~442
Less: Comprehensive income attributable to noncontrolling interest	12,844		28,523		29,226		53,179
Less: Comprehensive income (loss) attributable to noncontrolling interest	(5,343)		12,018		23,883		65,197
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY	$	~~113~~(40,~~377~~126)	$	~~111~~158,~~829~~032	$	~~185~~145,~~610~~484	$	~~167~~325,~~213~~245

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months EndedJune 30,
	Nine Months EndedSeptember 30,
(Thousands of dollars)	2025		2024
Operating Activities
Net income including noncontrolling interest	$	124,542	$	270,920
Net income (loss) including noncontrolling interest	$	116,226	$	422,032
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	~~453~~736,~~484~~949		~~426~~650,~~677~~309
Accretion of asset retirement obligations	2843,~~477~~153		2539,~~827~~068
Long-term non-cash compensation	2228,~~016~~514		2130,~~823~~060
Deferred income tax expense	2123,~~216~~305		5345,~~928~~136
Amortization of undeveloped leases	36,~~909~~907		57,~~778~~707
Mark-to-market loss on derivative instruments	(1,371)		—
Unrealized (gain) loss on derivative instruments	(3,904)		1,344
Unsuccessful exploration well costs and previously suspended exploration costs	~~(776)~~83		5869,~~280~~548
(Income) loss from discontinued operations	(~~669~~172)		12,~~515~~123
Impairment of assets	—115,002		34,528
Other operating activities, net	(247,428)		(3338,~~959~~260)
Net decrease in non-cash working capital	7,905		1,126
Net decrease (increase) in non-cash working capital	(20,473)		31,835
Net cash provided by continuing operations activities	~~658~~998,~~731~~162		~~866~~1,~~443~~295,430
Investing Activities
Property additions and dry hole costs	(~~678~~827,~~043~~007)		(~~516~~733,~~876~~289)
Acquisition of oil and natural gas properties	(124,~~383~~405)		—
Net cash required by investing activities	(~~679~~851,~~426~~412)		(~~516~~733,~~876~~289)
Financing Activities
Borrowings on revolving credit facility	~~350~~475,000		~~200~~350,000
Repayment of revolving credit facility	(~~150~~325,000)		(~~200~~350,000)
Retirement of debt	—		(50,000)
Repurchase of common stock	(102,620)		(~~105~~300,~~887~~132)
Cash dividends paid	(93139,~~412~~799)		(91136,~~545~~208)
Withholding tax on stock-based incentive awards	(7,~~654~~669)		(25,~~298~~310)
Distributions to noncontrolling interest	(1843,~~165~~211)		(6196,~~210~~618)
Finance lease obligation payments	(~~486~~543)		(~~331~~502)
Issue costs of revolving debt facility	(18)		—
Net cash required by financing activities	(22143,~~355~~860)		(~~334~~608,~~271~~770)
Effect of exchange rate changes on cash and cash equivalents	(~~888~~499)		~~1,249~~778
Net (decrease) increase in cash and cash equivalents	(43,938)		16,545
Net increase (decrease) in cash and cash equivalents	2,391		(45,851)
Cash and cash equivalents at beginning of period	423,569		317,074
Cash and cash equivalents at end of period	$	~~379~~425,~~631~~960	$	~~333~~271,~~619~~223

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

Three Months EndedJune 30,

Six Months EndedJune 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

(Thousands of dollars except number of shares)

2025

2024

2025

2024

Common Stock

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

195,101

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

195,101

Capital in Excess of Par Value

Balance at beginning of period

~~830~~841,~~945~~833

~~816~~826,~~815~~861

848,950

880,297

Restricted stock transactions and other

(~~398~~241)

(9953)

(27,~~736~~977)

(70,~~486~~539)

Share-based compensation

119,~~286~~372

108,~~145~~847

2029,~~619~~991

1725,~~050~~897

Balance at end of period

~~841~~850,~~833~~964

~~826~~835,~~861~~655

~~841~~850,~~833~~964

~~826~~835,~~861~~655

Retained Earnings

Balance at beginning of period

6,~~799~~775,~~299~~193

6,~~590~~672,~~308~~275

6,773,289

6,546,079

Net income attributable to Murphy

22,280

127,739

95,316

217,741

Net income (loss) attributable to Murphy

(2,973)

139,094

92,343

356,835

Cash dividends paid

(46,~~386~~387)

(4544,~~772~~663)

(93139,~~412~~799)

(91136,~~545~~208)

Balance at end of period

6,~~775~~725,~~193~~833

6,~~672~~766,~~275~~706

6,~~775~~725,~~193~~833

6,~~672~~766,~~275~~706

Accumulated Other Comprehensive Loss

Balance at beginning of period

(~~628~~537,~~875~~778)

(~~555~~571,~~735~~645)

(628,072)

(521,117)

Foreign currency translation, net of income taxes

90(38,~~222~~027)

~~(16~~17,~~824)~~764

8850,~~555~~528

(5234,~~352~~588)

Retirement and postretirement benefit plans, net of income taxes

~~875~~874

~~914~~1,174

12,~~739~~613

12,~~824~~998

Balance at end of period

(~~537~~574,~~778~~931)

(~~571~~552,~~645~~707)

(~~537~~574,~~778~~931)

(~~571~~552,~~645~~707)

Treasury Stock

Balance at beginning of period

(2,~~076~~075,~~211~~823)

(1,~~742~~798,~~498~~872)

(1,995,018)

(1,737,566)

Repurchase of common stock

—

(56196,~~445~~187)

(100,876)

(~~106~~302,~~494~~681)

Awarded restricted stock, net of forfeitures

~~388~~243

7141

20,~~071~~314

45,~~188~~229

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

(2,075,823)

(1,798,872)

(2,075,823)

(1,798,872)

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

(2,075,580)

(1,995,018)

(2,075,580)

(1,995,018)

Murphy Shareholders’ Equity

5,~~198~~121,~~526~~387

5,~~323~~249,~~720~~737

5,~~198~~121,~~526~~387

5,~~323~~249,~~720~~737

Noncontrolling Interest

Balance at beginning of period

~~157~~158,~~020~~654

~~188~~178,~~514~~828

147,593

186,859

Net income attributable to noncontrolling interest

12,844

28,523

29,226

53,179

Net income (loss) attributable to noncontrolling interest

(5,343)

12,018

23,883

65,197

Distributions to noncontrolling interest owners

(1125,~~210~~046)

(3835,~~209~~408)

(1843,~~165~~211)

(6196,~~210~~618)

Balance at end of period

~~158~~128,~~654~~265

~~178~~155,~~828~~438

~~158~~128,~~654~~265

~~178~~155,~~828~~438

Total Equity

5,~~357~~249,~~180~~652

5,~~502~~405,~~548~~175

5,~~357~~249,~~180~~652

5,~~502~~405,~~548~~175

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.

Note A – Basis of Presentation

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at ~~June~~September 30, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended ~~June~~September 30, 2025 and 2024, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2024 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and ~~six~~nine-month periods ended ~~June~~September 30, 2025 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Reportable Segment Disclosures. In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. 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 FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

Income Tax Disclosures. In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. 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. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

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

U.S. - 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.

Canada - In Canada, contracts include long-term floating commodity index priced and natural gas physical forward sales fixed price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.

Disaggregation of Revenue

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

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

Three Months EndedJune 30,

Six Months EndedJune 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

(Thousands of dollars)

2025

2024

2025

2024

Net crude oil and condensate revenue

United States - Onshore

~~166~~209,~~101~~051

~~145~~161,~~955~~965

~~275~~484,~~559~~610

~~288~~450,~~498~~463

United States - Offshore 1

~~343~~356,~~080~~903

~~501~~399,~~692~~940

~~695~~1,~~442~~052,345

~~982~~1,~~131~~382,071

Canada - Onshore

1218,~~583~~115

1920,~~580~~852

2745,~~313~~428

3354,~~453~~305

Canada - Offshore

4535,~~741~~211

4380,~~326~~226

~~120~~155,~~210~~421

98178,~~101~~327

Other

~~2,948~~88

~~4,307~~(795)

23,~~948~~036

43,~~209~~414

Total crude oil and condensate revenue

~~570~~619,~~453~~368

~~714~~662,~~860~~188

1,~~121~~740,~~472~~840

12,~~406~~068,~~392~~580

Net natural gas liquids revenue

United States - Onshore

913,~~893~~736

78,~~311~~134

1832,~~380~~117

1523,~~147~~281

United States - Offshore 1

8,~~311~~353

9,~~337~~812

1725,~~560~~913

1929,~~711~~523

Canada - Onshore

1,~~523~~094

12,~~595~~402

34,~~270~~363

35,~~032~~434

Total natural gas liquids revenue

1923,~~727~~183

1820,~~243~~348

3962,~~210~~393

3758,~~890~~238

Net natural gas revenue

United States - Onshore

89,~~099~~571

34,~~352~~265

1625,~~066~~637

711,~~628~~893

United States - Offshore 1

1615,~~726~~741

1012,~~500~~311

3652,~~667~~408

2335,~~389~~700

Canada - Onshore

6853,~~060~~103

5054,~~555~~057

~~142~~195,~~380~~483

~~116~~170,~~814~~871

Total natural gas revenue

9278,~~885~~415

6470,~~407~~633

~~195~~273,~~113~~528

~~147~~218,~~831~~464

Revenue from production

~~683~~720,~~065~~966

~~797~~753,~~510~~169

12,~~355~~076,~~795~~761

12,~~592~~345,~~113~~282

Sales of purchased natural gas 2

Canada - Onshore

—

~~3,497~~—

—

3,742

Total sales of purchased natural gas

—

~~3,497~~—

—

3,742

Total revenue from sales to customers

~~683~~720,~~065~~966

~~801~~753,~~007~~169

12,~~355~~076,~~795~~761

12,~~595~~349,~~855~~024

Gain on derivative instruments

10,808

—

1,349

—

Gain (loss) on derivative instruments

5,722

(1,344)

7,071

(1,344)

Gain on sale of assets and other operating income

16,~~697~~297

16,~~764~~506

410,~~137~~434

39,~~328~~834

Total revenues and other income

~~695~~732,~~570~~985

~~802~~758,~~771~~331

12,~~361~~094,~~281~~266

12,~~599~~357,~~183~~514

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 ~~June~~September 30, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $~~172~~180.2 million and $178.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

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

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

Performance Obligations

The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. 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, 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. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

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

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

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

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 2026

Contracts to sell natural gas at USD index pricing

49 MMCFD

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at USD index pricing

30 MMCFD

Canada

Natural Gas

Q4 2028

Contracts to sell natural gas at USD index pricing

10 MMCFD

Canada

Natural Gas

Q4 2025

Contracts to sell natural gas at CAD fixed pricing

40 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at CAD fixed pricing

50 MMCFD

Canada

NGLs

Q4 2026

Contracts to sell NGLs at CAD index pricing

As produced

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

Note D – Property, Plant and Equipment

Exploratory Wells

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

As of ~~June~~September 30, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $~~110~~115.51 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~six~~nine-month periods ended ~~June~~September 30, 2025 and 2024.

(Thousands of dollars)	2025		2024
Beginning balance at January 1	$	72,055	$	49,118
Additions pending the determination of proved reserves	3843,~~469~~091		2028,~~391~~452
Capitalized exploratory well costs charged to expense	—		(26,471)
Balance at June 30	$	110,524	$	43,038
Balance at September 30	$	115,146	$	51,099

Capital additions of $3843.51 million, for the ~~six~~nine months ended ~~June~~September 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam ~~and long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America~~. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well in Vietnam encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations. Capital additions also included long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

exploration wells in the Gulf of America and long-lead equipment for Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire. Capital additions of $2028.45 million, for the ~~six~~nine months ended ~~June~~September 30, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam.

There were no capitalized well costs charged to dry hole expense for the ~~six~~nine months ended ~~June~~September 30, 2025. Capitalized well costs charged to dry hole expense of $26.5 million for the ~~six~~nine months ended ~~June~~September 30, 2024 were primarily related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America.

The preceding table excludes well costs of $3143.80 million incurred and expensed directly to dry hole for the ~~six~~nine months ended ~~June~~September 30, 2024. ~~This~~These ~~amount~~costs primarily ~~related~~included to$25.8 million for the non-operated Orange #1 (Mississippi Canyon 216) and $11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration ~~well~~wells in the Gulf of America.

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

	June 30,
	September 30,
	2025			2024
(Thousands of dollars)	Amount		No. of Wells		Amount		No. of Wells
Aging of capitalized well costs:
Zero to one year	$	1617,~~002~~562	5		$	2028,~~545~~552	3
One to two years	7275,~~004~~171		3		—		—
Two to three years	—		—		—		—
Three years or more	22,~~518~~413		3		22,~~493~~547		3
	$	~~110~~115,~~524~~146	11		$	4351,~~038~~099	6

Of the $9497.56 million of exploration well costs capitalized and classified as more than one year at ~~June~~September 30, 2025, $6568.02 million was in Vietnam, $22.1 million was in the Gulf of America, $4.76 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

~~During~~On ~~the~~July ~~first~~1, ~~quarter of~~ 2025, ~~Murphy~~the Company purchased aadditional ~~floating~~working ~~production~~interests ~~storage~~in ~~and~~Eagle ~~offloading~~Ford ~~vessel~~Shale, ~~(FPSO)~~in ~~from~~acreages BWprimarily ~~Offshore~~operated ~~(UK)~~by ~~Limited~~Murphy, for ~~a gross purchase price of~~ $~~125~~23.0 million~~, subject to customary closing adjustments~~. An initial payment of $100.0 million was made in the first quarter of 2025, with the remaining balance paid during the second quarter of 2025, after certain contractual obligations were met. The FPSO will remain at its current location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited will continue to provide operations and maintenance services under a new five-year contract.

During the first quarter of 2025, Murphy purchased a floating production storage and offloading vessel (FPSO) from BW Offshore (UK) Limited for a gross purchase price of $125.0 million. An initial payment of $100.0 million was made in the first quarter of 2025, with the remaining balance paid during the second quarter of 2025, after certain contractual obligations were met. The FPSO will remain at its current location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited will continue to provide operations and maintenance services under a new five-year contract.

Impairments

There were nopretax impairments of $115.0 million ($92.0 million excluding NCI) in the three and ~~six~~nine months ended ~~June~~September 30, 2025. The impairment related to the partial write-down of the Dalmatian field in the Gulf of America due to reserve reductions, as ~~well~~certain asprojects in the field were less competitive for capital allocation. There were no impairments in the three months ended ~~June~~September 30, 2024. There were pretax impairments of $34.5 million in the ~~six~~nine months ended ~~June~~September 30, 2024, related to the Calliope field in Mississippi Canyon in the Gulf of America, in which operational issues led to a reserve reduction.

Subsequent Event

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

Note E – Financing Arrangements and Debt

As of June 30, 2025, the Company had a $1.35 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on October 7, 2029. At June 30, 2025, the Company had $200.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At June 30, 2025, the interest rate in effect on borrowings under the RCF was 6.67%. At June 30, 2025, the Company was in compliance with all covenants related to the RCF.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt ~~(Continued)~~

Revolving Credit Facility

As of September 30, 2025, the Company had a $1.35 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on October 7, 2029. At September 30, 2025, the Company had $150.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.48%. At September 30, 2025, the Company was in compliance with all covenants related to the RCF.

Debt Extinguishment

In May 2024, the Company paid a total of $50.5 million to complete the open market repurchases of $26.5 million aggregate principal of its 5.875% senior notes due 2027 (2027 Notes) and $23.5 million aggregate principal of its 6.375% senior notes due 2028 (2028 Notes). The cash costs of the debt extinguishment of $0.5 million is included in “Interest expense, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2024.

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.

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows

	Six Months EndedJune 30,
	Nine Months EndedSeptember 30,
(Thousands of dollars)	2025		2024
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(~~976~~7,567)	$	780,~~355~~603
(Increase) decrease in inventories	(9,~~040~~532)		21,~~170~~823
(Increase) decrease in prepaid expenses	~~(11,009)~~15		2(8,~~296~~131)
Increase (decrease) in accounts payable and accrued liabilities	24(5,~~141~~373)		(943,~~689~~231)
Increase (decrease) in income taxes payable	41,~~789~~984		~~(1,006)~~771
Net decrease in non-cash working capital	$	7,905	$	1,126
Net decrease (increase) in non-cash working capital	$	(20,473)	$	31,835
Supplementary disclosures:
Net cash income taxes (refunded) paid	$	423	$	3,236
Net cash income taxes paid	$	9,217	$	12,519
Interest paid, net of amounts capitalized of $2.9 million in 2025 and $7.8 million in 2024	44,577		38,262
Interest paid, net of amounts capitalized of $5.3 million in 2025 and $10.8 million in 2024	52,426		48,708
Non-cash investing activities:
Asset retirement costs capitalized	$	921,~~427~~756	$	1619,~~175~~949
(Increase) decrease in capital expenditure accrual	2234,~~748~~210		(242,~~780~~177)

Note G – Asset Retirement Obligations

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

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

(Thousands of dollars)	June 30, 2025		June 30, 2024
Balance at beginning of year	$	1,008,884	$	914,763
Accretion	28,477		25,827
Liabilities incurred	5,428		14,199
Revisions of previous estimates	3,999		1,995
Liabilities settled	(6,359)		(2,925)
Changes due to translation of foreign currencies	9,784		(4,541)
Balance at end of period	1,050,213		949,318
Current portion of liability	(70,104)		(25,622)
Non-current portion of liability	$	980,109	$	923,696

The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note G – Asset Retirement Obligations

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


(Thousands of dollars)	September 30, 2025		September 30, 2024
Balance at beginning of year	$	1,008,884	$	914,763
Accretion	43,153		39,068
Liabilities incurred	14,267		17,975

Revisions of previous estimates	7,489		2,452
Liabilities settled	(32,145)		(1,982)



Changes due to translation of foreign currencies	6,147		(2,618)
Balance at end of period	1,047,795		969,658
Current portion of liability	(45,876)		(39,693)
Non-current portion of liability	$	1,001,919	$	929,965

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 plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. 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. employees. 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 six-month periods ended June 30, 2025 and 2024.~~13

	Three Months Ended June 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Service cost	$	1,683	$	1,706	$	84	$	135
Interest cost	8,482		8,393		708		782
Expected return on plan assets	(8,953)		(8,359)		—		—
Estimated defined contribution provision	62		54		—		—
Amortization of prior service cost (credit)	492		579		(133)		(133)
Recognized actuarial loss (gain)	1,914		2,361		(1,057)		(812)
Total net periodic benefit expense	$	3,680	$	4,734	$	(398)	$	(28)
	Six Months Ended June 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Service cost	$	3,366	$	3,412	$	168	$	270
Interest cost	16,880		16,784		1,416		1,564
Expected return on plan assets	(17,824)		(16,716)		—		—
Estimated defined contribution provision	122		109		—		—
Amortization of prior service cost (credit)	983		1,158		(266)		(266)
Recognized actuarial loss (gain)	3,805		4,721		(2,113)		(1,624)
Total net periodic benefit expense	$	7,332	$	9,468	$	(795)	$	(56)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans (Continued)

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


	Three Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Service cost	$	1,683	$	1,706	$	84	$	135
Interest cost	8,495		8,398		708		782
Expected return on plan assets	(8,967)		(8,366)		—		—
Estimated defined contribution provision	62		54		—		—
Amortization of prior service (credit) cost	492		579		(133)		(133)
Recognized actuarial (gain) loss	1,918		2,363		(1,057)		(812)



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

	Nine Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Service cost	$	5,049	$	5,118	$	252	$	405
Interest cost	25,375		25,182		2,124		2,346
Expected return on plan assets	(26,791)		(25,082)		—		—
Estimated defined contribution provision	184		163		—		—
Amortization of prior service (credit) cost	1,475		1,737		(399)		(399)
Recognized actuarial (gain) loss	5,723		7,084		(3,170)		(2,436)
Total net periodic benefit expense	$	11,015	$	14,202	$	(1,193)	$	(84)

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

During the ~~six~~nine-month period ended ~~June~~September 30, 2025, the Company made contributions of $1826.64 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 $124.35 million.

Note I – Incentive Plans

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

The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

13In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan). All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan. The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term. Additional information on the 2025 Long-Term Plan can be found in Exhibit A to definitive proxy statement filed on March 28, 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

~~other~~options ~~employees.~~(nonqualified ~~Cash~~or ~~awards~~incentive), ~~under~~stock ~~the~~appreciation ~~AIP~~rights ~~are~~(SARs), ~~determined~~restricted ~~based~~stock, onrestricted ~~the~~stock ~~Company’s~~units ~~actual~~(RSUs), ~~financial~~performance ~~and~~units, ~~operating~~performance ~~results~~shares, asdividend ~~measured~~equivalents ~~against~~and ~~the~~other ~~performance~~stock-based ~~goals established by the Committee~~incentives.

In May 2025, the Company’s shareholders approved the 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) to replace the 2020 Long-Term Incentive Plan (the 2020 Long-Term Plan). All awards granted on or after May 14, 2025, will be made under the 2025 Long-Term Plan. The 2025 Long-Term Plan will expire in 2035 and authorizes the issuance of up to 3.885 million shares of common stock over its term. Additional information on the 2025 Long-Term Plan can be found in Exhibit A to definitive proxy statement filed on March 28, 2025.

Similar to the 2020 Long-Term Plan, the 2025 Long-Term Plan authorizes the Committee to make grants of the Company’s common stock and stock-based awards to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents and other stock-based incentives.

Shares issued pursuant to awards granted under the 2025 Long-Term Plan and the previous 2020 Long-Term Plan, may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Share awards that have been canceled, expired, forfeited, or otherwise not issued will not count as shares issued under both plans.

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

Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Performance-based RSUs (TSR) 1	520,150	February 4, 2025	$	22.11	Monte Carlo
Performance-based RSUs (ROACE) 1	129,990	February 4, 2025	$	25.98	Average Stock Price
Time-based RSUs (Stock-Settled) 2	470,440	February 4, 2025	$	25.98	Average Stock Price
Time-based RSUs (Cash-Settled) 2	771,390	February 4, 2025	$	25.98	Average Stock Price
Performance-based RSUs (TSR) 1	6,070	August 11, 2025	$	19.65	Monte Carlo
Performance-based RSUs (ROACE) 1	1,520	August 11, 2025	$	23.09	Average Stock Price
Time-based RSUs (Stock-Settled) 2	5,060	August 11, 2025	$	23.09	Average Stock Price

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

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

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

The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for NEDs (the 2021 NED Plan) and the 2018 Stock Plan for NEDs. All awards granted on or after May 12, 2021 were made under the 2021 NED Plan.

14During the nine months ended September 30, 2025, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:


Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Time-Based RSUs 1	74,970	February 5, 2025	$	26.68	Closing Stock Price
Time-Based RSUs 2	2,114	March 31, 2025	$	28.40	Closing Stock Price
Time-Based RSUs 2	2,668	June 30, 2025	$	22.50	Closing Stock Price
Time-Based RSUs 2	2,112	September 30, 2025	$	28.41	Closing Stock Price

1 Non-Employee Directors’ time-based RSUs are scheduled to vest on the first anniversary of the date of grant. Non-Employee Directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election. These unvested time-based RSUs are included in the table above, will vest in one year, and become deferred RSUs.

2 Effective January 1, 2024, Non-Employee Directors can elect to receive their annual retainers in the form of deferred RSUs. Director fees that are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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

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


	Nine Months Ended September 30,
(Thousands of dollars)	2025		2024
Compensation charged against income before tax benefit	$	33,884	$	27,044
Related income tax benefit recognized in income	4,882		3,627

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Time-Based RSUs 1

74,970

February 5, 2025

26.68

Closing Stock Price

Time-Based RSUs 2

2,114

March 31, 2025

28.40

Closing Stock Price

Time-Based RSUs 2

2,668

June 30, 2025

22.50

Closing Stock Price

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

	Six Months EndedJune 30,
(Thousands of dollars)	2025		2024
Compensation charged against income before tax benefit	$	20,758	$	19,987
Related income tax benefit recognized in income	2,832		2,067

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

Note J – Net Income (Loss) Per Common Share

Net income (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income (loss) per common share for the three-month and ~~six~~nine-month periods ended ~~June~~September 30, 2025 and 2024. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months EndedJune 30,		Six Months EndedJune 30,
	Three Months EndedSeptember 30,		Nine Months EndedSeptember 30,
(Weighted-average shares)	2025	2024	2025	2024
Basic method	142,~~720~~730,~~904~~808	~~152~~149,~~153~~384,~~401~~354	143,~~502~~245,~~425~~219	~~152~~151,~~408~~400,~~912~~726
Dilutive restricted stock units	494,710	990,183	641,426	1,070,766
Dilutive restricted stock units 1	—	968,428	730,291	1,036,653
Diluted method	~~143~~142,~~215~~730,~~614~~808	~~153~~150,~~143~~352,~~584~~782	~~144,~~143,~~851~~975,510	~~153~~152,~~479~~437,~~678~~379

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

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Antidilutive restricted stock units excluded from diluted shares	908,021	—	—	—

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month and ~~six~~nine-month periods ended ~~June~~September 30, 2025 and 2024, the Company’s effective income tax rates were as follows:

	2025	2024
Three months ended June 30,	3.0%	17.2%
Three months ended September 30,	(113.5)%	1.4%
Six months ended June 30,	21.4%	18.7%
Nine months ended September 30,	24.6%	13.3%

15The effective tax rate for the three-month period ended September 30, 2025 was below the U.S. statutory tax rate of 21% due to the impact of the Company's reported pre-tax loss. Several factors affect the rate including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available, foreign currency translation adjustments, no tax benefit applied to the pretax loss of the noncontrolling interest in MP GOM, and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate. The negative impact on the effective tax rate was partially offset by the tax effect of stock-based compensation and U.S. state tax expense.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

The effective tax rate for the three-month period ended ~~June~~September 30, ~~2025~~2024 was below the U.S. statutory tax rate of 21% primarily due to ~~several~~an ~~factors~~income ~~including: no~~ tax ~~applied~~deduction tofor ~~the~~prior ~~pretax~~years’ ~~income~~Australia ofexploration ~~the noncontrolling interest in MP GOM~~spend, ~~a Canada tax credit received, and the effects of tax losses generated in Canada~~ which ~~has~~resulted ~~a higher tax rate. These impacts are partially offset by exploration and other expenses~~ in ~~certain~~an ~~foreign jurisdictions, for which no~~ income tax ~~benefits~~benefit ~~are~~of ~~currently available as well as stock-based compensation~~$33.7 million.

The effective tax rate for the ~~three~~nine-month period ended ~~June~~September 30, ~~2024~~ 2025 was ~~below~~above the U.S. statutory tax rate of 21% primarily due to noseveral ~~tax~~factors ~~applied~~including: to the ~~pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received. These impacts are partially offset by the~~ effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. ~~Federal~~federal rate,; U.S. state tax expense; stock-based compensation; foreign currency translation adjustments; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.

The effective tax rate for the ~~six~~nine-month period ended ~~June~~September 30, ~~2025~~2024 was ~~above~~below the U.S. statutory tax rate of 21% primarily due to ~~several~~an ~~factors including: the effects of~~ income ~~generated in foreign~~ tax ~~jurisdictions,~~deduction ~~certain~~for ofprior ~~which~~years’ ~~have~~Australia ~~income~~exploration ~~tax~~spend ~~rates higher than the U.S. Federal rate; U.S. 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 pretax income of the noncontrolling interest in MP GOM~~, and a Canada tax credit received~~.

The ~~effective~~Company’s tax ~~rate~~returns ~~for~~in ~~the~~multiple ~~six-month~~jurisdictions ~~period~~are ~~ended~~subject ~~June 30,~~to ~~2024~~audit ~~was~~by ~~below~~taxing ~~the U~~authorities.S. ~~statutory~~These ~~tax~~audits ~~rate~~often oftake ~~21%~~years ~~primarily due~~ to nocomplete ~~tax~~and ~~applied~~settle. toAlthough the ~~pretax~~Company ~~income~~believes ofthat ~~the~~recorded ~~noncontrolling~~liabilities ~~interest~~for inunsettled MPissues ~~GOM~~are adequate, ~~and~~additional agains ~~Canada~~or ~~tax~~losses ~~credit~~could ~~received.~~occur ~~These~~in ~~impacts~~future ~~were~~years ~~partially~~from ~~offset~~resolution byof ~~several~~outstanding ~~factors~~unsettled ~~including:~~matters. Additionally, the ~~effects~~Company ofcould ~~income~~be ~~generated~~required into ~~foreign~~pay ~~tax~~amounts ~~jurisdictions,~~into ~~certain~~an ofescrow ~~which~~account ~~have~~as ~~income~~any ~~tax~~matters ~~rates~~are ~~higher~~identified ~~than~~and appealed with the Urelevant taxing authorities.S. As ~~Federal~~of ~~rate;~~September 30, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. ~~state~~– ~~tax~~2016; ~~expense~~Canada ~~and~~– ~~certain~~2016; ~~expenses,~~and ~~including~~Malaysia ~~exploration~~– ~~and~~2018. ~~other~~The ~~expenses~~Company inhas retained certain ~~foreign~~possible ~~jurisdictions,~~liabilities ~~for~~and ~~which~~rights noto income tax ~~benefits~~receivables ~~are~~relating ~~currently~~to ~~available~~Malaysia for the years prior to 2019.

~~The~~On ~~Company’s~~July ~~tax~~4, ~~returns~~2025, inthe ~~multiple~~current ~~jurisdictions~~U.S. ~~are~~Administration ~~subject~~signed into law the legislation commonly referred to ~~audit~~as bythe ~~taxing~~One ~~authorities.~~Big ~~These~~Beautiful ~~audits~~Bill ~~often~~Act ~~take~~(OBBBA), ~~years~~which toincludes ~~complete~~a ~~and~~broad ~~settle~~range of tax reform provisions affecting corporations. ~~Although~~The OBBBA, among other changes, permanently reinstates the ~~Company~~"bonus" ~~believes~~depreciation provisions that ~~recorded~~allow ~~liabilities~~ for ~~unsettled~~the ~~issues~~immediate ~~are~~expensing ~~adequate,~~of ~~additional~~100% ~~gains~~of orthe ~~losses~~cost ~~could~~of ~~occur~~certain inqualified ~~future~~property ~~years~~acquired ~~from~~and ~~resolution~~placed ofin ~~outstanding~~service ~~unsettled~~after ~~matters.~~January ~~Additionally~~19, 2025, permanently reinstates the ~~Company~~elective ~~could~~immediate beexpensing ~~required~~of todomestic ~~pay~~research ~~amounts~~and ~~into~~experimental anexpenditures ~~escrow~~paid ~~account~~or asincurred ~~any~~in ~~matters~~tax ~~are~~years ~~identified~~beginning ~~and~~after ~~appealed~~December 31, 2024 (with a special transition rule that allows accelerated deduction of the ~~relevant~~remaining ~~taxing~~unamortized ~~authorities. As~~balance of ~~June 30,~~capitalized ~~2025~~domestic research and experimental expenditures), and permanently relaxes the ~~earliest~~limitation ~~years~~on ~~remaining~~the ~~open~~deductibility of business interest effective for ~~audit~~tax ~~and/or~~years ~~settlement~~beginning inafter ~~our~~December ~~major~~31, ~~taxing~~2024. ~~jurisdictions~~The ~~are~~OBBBA asalso ~~follows:~~modifies ~~U.S.~~certain –international ~~2016;~~tax ~~Canada~~provisions –effective ~~2016;~~for ~~and~~tax ~~Malaysia~~years –beginning ~~2018~~after December 31, 2025. The Company ~~has~~evaluated ~~retained~~the ~~certain~~effects ~~possible~~of ~~liabilities~~the OBBBA in accordance with ASC 740, Income Taxes, and ~~rights~~determined tothat ~~income~~the ~~tax~~legislation ~~receivables~~did ~~relating~~not tohave ~~Malaysia~~a material impact on its consolidated financial statements for the ~~years~~period ~~prior~~ended September 30, 2025. The Company will continue to ~~2019~~monitor any subsequent regulatory guidance related to the OBBBA.

Subsequent to the balance sheet date, on July 4, 2025, the current U.S. Administration signed into law the legislation commonly referred to as the One Big Beautiful Bill Act (OBBBA), which includes a broad range of tax reform provisions affecting corporations. The OBBBA, among other changes, permanently reinstates the "bonus" depreciation provisions that allow for the immediate expensing of 100% of the cost of certain qualified property acquired and placed in service after January 19, 2025, permanently reinstates the elective immediate expensing of domestic research and experimental expenditures paid or incurred in tax years beginning after December 31, 2024 (with a special transition rule that allows accelerated deduction of the remaining unamortized balance of capitalized domestic research and experimental expenditures), and permanently relaxes the limitation on the deductibility of business interest effective for tax years beginning after December 31, 2024. The OBBBA also modifies certain international tax provisions effective for tax years beginning after December 31, 2025. The Company is currently evaluating the impact of these tax law changes and will recognize the income tax effects in the consolidated financial statements beginning in the period in which the OBBBA was signed into law.

Note L – Financial Instruments and Risk Management

Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.

1617

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at ~~June~~September 30, 2025 and 2024.

Commodity Price Risks

The Company is subject to commodity price risk related to products it produces and sells. During the ~~second~~third quarter of 2025, the Company had the following open natural gas swap contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.

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

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural Gas

3.65

7/1/2025

9/30/2025

Fixed price derivative swap

United States

Natural Gas

3.74

10/1/2025

12/31/2025

During ~~first~~the ~~six~~nine months ended ~~June~~September 30, 2025 and September 30, 2024, the Company did not have any crude oil derivative contracts. ~~During~~At ~~first six months ended June~~ September 30, 2024, the Company ~~did~~had ~~not~~natural ~~have~~gas ~~any~~derivative ~~crude~~contracts ~~oil~~outstanding orfor ~~natural~~20 ~~gas~~MMCF/d ~~derivative~~at ~~contracts.~~an average price of $3.20/MCF.

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

(Thousands of dollars)

Asset (Liability) Derivatives Fair Value

Type of Derivative Contract

Balance Sheet Location

~~June~~September 30, 2025

December 31, 2024

Commodity swaps

Accounts ~~payable~~receivable

~~(337)~~2,197

~~(1,707)~~—

Commodity swaps

Accounts payable

—

(1,707)

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

		Gain (Loss)			Gain (Loss)
(Thousands of dollars)		Three Months ~~EndedJune~~EndedSeptember 30,			~~Six~~Nine Months Ended ~~June~~September 30,
Type of Derivative Contract	Statement of Operations Location		2025		2024		2025		2024
Commodity swaps	Gain (loss) on derivative instruments		$	105,~~808~~722	$	—(1,344)	$	17,~~349~~071	$	—(1,344)

17Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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


	September 30, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:

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

Liabilities:

Commodity swaps	$	—	$	—	$	—	$	—	$	—	$	1,707	$	—	$	1,707
Nonqualified employee savings plan	21,168		—		—		21,168		19,469		—		—		19,469
	$	21,168	$	—	$	—	$	21,168	$	19,469	$	1,707	$	—	$	21,176

The commodity swaps receivable as of September 30, 2025 was $2.2 million and recorded as “Accounts receivable” in the Consolidated Balance Sheets. The fair value ~~measurements~~of commodity swaps was based on active market quotes for ~~these~~NYMEX ~~assets~~Henry ~~and~~Hub ~~liabilities~~natural atgas. ~~June 30,~~The ~~2025~~before ~~and~~tax ~~December 31,~~income ~~2024,~~effect ~~are~~of ~~shown~~changes in the ~~following~~fair ~~table~~value of natural gas derivative contracts is recorded in “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations.

	June 30, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Liabilities:
Commodity swaps	$	—	$	337	$	—	$	337	$	—	$	1,707	$	—	$	1,707
Nonqualified employee savings plan	19,763		—		—		19,763		19,469		—		—		19,469
	$	19,763	$	337	$	—	$	20,100	$	19,469	$	1,707	$	—	$	21,176

The commodity swaps liability as of June 30, 2025 was $0.3 million and recorded as “Accounts payable” in the Consolidated Balance Sheets. The fair value of commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in the fair value of natural gas derivative contracts is recorded in “Loss on derivative instruments” in the Consolidated Statements of Operations.

The 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. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. 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.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at ~~June~~September 30, 2025 and December 31, 2024.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at ~~June~~September 30, 2025 and December 31, 2024. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, were minimal.

June 30, 2025

December 31, 2024

September 30, 2025

December 31, 2024

(Thousands of dollars)

CarryingAmount

FairValue

CarryingAmount

FairValue

Financial liabilities:

Current and long-term debt

1,~~475~~426,~~869~~153

1,~~354~~366,~~719~~561

1,275,374

1,185,961

~~Fair Values – Nonrecurring~~19

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

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Fair Values – Nonrecurring

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

There were no impairment expenses incurred in the three months ended September 30, 2024. In the nine months ended September 30, 2024, an impairment charge of $34.5 million was triggered for the Calliope field, due to operational issues that led to reserve reductions.

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

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

Six Months Ended June 30, 2024

Nine Months Ended September 30, 2025

Net BookValuePrior toImpairment

TotalPretaxImpairment

Fair Value

(Thousands of dollars)

Level 1

Level 2

Level 3

Property, plant and equipment:

Impaired proved properties

United States - Offshore

—

~~437~~42,397

34157,~~965~~399

34115,~~528~~002


	Nine Months Ended September 30, 2024
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3








Property, plant and equipment:
Impaired proved properties
United States - Offshore	$	—	$	—	$	437	$	34,965	$	34,528

Note M – Accumulated Other Comprehensive Loss

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

(Thousands of dollars)	ForeignCurrencyTranslationGains (Losses)		Retirement andPostretirementBenefit PlanAdjustments		Total
Balance at December 31, 2024	$	(516,324)	$	(111,748)	$	(628,072)
Components of other comprehensive income (loss):
Before reclassifications to income	8850,~~555~~528		—		8850,~~555~~528
Reclassifications to income ¹	—		12,~~739~~613		12,~~739~~613
Net other comprehensive income (loss)	8850,~~555~~528		12,~~739~~613		9053,~~294~~141
Balance at June 30, 2025	$	(427,769)	$	(110,009)	$	(537,778)
Balance at September 30, 2025	$	(465,796)	$	(109,135)	$	(574,931)

1 Reclassifications before taxes of $23.1 million are included in the computation of net periodic benefit expense for the ~~six~~nine-month period ended ~~June~~September 30, 2025. See Note H for additional information. Related income taxes of $0.35 million are included in "Income tax expense” on the Consolidated Statements of Operations for the ~~six~~nine-month period ended ~~June~~September 30, 2025.

~~Note N – Environmental and Other Contingencies~~20

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; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies ~~(Continued)~~

~~products,~~The ~~wastewater~~Company’s operations and ~~hazardous~~earnings ~~materials;~~have been and may be affected by various forms of governmental action both in the ~~emission~~United States and ~~discharge~~throughout the world. Examples of such ~~materials~~governmental action include, but are by no means limited to: tax ~~the~~legislation ~~environment~~changes, including ~~methane~~tax ~~and~~rate ~~other~~changes, ~~greenhouse~~and ~~gas~~retroactive ~~(GHG)~~tax ~~emissions~~claims; ~~wildlife~~trade policies, ~~habitat~~tariffs and ~~water~~other ~~protection~~trade restrictions; ~~water~~royalty ~~access,~~and ~~use~~revenue sharing increases; import and ~~disposal~~export controls; ~~the~~price ~~placement,~~controls; ~~operation~~currency ~~and~~controls; ~~decommissioning~~allocation of ~~production~~supplies ~~equipment~~of crude oil and petroleum products and other goods; ~~the~~expropriation ~~health~~of property; restrictions and ~~safety~~preferences affecting the issuance of ~~our~~oil ~~employees~~and natural gas or mineral leases; restrictions on drilling and/or production; laws, ~~contractors~~regulations and ~~communities~~government ~~where~~action ~~our~~intended ~~operations~~for ~~are~~the ~~located,~~promotion ~~including~~of ~~indigenous~~safety ~~communities;~~and the protection and/or remediation of the environment including in connection with the purported causes ~~and~~or potential impacts of climate change.; ~~These~~governmental support for other forms of energy; and laws and regulations ~~also~~affecting ~~generally~~the ~~require~~Company’s ~~permits~~relationships ~~for~~with ~~existing~~employees, ~~operations~~suppliers, ascustomers, ~~well~~stockholders asand others. Given the ~~construction~~factors orinvolved ~~development~~in ofvarious ~~new~~government ~~operations~~actions, ~~and~~including political considerations, it is difficult to predict their likelihood, the ~~decommissioning~~form ofthey ~~facilities~~may ~~once~~take, ~~production~~or ~~has~~the ~~ceased.~~effect they may have on the Company.

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 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; 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.

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this 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. EPA. However, the U.S. EPA has since published an interim final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the OBBBA passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. 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. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. 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. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently 21

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

~~unidentified~~or ~~sites~~under isthe properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not ~~expected~~under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. 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. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on ~~the Company~~Murphy’s ~~future~~ net income, ~~cash~~financial ~~flows~~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.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note O – Common Stock Issued and Outstanding

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

(Number of shares outstanding)

~~June~~September 30, 2025

~~June~~September 30, 2024

Beginning of period

145,845,124

152,748,642

Restricted stock awards 1

~~494~~500,~~071~~146

1,~~102~~103,~~501~~503

Treasury shares purchased

(3,613,450)

(28,~~634~~008,~~595~~786)

End of period

142,~~725~~731,~~745~~820

~~151~~145,~~216~~843,~~548~~359

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 three months ended ~~June~~September 30, 2025, the Company did not repurchase any ~~share~~shares of its common stock. During the ~~six~~nine months ended ~~June~~September 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.9 million including excise taxes and fees). As of ~~June~~September 30, 2025, the Company had $550.1 million of its common stock remaining available to repurchase under the program.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments

Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses, interest expense and unallocated overhead, is shown in the table to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia, and U.S. refining and marketing operations as discontinued operations for all periods presented. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

	Exploration and Production
(Millions of dollars)	UnitedStates 1		Canada		Other		TotalE&P		Corporate,Other, and Discontinued Operations		ConsolidatedTotal
Three Months Ended June 30, 2025
Three Months Ended September 30, 2025
Revenue from production	$	~~552~~613.24	$	~~127~~107.95	$	20.91	$	~~683~~721.0	$	—	$	~~683~~721.0
Gain on sales of assets and other operating income	10.3		0.45		—		10.78		1311.14		1412.82
Revenues from external customers	~~553~~613.57		~~128~~108.30		20.91		~~684~~721.78		1311.14		~~697~~733.82
Lease operating expenses
Lease operating expenses and taxes other than income	~~100~~95.06		4641.62		0.94		~~147~~137.52		—		~~147~~137.52
Repair and maintenance	13.9		1.14		—		15.03		—		15.03
Workovers	5231.68		0.51		—		5331.19		—		5331.19
Total lease operating expenses	~~166~~141.53		4842.27		0.94		~~215~~184.64		—		~~215~~184.64
Severance and ad valorem taxes	1011.59		0.34		—		1012.83		—		1012.83
Transportation, gathering and processing	3023.3		2324.8		—		5448.1		—		5448.1
Costs of purchased natural gas	—		—		—		—		—		—
Selling and general expenses	1.9		5.4		2.2		9.5		21.4		30.9
Selling and general expenses	4.8		5.7		2.6		13.1		23.8		36.9
Exploration Expenses
Geological and geophysical	019.71		—0.1		01.21		020.93		—		020.93
Dry holes and previously suspended exploration costs	(1.0.1)		—		0.19		(0.9)8		—		(0.9)8
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	3.65		—0.1		67.8		1011.4		—		1011.4
Total exploration expenses	322.35		—0.2		79.18		1032.45		—		1032.45
Depreciation, depletion and amortization	~~218~~242.31		3839.13		~~1.2~~—		~~257~~281.64		12.71		~~259~~283.35
Accretion of asset retirement obligations	11.6		2.6		0.2		14.4		—		14.4
Impairment of assets	115.0		—		—		115.0		—		115.0
Other operating expenses	1.3		0.7		(1.4)		0.6		1.2		1.8
Accretion of asset retirement obligations	11.8		2.6		0.2		14.6		0.1		14.7
Interest Income	(0.5)		—		—		(0.5)		(2.7)		(3.2)
Other operating expenses	5.7		0.1		0.2		6.0		(0.1)		5.9
Interest expense, net of capitalization	—		0.2		—		0.2		24.9		25.1
Interest Income	(0.4)		—		—		(0.4)		(2.7)		(3.1)
Interest expense, net of capitalization	—		0.1		—		0.1		24.6		24.7
Income tax expense
Current income tax expense (benefit)	01.70		0(1.37)		~~0.2~~—		1(0.27)		(52.0)8		(32.8)1
Deferred income tax expense (benefit)	197.29		(20.2)		(0.74)		167.3		(~~11.~~5.2)		42.81
Total income tax expense (benefit)	198.9		(1.9)		(0.54)		176.56		(162.54)		14.02
Other segment costs (income)	1.0.8		0.14		(0.13)		10.29		35(12.35)		36(11.56)
Segment income (loss) - including NCI 1	$	8628.59	$	10(6.51)	$	(712.30)	$	8910.78	$	(5419.61)	$	35(8.13)
Additions to property, plant, equipment	$	~~176~~111.26	$	4526.70	$	2041.81	$	~~242~~178.7	$	2.73	$	~~245~~181.40
Total assets at quarter-end	6,~~984~~848.91		21,~~038~~981.68		~~364~~411.48		9,~~387~~241.97		~~451~~491.61		9,~~839~~732.58

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

2224

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

	Exploration and Production
(Millions of dollars)	UnitedStates 1		Canada		Other		TotalE&P		Corporate,Other, and Discontinued Operations		ConsolidatedTotal
Three Months Ended June 30, 2024
Three Months Ended September 30, 2024
Revenue from production	$	~~678~~596.15	$	~~115~~157.16	$	4(0.38)	$	~~797~~753.51	$	—	$	~~797~~753.51
Sales of purchased natural gas	—		3.5		—		3.5		—		3.5
Gain on sales of assets and other operating income	0.5		0.3		—		1.0		4.2		5.2
Gain on sales of assets and other operating income	1.4		0.4		—		1.8		—		1.8
Revenues from external customers	597.0		157.9		(0.8)		754.1		4.2		758.3
Revenues from external customers	679.5		119.0		4.3		802.8		—		802.8
Lease operating expenses
Lease operating expenses and taxes other than income	~~120~~108.40		4351.7		0.53		~~164~~160.60		—		~~164~~160.60
Repair and maintenance	15.71		01.98		—		16.69		—		16.69
Workovers	7645.17		20.3		—		7846.40		—		7846.40
Total lease operating expenses	~~212~~168.28		4653.98		0.53		~~259~~222.69		—		~~259~~222.69
Severance and ad valorem taxes	10.01		0.43		—		10.45		—		10.45
Transportation, gathering and processing	3426.23		1921.32		—		5347.5		—		5347.5
Costs of purchased natural gas	—		3.0		—		3.0		—		3.0
Selling and general expenses	(1.7)		4.7		1.9		4.9		20.0		24.9
Selling and general expenses	(3.4)		4.5		1.8		2.9		20.0		22.9
Exploration Expenses											—
Exploration Expenses
Geological and geophysical	9.9		0.1		2.8		12.8		—		12.8
Geological and geophysical	3.0		0.1		5.0		8.1		—		8.1
Dry holes and previously suspended exploration costs	10.8		—		0.4		11.2		—		11.2
Dry holes and previously suspended exploration costs	25.8		—		—		25.8		—		25.8
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	2.5		0.2		4.7		7.3		—		7.3
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	3.8		0.1		4.9		8.8		—		8.8
Total exploration expenses	23.2		0.3		7.9		31.3		—		31.3
Total exploration expenses	32.6		0.2		9.9		42.7		—		42.7
Depreciation, depletion and amortization	179.3		42.8		—		222.1		1.5		223.6
Depreciation, depletion and amortization	175.0		37.0		0.9		212.9		2.6		215.5
Impairment of assets	—		—		—		—		—		—
Accretion of asset retirement obligations	10.89		2.1		0.2		13.12		—		13.12
Other operating expenses	(34.1)8		10.1		0.15		(15.9)4		(0.3)1		(25.2)5
Interest Income	(20.1)		—		—		(20.1)		(2.7)		(22.8)
Interest income	(0.8)		—		—		(0.8)		(3.1)		(3.9)
Interest expense, net of capitalization	—0.3		~~0.1~~—		—		0.13		2021.80		2021.93
Income tax expense
Current income tax expense (benefit)	10.18		(38.5)2		(0.31)		(28.1)9		02.31		(111.8)0
Deferred income tax expense (benefit)	4234.74		(0.7)2		0(34.60)		420.6		(89.25)		34(8.49)
Total income tax expense (benefit)	4335.82		(48.2)4		0(34.91)		409.5		(7.94)		322.61
Other segment costs (income)	1.8		~~(0.3)~~—		0.1		1.69		(46.2)4		(28.6)3
Segment income (loss) - including NCI 1	$	~~185~~138.78	$	824.92	$	~~(10~~22.1)4	$	~~184~~185.54	$	(2834.3)	$	~~156~~151.21
Additions to property, plant, equipment	$	~~195~~130.2	$	4213.15	$	1220.15	$	~~249~~164.42	$	48.30	$	~~253~~172.72
Total assets at quarter-end	7,~~222~~088.63		2,~~050~~043.50		~~244~~266.26		9,~~517~~397.39		~~376~~318.45		9,~~893~~716.74

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

	Exploration and Production
(Millions of dollars)	UnitedStates 1		Canada		Other		TotalE&P		Corporate,Other, and Discontinued Operations		ConsolidatedTotal
Six Months Ended June 30, 2025
Nine Months Ended September 30, 2025
Revenue from production	$	1,~~059~~673.71	$	~~293~~400.27	$	23.90	$	12,~~355~~076.8	$	—	$	12,~~355~~076.8
Gain on sales of assets and other operating income	3.36		01.83		—		4.19		315.60		719.79
Revenues from external customers	1,~~063~~676.07		~~294~~402.0		23.90		12,~~359~~081.97		315.60		12,~~363~~096.57
Lease operating expenses
Lease operating expenses and taxes other than income	~~200~~295.39		91133.91		1.26		~~293~~430.46		—		~~293~~430.46
Repair and maintenance	2438.10		24.60		—		2642.70		—		2642.70
Workovers	99131.75		0.89		—		~~100~~132.54		—		~~100~~132.54
Total lease operating expenses	~~324~~465.14		95138.30		1.26		~~420~~605.60		—		~~420~~605.60
Severance and ad valorem taxes	1830.87		01.71		—		1931.58		—		1931.58
Transportation, gathering and processing	5982.04		4368.97		—		~~102~~151.91		—		~~102~~151.91
Costs of purchased natural gas	—		—		—		—		—		—
Selling and general expenses	8.7		17.1		6.7		32.5		66.2		98.7
Selling and general expenses	6.8		11.7		4.5		23.0		44.8		67.8
Exploration Expenses
Geological and geophysical	323.90		—0.1		01.56		424.47		—		424.47
Dry holes and previously suspended exploration costs	(0.89)		—		0.1.0		(0.7)1		—		(0.7)1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	69.38		0.12		1422.86		2132.26		—		2132.26
Total exploration expenses	931.49		0.13		1525.42		2457.94		—		2457.94
Depreciation, depletion and amortization	~~377~~619.67		70109.58		1.32		~~449~~730.47		46.12		~~453~~736.59
Accretion of asset retirement obligations	23.0		5.1		0.4		28.5		—		28.5
Impairment of assets	115.0		—		—		115.0		—		115.0
Other operating expenses	4.0		1.7		(1.3)		4.4		3.1		7.5
Accretion of asset retirement obligations	34.8		7.7		0.6		43.1		0.1		43.2
Interest Income	(0.9)		—		—		(0.9)		(6.0)		(6.9)
Other operating expenses	9.7		1.8		(1.1)		10.4		3.0		13.4
Interest expense, net of capitalization	—		—		0.1		0.1		48.5		48.6
Interest Income	(1.3)		—		—		(1.3)		(8.7)		(10.0)
Interest expense, net of capitalization	—		0.1		0.1		0.2		73.1		73.3
Income tax expense
Current income tax expense (benefit)	12.32		1412.03		0.2		1514.57		(20.91)		1214.6
Deferred income tax expense (benefit)	4351.76		(1.68)		(01.71)		4148.47		(2025.24)		2123.23
Total income tax expense (benefit)	4553.08		1210.45		(0.59)		5663.94		(2325.15)		3337.89
Other segment cost	12.86		01.61		~~0.3~~—		23.7		3523.61		3826.38
Segment income (loss) - including NCI 1	$	~~194~~223.43	$	5245.08	$	(1830.54)	$	~~227~~238.97	$	(~~103~~122.45)	$	~~124~~116.52
Additions to property, plant, equipment	$	~~493~~586.24	$	~~101~~127.10	$	5694.14	$	~~650~~807.48	$	79.02	$	~~657~~817.40
Total assets at quarter-end	6,~~984~~848.91		21,~~038~~981.68		~~364~~411.48		9,~~387~~241.97		~~451~~491.61		9,~~839~~732.58

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)

	Exploration and Production
(Millions of dollars)	UnitedStates 1		Canada		Other		TotalE&P		Corporate,Other, and Discontinued Operations		ConsolidatedTotal
Six Months Ended June 30, 2024
Nine Months Ended September 30, 2024
Revenue from production	$	1,~~336~~933.50	$	~~251~~408.59	$	43.24	$	12,~~592~~345.23	$	—	$	12,~~592~~345.23
Sales of purchased natural gas	—		3.7		—		3.7		—		3.7
Gain on sales of assets and other operating income	23.61		01.72		—		34.3		—4.2		38.35
Revenues from external customers	1,~~339~~936.1		~~255~~413.98		43.24		12,~~599~~353.23		—4.2		12,~~599~~357.25
Lease operating expenses
Lease operating expenses and taxes other than income	~~240~~348.6		90142.41		01.70		~~331~~491.7		—		~~331~~491.7
Repair and maintenance	2641.89		13.42		—		2845.21		—		2845.21
Workovers	~~131~~177.52		2.58		—		~~134~~180.0		—		~~134~~180.0
Total lease operating expenses	~~398~~567.97		94148.31		01.70		~~493~~716.98		—		~~493~~716.98
Severance and ad valorem taxes	1929.89		01.71		—		2031.50		—		2031.50
Transportation, gathering and processing	7097.81		3960.24		—		~~110~~157.05		—		~~110~~157.05
Costs of purchased natural gas	—		3.1		—		3.1		—		3.1
Selling and general expenses	(3.5.2)		914.62		34.09		913.19		4565.0		5478.19
Exploration Expenses
Geological and geophysical	313.75		0.12		58.96		922.73		—		922.73
Dry holes and previously suspended exploration costs	5767.19		—		1.27		5869.36		—		5869.36
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	79.16		—0.2		1216.07		1926.15		—		1926.15
Total exploration expenses	6791.90		0.14		1927.10		87118.14		—		87118.14
Depreciation, depletion and amortization	~~349~~528.03		71114.31		0.9		~~421~~643.23		57.50		~~426~~650.73
Impairment of assets	34.5		—		—		34.5		—		34.5
Accretion of asset retirement obligations	2132.10		46.34		0.46		2539.80		—0.1		2539.81
Other operating expenses	38.20		2.01		0.16		510.37		(0.32)		510.05
Interest Income	(2021.86)		—		—		(2021.86)		(58.56)		(2630.32)
Interest expense, net of capitalization	—0.3		0.2		0.1		0.36		4061.7		4162.03
Income tax expense
Current income tax expense	2.09		210.25		0.32		413.56		46.2		819.78
Deferred income tax expense (benefit)	72106.59		0.57		0(33.37)		73.39		(1928.38)		5445.01
Total income tax expense (benefit)	74109.58		211.72		0(33.65)		7787.85		(1522.16)		6264.79
Other segment costs (income)	3.5.3		~~0.1~~—		0.23		35.86		(137.62)		(91.86)
Segment income (loss) - including NCI 1	$	~~320~~459.20	$	2852.35	$	~~(20~~1.9)5	$	~~327~~513.60	$	(5691.70)	$	~~270~~422.90
Additions to property, plant, equipment	$	~~350~~511.53	$	~~109~~122.39	$	1544.06	$	~~474~~678.8	$	816.4	$	~~483~~695.2
Total assets at quarter-end	7,~~222~~088.63		2,~~050~~043.50		~~244~~266.26		9,~~517~~397.39		~~376~~318.45		9,~~893~~716.74

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

2527

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note Q – Leases

Nature of Leases

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

Options to extend lease terms are at the Company’s discretion. Early lease terminations are at the Company’s discretion and/or the mutual agreement between the Company and lessor. Purchase options also exist for certain leases.

During the third quarter of 2025, the Company exercised an option to extend an operating lease pertaining to a drill ship used in our offshore business. This resulted in an increase of $167.1 million (discounted) to our right-of-use assets and operating lease liabilities at September 30, 2025.

Maturity of Lease Liabilities


(Thousands of dollars)	Operating Leases		Finance Leases		Total
2025	$	60,970	$	319	$	61,289
2026	248,750		1,274		250,024
2027	141,648		1,274		142,922
2028	62,259		1,275		63,534
2029	59,471		464		59,935
Remaining	419,202		958		420,160
Total future minimum lease payments	992,300		5,564		997,864
Less imputed interest	(199,449)		(1,352)		(200,801)
Present value of lease liabilities 1	$	792,851	$	4,212	$	797,063

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

Lease Term and Discount Rate


	September 30, 2025		December 31, 2024
Weighted average remaining lease term:
Operating leases	8 years		8 years
Finance leases	5 years		6 years
Weighted average discount rate:
Operating leases	5.5	%	5.7	%
Finance leases	4.9	%	4.9	%

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended ~~June~~September 30, 2025 included under “Item 1. Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2024. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.

Overview

Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The Company boasts over a century of strong execution and innovative, full-cycle development capabilities, with a focus on value creation to enhance shareholder returns. The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. 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 ~~second~~third quarter of 2025 were as follows:

•Increased production to ~~196~~206,~~315~~936 barrels of oil equivalent (BOE) per day (including NCI), up from ~~187~~191,~~847~~273 BOE per day in the ~~second~~third quarter of 2024, and up from ~~163~~196,~~374~~315 BOE per day in the ~~first~~second quarter of 2025

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

Subsequent to the ~~second~~third quarter, Murphy completed the installation of ~~2025:~~the LDV-A platform jacket and initiated development drilling at the Lac Da Vang (Golden Camel) development project in Vietnam.

~~•Closed~~Murphy anOil ~~acquisition~~Corporation’s ofnet ~~additional~~loss ~~working~~from ~~interests~~continuing inoperations, ~~Eagle~~including ~~Ford~~noncontrolling ~~Shale~~interest, infor ~~acreages~~the ~~primarily~~three ~~operated~~months byended ~~Murphy~~September 30, ~~for~~2025, awas ~~gross~~$7.8 ~~purchase~~million ~~price~~compared to net income of $23151.7 million for the same period in 2024. The results for 2025 were impacted by higher impairment expense ($115.0 million), higher depreciation, depletion and amortization expenses (DD&A) ($59.8 million), and lower revenues from production ($32.2 million). These changes were partially offset by lower lease operating expenses ($38.5 million) and higher other income ($19.2 million).

~~•Declared~~The aimpairment ~~quarterly~~expense ~~dividend~~during the quarter related to the Dalmatian field in the Gulf of $0America that resulted from reserve reductions, as certain projects in the field were less competitive for capital allocation.~~325~~ ~~per~~The ~~share~~increase orin $1DD&A resulted from higher total production levels and elevated rates in the Gulf of America.30 ~~per~~Lower ~~share~~revenues ~~annualized~~during the quarter were mainly the result of lower oil prices, partially offset by higher overall production volumes. Lower lease operating expenses were primarily due to lower workover costs and production handling fees in the Gulf of America and cost-savings initiatives in the Eagle Ford Shale, and were partially offset by higher production in the Eagle Ford Shale. Higher other income was the result of unrealized foreign exchange gains.

~~•Signed~~For athe ~~rig~~three ~~contract~~months ~~for~~ended ~~our~~September ~~upcoming~~30, ~~Côte~~2025, ~~d’Ivoire~~total ~~three-~~hydrocarbon production was 206,936 barrels of oil equivalent per day, an increase of 8% compared to the third quarter of 2024. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in both the U.S. and Canada. Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year at Karnes and Catarina. Higher production in Canada Onshore relates to better well ~~exploration~~performance ~~program~~at Tupper Montney. Lower production in the Gulf of America and Canada Offshore was due to natural decline and both planned and unplanned downtime for mechanical issues.

~~Murphy~~Net ~~Oil Corporation’s net~~ income from continuing operations, including noncontrolling interest, for the ~~three~~nine months ended ~~June~~September 30, 2025, was $33116.81 million, a decrease of $~~123~~308.1 million compared to the same period in 2024. Lower net income from continuing operations was largely driven ~~primarily~~ by lower revenues from production ($~~114~~268.~~4 million), lower other income ($58.~~5 million), and higher depreciation, depletion and amortization expenses (DD&A) ($43.8 million). These decreases were partially offset by lower lease operating expenses ($44.1 million), lower exploration expenses ($32.3 million), and lower income tax expenses ($31.6 million).

Lower revenues during the quarter were the result of lower oil prices partially offset by higher production volumes. Lower other income was the result of unrealized foreign exchange losses and no repeat of prior year interest income on joint interest receivables. Higher DD&A was due to higher overall production. Lower lease operating expenses were caused primarily by less workover expenses in the current period and lower production handling fees related to lower Gulf of America production. Lower exploration expenses were due to no dry holes recorded in 2025 (2024: non-operated Orange #1 (Mississippi Canyon 216) exploration well), and lower income tax expenses were driven by lower net income.29

For the three months ended June 30, 2025, total hydrocarbon production was 196,315 barrels of oil equivalent per day, an increase of 5% compared to the second quarter of 2024. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in both the U.S. and Canada. Higher production in the Eagle Ford Shale was primarily the result of new wells online during the period, and higher production at Tupper Montney was due to better well performance and no repeat of 2024 planned turnaround-related downtime. Lower production in the Gulf of America was caused by

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Overview (Continued)

~~downtime~~million), higher DD&A ($86.6 million), higher impairment expense ($80.5 million), and ~~well~~lower ~~performance~~other ~~issues~~income at($48.5 ~~several~~million). ~~wells~~These ~~but~~changes ~~was~~were partially offset by ~~wells~~lower ~~coming~~lease ~~back~~operating ~~online~~expenses ~~during~~($111.8 ~~the~~million), ~~quarter~~lower exploration expenses ($61.0 million), and lower income tax expenses ($26.9 million).

~~Net~~Lower ~~income~~revenues ~~from~~were ~~continuing~~primarily ~~operations,~~due ~~including~~to ~~noncontrolling~~the ~~interest~~lower price of oil, ~~for~~combined ~~the~~with ~~six~~lower ~~months~~production ~~ended~~in ~~June~~the 30Gulf of America, ~~2025~~and were partially offset by higher production in the Eagle Ford Shale, ~~was~~and ~~$123~~the higher price of natural gas.9 ~~million~~Higher DD&A was due to higher production in the Eagle Ford Shale and higher rates in the Gulf of America, apartially ~~decrease~~offset by lower production volumes in the Gulf of ~~$148~~America.6 ~~million~~Higher ~~compared~~impairment expense was related to the ~~same~~Dalmatian ~~period~~field in ~~2024~~the Gulf or America. Lower ~~net~~other income ~~from~~was ~~continuing~~primarily ~~operations~~the ~~was~~result ~~largely~~of ~~driven~~unrealized byforeign exchange losses. Lower lease operating expenses related to lower ~~revenues~~workover ~~from~~costs and production ~~($236.3~~handling ~~million)~~fees in the Gulf of America, combined with lower ~~other~~operating ~~income~~costs ~~($67.7~~due ~~million),~~to ~~and~~the ~~higher~~acquisition ~~DD&A~~of ~~($26~~the BW Pioneer FPSO earlier this year.8 ~~million),~~Cost ~~and~~reduction ~~was~~activities ~~partially~~in ~~offset~~the byEagle Ford Shale also contributed to overall lower lease operating expenses. Lower exploration expenses were primarily due to no dry hole expense recorded in 2025 (~~$73.3~~2024: ~~million~~Sebastian #1 (Mississippi Canyon 387), ~~lower~~operated exploration ~~expenses~~well, the Orange #1 (~~$62.2~~Mississippi ~~million~~Canyon 216) non-operated exploration well, ~~lower~~and ~~impairment~~the ofpreviously ~~assets~~suspended exploration well at Hoffe Park #1 (~~$34.5~~Mississippi ~~million~~Canyon 166), ~~and~~in ~~lower~~the Gulf of America). Lower dry hole costs were partially offset by higher exploration activity in Côte d'Ivoire. Lower income tax ~~expenses~~expense ~~($29.0~~was ~~million)~~due to lower net income for the period.

~~Lower~~For ~~revenues~~the ~~were~~nine ~~primarily~~months ~~driven~~ended bySeptember 30, ~~lower~~2025, ~~crude~~total ~~oil~~hydrocarbon ~~prices~~production ~~combined~~was ~~with~~189,035 ~~decreased~~barrels of oil ~~production~~equivalent inper ~~the~~day, ~~current~~an ~~period.~~increase ~~These~~of ~~items~~2% ~~were~~compared ~~partially~~to ~~offset~~the bysame ~~higher~~period ~~natural~~in ~~gas~~2024. ~~prices,~~Higher ~~and higher~~ production ~~volumes~~ in the Eagle Ford Shale ~~and Canada. Lower other income~~ was primarily the result of ~~unrealized~~new ~~foreign~~wells ~~exchange~~online ~~losses~~in ~~and~~the nocurrent ~~repeat of prior~~ year ~~interest~~in ~~income~~Karnes onand ~~joint interest receivables~~Catarina. Higher ~~DD&A~~production ~~was~~in ~~due~~Canada Onshore relates to ~~higher~~better ~~production~~well performance at ~~new~~Tupper ~~onshore wells~~Montney. Lower ~~lease~~production ~~operating expenses were caused primarily by less workover expenses~~ in the ~~current period and lower production handling fees related to reduced~~ Gulf of America ~~production.~~related ~~Lower exploration expenses were due~~ to noplanned ~~dry holes recorded in 2025 (2024: non-operated Orange #1 (Mississippi Canyon 216)~~ and ~~Hoffe~~unplanned ~~Park #1 (Mississippi Canyon 166) exploration wells). Impairment charges related to the Calliope field were recorded in the first quarter of 2024~~downtime, and ~~there~~was ~~were~~partially nooffset ~~impairment charges recorded in 2025. Lower income tax expenses were driven~~ by ~~lower~~new ~~net~~wells ~~income~~online.

For the six months ended June 30, 2025, total hydrocarbon production was 179,935 barrels of oil equivalent per day, a decrease of 1% compared to the same period in 2024. The decrease was principally due to lower offshore production in the Gulf of America, partially offset by increased production in the Eagle Ford Shale and in both onshore and offshore Canada. Lower production in the Gulf of America was caused by downtime and well performance issues at several wells but was partially offset by other wells coming back online. Higher production in the Eagle Ford Shale was the result of bringing online new wells in Karnes during the period, and higher production at Tupper Montney was due to better performance in 2025, and no repeat of planned turnaround-related downtime in 2024.

Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. 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 for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

At ~~June~~September 30, 2025, the West Texas Intermediate (WTI) crude oil price was $6562.1137 per barrel, whereas the crude oil price at the end of ~~July~~October 2025 was $6960.2698, reflecting ana 62% ~~increase~~decrease in price. As of ~~August~~November 43, 2025 closing, the NYMEX WTI forward curve price for the remainder of 2025 was $6561.0305 per barrel. Reductions in commodity prices will reduce the Company’s future profits and operating cash flows.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations

Murphy’s Net income (loss) by type of business and geographic segment is presented below:

	Income (Loss)
	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024		2025		2024
Exploration and production
United States	$	8628.59	$	~~185~~138.78	$	~~194~~223.43	$	~~320~~459.20
Canada	10(6.51)		824.92		5245.08		2852.35
Other	(712.30)		~~(10~~22.1)4		(1830.54)		~~(20~~1.9)5
Total exploration and production	8910.78		~~184~~185.54		~~227~~238.97		~~327~~513.60
Corporate and other	(5518.96)		(2733.7)		(~~104~~122.17)		(5588.29)
Income from continuing operations	33.8		156.8		123.8		272.4
Income (loss) from continuing operations	(7.8)		151.7		116.0		424.1
Discontinued operations, net of tax 1	1(0.35)		(0.6)		0.72		(12.51)
Net income including noncontrolling interest	35.1		156.2		124.5		270.9
Net income (loss) including noncontrolling interest	(8.3)		151.1		116.2		422.0
Less: Net income attributable to noncontrolling interest	12.8		28.5		29.2		53.2
Less: Net income (loss) attributable to noncontrolling interest	(5.3)		12.0		23.9		65.2
Net income attributable to Murphy	$	22.3	$	127.7	$	95.3	$	217.7
Net income (loss) attributable to Murphy	$	(3.0)	$	139.1	$	92.3	$	356.8

1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Exploration and Production Continuing Operations

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

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024		2025		2024
Revenues and other income
Revenue from production	$	~~683~~721.0	$	~~797~~753.52	$	12,~~355~~076.8	$	12,~~592~~345.13
Sales of purchased natural gas	—		~~3.5~~—		—		3.7
Other income	10.78		10.89		4.19		3.4.3
Total revenues and other income	~~684~~721.78		~~802~~754.81		12,~~359~~081.97		12,~~599~~353.23
Cost and Expenses
Costs and expenses
Lease operating expenses	~~215~~184.54		~~259~~222.69		~~420~~605.60		~~493~~716.98
Severance and ad valorem taxes	1012.83		10.45		1931.58		2031.50
Transportation, gathering and processing	5448.01		5347.5		~~102~~151.91		~~110~~157.05
Costs of purchased natural gas	—		~~2.9~~—		—		3.1
Depreciation, depletion and amortization	~~257~~281.64		~~212~~222.91		~~449~~730.47		~~421~~643.23
Impairments of assets	—		—		—		34.5
Impairment of assets	115.0		—		115.0		34.5
Accretion of asset retirement obligations	14.46		13.12		2843.51		2539.80
Total exploration expenses, including undeveloped lease amortization	10.4		42.8		24.9		87.2
Exploration expenses, including undeveloped lease amortization	32.5		31.2		57.4		118.4
Selling and general expenses	139.15		25.90		2332.05		914.0
Other	16.6		~~(20~~6.2)7		613.30		(~~11.~~4.7)
Results of operations before taxes	~~107~~17.34		~~224~~195.90		~~284~~302.81		~~405~~600.4
Income tax provisions	176.6		409.46		5663.94		7787.84
Results of operations (excluding Corporate segment) 1	$	8910.78	$	~~184~~185.54	$	~~227~~238.97	$	~~327~~513.60

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Pricing

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Weighted average sales prices)	2025		2024		2025		2024
Crude oil and condensate – dollars per barrel
United States - Onshore	$	6465.0048	$	8075.7149	$	66.8424	$	7877.7655
United States - Offshore 1	6467.4800		8175.6765		6867.2381		7978.6142
Canada - Onshore 2	5956.9433		7266.2518		6159.7346		7068.2462
Canada - Offshore 2	6469.7642		8480.3406		70.3917		8582.2583
Other 2	~~70.86~~—		~~100.92~~—		7072.8697		9678.4320
Natural gas liquids – dollars per barrel
United States - Onshore	1918.5657		19.4805		2119.0792		2019.0871
United States - Offshore 1	1920.3518		22.7750		2221.7585		23.5620
Canada - Onshore 2	3326.8488		3534.4600		3532.0054		3534.1664
Natural gas – dollars per thousand cubic feet
United States - Onshore	2.7564		1.5977		32.0387		1.77
United States - Offshore 1	3.4739		2.0028		3.8973		2.3230
Canada - Onshore 2	1.6522		1.3734		1.9668		1.6856

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

2 U.S. dollar equivalent.

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Average price for the period)	2025		2024		2025		2024
Oil and NGLs
WTI ($/BBL)	$	6364.7493	$	8075.5710	$	6766.5870	$	~~78.~~77.54
Natural gas
NYMEX ($/MMBTU)	3.1603		2.0409		3.7249		2.2318
AECO (C$/MCF)	10.6963		10.1869		1.9350		1.8445

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Production Volumes

The following table contains hydrocarbons produced during the three-month and ~~six~~nine-month periods ended ~~June~~September 30, 2025 and 2024. For further discussion on volumes, please see the “Revenues from Production” section on page 3336.

Three Months EndedJune 30,

Six Months EndedJune 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

(Barrels per day unless otherwise noted)

2025

2024

2025

2024

Net crude oil and condensate

United States - Onshore

2834,~~519~~703

1923,~~873~~320

2226,~~779~~797

2021,~~127~~199

United States - Offshore 1

5856,~~840~~071

6659,~~818~~282

5756,~~222~~835

6664,~~448~~042

Canada - Onshore

23,~~307~~495

23,~~978~~425

2,~~445~~799

2,~~617~~888

Canada - Offshore

5,~~638~~518

7,~~506~~880

76,~~237~~658

67,~~885~~219

Other

~~296~~278

~~245~~171

~~275~~276

~~245~~221

Total net crude oil and condensate

95100,~~600~~065

9794,~~420~~078

8993,~~958~~365

9695,~~322~~569

Net natural gas liquids

United States - Onshore

58,~~557~~042

4,~~125~~640

45,~~818~~905

4,~~145~~312

United States - Offshore 1

4,~~720~~500

4,~~505~~739

4,~~265~~344

4,~~596~~644

Canada - Onshore

~~494~~442

~~494~~768

~~516~~491

~~474~~572

Total net natural gas liquids

1012,~~771~~984

910,~~124~~147

910,~~599~~740

9,~~215~~528

Net natural gas – thousands of cubic feet per day

United States - Onshore

3239,~~389~~411

2326,~~197~~223

2932,~~306~~711

2324,~~714~~556

United States - Offshore 1

5250,~~964~~477

5758,~~762~~747

5251,~~062~~528

5556,~~462~~565

Canada - Onshore

~~454~~473,~~310~~431

~~406~~437,~~856~~316

~~400~~425,~~898~~342

~~381~~400,~~155~~012

Total net natural gas

~~539~~563,~~663~~319

~~487~~522,~~815~~286

~~482~~509,~~266~~581

~~460~~481,~~331~~133

Total net hydrocarbons - including NCI 2,3

~~196~~206,~~315~~936

~~187~~191,~~847~~273

~~179~~189,~~935~~035

~~182~~185,~~259~~286

Noncontrolling interest

Net crude oil and condensate – barrels per day

(65,~~070~~998)

(6,~~717~~188)

(5,~~925~~950)

(6,~~608~~467)

Net natural gas liquids – barrels per day

(~~244~~228)

(~~217~~193)

(~~207~~214)

(~~214~~207)

Net natural gas – thousands of cubic feet per day

(1,~~942~~963)

(21,~~003~~947)

(1,~~590~~715)

(2,~~039~~008)

Total noncontrolling interest 2,3

(6,~~638~~553)

(76,~~268~~706)

(6,~~397~~450)

(7,~~162~~009)

Total net hydrocarbons - excluding NCI 2,3

~~189~~200,~~677~~383

~~180~~184,~~579~~567

~~173~~182,~~538~~585

~~175~~178,~~097~~277

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.

3134

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ITEM 2. 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 and ~~six~~nine-month periods ended ~~June~~September 30, 2025 and 2024. For further discussion on volumes, please see the “Revenues from Production” section on page 3336.

Three Months EndedJune 30,

Six Months EndedJune 30,

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

(Barrels per day unless otherwise noted)

2025

2024

2025

2024

Net crude oil and condensate

United States - Onshore

2834,~~520~~703

1923,~~873~~320

2226,~~779~~797

2021,~~127~~199

United States - Offshore 1

5857,~~469~~903

6757,~~507~~467

56,~~313~~849

6764,~~781~~317

Canada - Onshore

23,~~307~~495

23,~~978~~425

2,~~444~~799

2,~~617~~888

Canada - Offshore

75,~~762~~513

510,~~645~~892

98,~~436~~114

67,~~322~~857

Other

~~457~~—

~~469~~—

~~230~~152

~~240~~159

Total net crude oil and condensate

97101,~~515~~614

9695,~~472~~104

9194,~~202~~711

9796,~~087~~420

Net natural gas liquids

United States - Onshore

58,~~557~~042

4,~~125~~640

45,~~819~~905

4,~~145~~312

United States - Offshore 1

4,~~720~~500

4,~~505~~739

4,~~264~~344

4,~~596~~644

Canada - Onshore

~~494~~442

~~494~~768

~~516~~491

~~474~~572

Total net natural gas liquids

1012,~~771~~984

910,~~124~~147

910,~~599~~740

9,~~215~~528

Net natural gas – thousands of cubic feet per day

United States - Onshore

3239,~~388~~411

2326,~~197~~223

2932,~~306~~711

2324,~~714~~556

United States - Offshore 1

5250,~~964~~477

5758,~~762~~747

5251,~~062~~528

5556,~~462~~565

Canada - Onshore

~~454~~473,~~310~~431

~~406~~437,~~855~~316

~~400~~425,~~898~~342

~~381~~400,~~155~~012

Total net natural gas

~~539~~563,~~662~~319

~~487~~522,~~814~~286

~~482~~509,~~266~~581

~~460~~481,~~331~~133

Total net hydrocarbons - including NCI 2,3

~~198~~208,~~230~~484

~~186~~192,~~898~~299

~~181~~190,~~179~~381

~~183~~186,~~024~~137

Noncontrolling interest

Net crude oil and condensate – barrels per day

(6,~~014~~273)

(65,~~792~~920)

(5,~~792~~954)

(6,~~798~~503)

Net natural gas liquids – barrels per day

(~~243~~228)

(~~217~~193)

(~~207~~214)

(~~214~~207)

Net natural gas – thousands of cubic feet per day

(1,~~942~~963)

(21,~~003~~947)

(1,~~590~~715)

(2,~~039~~008)

Total noncontrolling interest 2,3

(6,~~581~~828)

(76,~~343~~438)

(6,~~264~~454)

(7,~~352~~045)

Total net hydrocarbons - excluding NCI 2,3

~~191~~201,~~649~~656

~~179~~185,~~555~~861

~~174~~183,~~915~~927

~~175~~179,~~672~~092

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.

3235

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted.

Revenues from Production

The Company’s production revenues by country and product were as follows:

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024		2025		2024
Revenues from production
United States - Oil	$	~~509~~566.20	$	~~647~~561.69	$	~~971~~1,537.0	$	1,~~270~~832.6
United States - Natural gas liquids	1822.1		1617.69		3558.90		3452.98
United States - Natural gas	2425.83		1316.96		5278.70		3147.06
Canada - Oil	5853.3		62101.91		~~147~~200.59		~~131~~232.6
Canada - Natural gas liquids	1.51		12.64		34.34		35.04
Canada - Natural gas	6853.1		5054.61		~~142~~195.45		~~116~~170.89
Other - Oil	20.91		4(0.38)		23.90		43.24
Total revenue from production	$	~~683~~721.0	$	~~797~~753.52	$	12,~~355~~076.8	$	12,~~592~~345.13

Revenues from production for the three months ended ~~June~~September 30, 2025, decreased by $~~114~~32.42 million compared to the same period in 2024. ~~Lower~~Revenues ~~revenues~~decreased ~~were~~ primarily ~~driven~~due byto lower crude oil prices, ~~combined~~reduced ~~with decreased~~ oil production in the Gulf of America ~~due~~from to downtime ~~related~~relating to ~~workovers,~~ planned ~~turnarounds~~maintenance and ~~well~~ongoing ~~issues~~workovers, ~~primarily~~and downtime in offshore Canada at ~~the~~Terra ~~Samurai~~Nova and ~~Cascade~~Hibernia &related ~~Chinook~~to ~~fields~~well issues in the quarter. These ~~items~~reductions were partially offset by higher ~~natural~~production ~~gas~~at ~~prices,~~Karnes ~~new~~and ~~wells~~Catarina ~~online~~ in the Eagle Ford Shale atrelated ~~the~~to ~~Karnes~~better ~~field,~~well performance and new wells online, atand ~~Mormont~~higher insales ~~the~~volumes ~~Gulf~~at ofCascade ~~America,~~& ~~wells~~Chinook ~~back online from downtime~~ in the Gulf of America~~, and timing of deliveries in Canada Offshore~~.

Revenues from production for the ~~six~~nine months ended ~~June~~September 30, 2025, decreased $~~236~~268.35 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, ~~combined~~as ~~with~~well as decreased ~~oil~~ production in the Gulf of America due to ~~downtime~~well ~~related~~issues toat ~~workovers~~Samurai, ~~planned~~natural ~~turnarounds~~decline ~~and~~of ~~well~~new ~~issues~~wells, ~~primarily at the Samurai~~ and ~~Cascade~~downtime &for ~~Chinook~~maintenance ~~fields~~at Khaleesi. These ~~items~~decreases were partially offset by ~~higher~~increased ~~natural~~production ~~gas~~in ~~prices,~~Eagle ~~new~~Ford ~~wells~~Shale ~~online~~due into ~~the~~new ~~Eagle~~wells ~~Ford~~at ~~Shale~~Karnes and ~~Gulf of America~~Catarina, as well as ~~wells back online from downtime~~ in the Gulf of America, ~~and~~at ~~timing~~Mormont ofand ~~deliveries in Canada Offshore~~Neidermeyer.

3336

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Lease Operating and Transportation, Gathering and Processing Expenses

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

	Three Months EndedJune 30,								Six Months EndedJune 30,
	Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
	(Millions of dollars)				(Dollars per equivalent barrel)				(Millions of dollars)				(Dollars per equivalent barrel)
	2025		2024		2025		2024		2025		2024		2025		2024
Lease operating expenses
United States - Onshore	$	2931.59	$	3732.09	$	87.2004	$	1411.6103	$	5991.2	$	72105.74	$	108.0875	$	1413.1400
United States - Offshore	~~137~~109.04		~~175~~136.20		2016.9179		2320.5854		~~264~~374.92		~~326~~462.23		2119.1364		21.9652
Canada - Onshore	3530.60		35.32		43.9894		54.4396		6595.8		66101.24		54.2173		5.4628
Canada - Offshore	12.67		1118.65		1724.8696		2218.6051		2942.52		2846.17		1719.2905		2421.4367
Other	0.84		0.53		~~19.95~~—		~~12.26~~—		1.26		01.70		2937.0254		1623.1066
Total lease operating expenses	$	~~215~~184.54	$	~~259~~222.69	$	119.9561	$	1512.2760	$	~~420~~605.60	$	~~493~~716.98	$	1211.8364	$	14.8305
Transportation, gathering and processing
United States - Onshore	$	23.12	$	2.42	$	0.6272	$	0.9373	$	47.58	$	57.03	$	0.7775	$	0.9989
United States - Offshore	2820.1		3124.81		43.2808		43.2964		5474.56		6589.8		43.3591		4.4318
Canada - Onshore	2223.0		1820.81		3.0802		2.8984		4063.3		3656.79		3.1913		32.0396
Canada - Offshore	1.8		01.51		23.5349		1.0106		35.64		23.5		2.1042		21.1363
Total transportation, gathering and processing	$	5448.01	$	5347.5	$	32.0051	$	32.1468	$	~~102~~151.91	$	~~110~~157.05	$	32.1491	$	3.3009

For the three months ended ~~June~~September 30, 2025, lease operating expenses decreased by $4438.15 million and transportation, gathering and processing expenses increased by $0.56 million compared to the same period in 2024. In the Gulf of America, ~~current~~decreases ~~quarter~~in ~~workovers~~lease atoperating ~~Marmalard,~~expenses ~~Khaleesi~~primarily ~~(completed~~related into Q3lower ~~2025)~~production volumes and ~~Samurai~~handling ~~(completed~~fees inand Q2lower ~~2025)~~operating charges as a result of the acquisition of the BW Pioneer FPSO. In addition, current quarter workover costs at Marmalard, Khaleesi and Samurai were lower than expenditures at Neidermeyer and Dalmatian in the prior year. In the Eagle Ford Shale, ~~there were~~ lower operating ~~costs~~expenses ~~resulting~~were ~~from~~due to cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization. ~~The~~throughout ~~Company also realized lower operating costs at~~ the ~~U.S. Offshore Cascade & Chinook fields that resulted from the purchase of the FPSO. In addition~~year, ~~lower~~and ~~Gulf of America production handling fees, resulting from lower production, contributed to the decrease in the quarter. These decreases~~ were ~~partially~~largely offset by higher production ~~volumes from both the U~~.S. ~~Onshore and Canada Onshore areas.~~

For the ~~six~~nine months ended ~~June~~September 30, 2025, lease operating expenses decreased by $73111.38 million, and transportation, gathering and processing expenses decreased by $76.14 million compared to the same period in 2024. In the Gulf of America, ~~workover~~decreases ~~costs at~~primarily ~~the~~related ~~Khaleesi,~~to ~~Mormont~~lower ~~and~~workover ~~Samurai~~costs ~~fields~~due ~~were~~to ~~lower than~~ expenditures at ~~the~~ Neidermeyer ~~field~~and Dalmatian in the prior year~~. In the Eagle Ford Shale~~, ~~lower~~which ~~operating~~were ~~costs~~partially ~~resulted~~offset ~~from~~by ~~cost-savings~~current ~~initiatives~~year ~~including~~workovers ~~workforce reductions~~ at ~~the end of 2024~~Marmalard, ~~lower~~Khaleesi ~~repairs~~ and ~~maintenance, and equipment optimization~~Samurai. ~~The~~Lower ~~Company~~operating charges also ~~realized~~occured ~~lower~~as ~~operating~~a ~~costs~~result atof the ~~U.S.~~acquisition ~~Offshore~~of ~~Cascade~~the &BW ~~Chinook~~Pioneer ~~fields~~FPSO ~~that~~earlier ~~resulted~~in ~~from~~ the ~~purchase~~year. ofIn the ~~FPSO.~~Eagle InFord ~~addition~~Shale, lower ~~Gulf~~operating ofcosts ~~America~~resulted ~~production~~from ~~handling~~cost-savings ~~fees~~initiatives, ~~resulting~~including ~~from~~workforce ~~lower~~reductions ~~production,~~at ~~contributed~~the toend ~~the~~of ~~decrease~~2024, inlower ~~the~~repairs ~~period.~~and ~~These~~maintenance, ~~decreases~~and equipment optimizations, were partially offset by higher ~~production~~volume ~~volumes~~related ~~from both the U~~costs.~~S. Onshore and Canada Onshore areas.~~

3437

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Depreciation, Depletion and Amortization Expenses

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

	Three Months EndedJune 30,								Six Months EndedJune 30,
	Three Months EndedSeptember 30,								Nine Months EndedSeptember 30,
	(Millions of dollars)				(Dollars per equivalent barrel)				(Millions of dollars)				(Dollars per equivalent barrel)
	2025		2024		2025		2024		2025		2024		2025		2024
DD&A
United States - Onshore	$	~~107~~137.45	$	7588.10	$	2930.8830	$	29.6460	$	~~174~~311.49	$	~~149~~237.2	$	29.6895	$	29.0425
United States - Offshore	~~110~~104.96		9991.93		16.9306		13.4478		~~203~~307.28		~~199~~291.81		16.2116		13.4555
Canada - Onshore	3033.05		3034.85		4.2038		4.7687		5487.16		5993.05		4.2932		4.8687
Canada - Offshore	85.18		68.23		11.4753		128.0027		1622.42		1220.36		910.5903		109.7158
Other	~~1.2~~—		~~0.9~~—		~~28.38~~—		~~20.69~~—		1.32		0.9		31.0266		20.6882
Total DD&A	$	~~257~~281.64	$	~~212~~222.91	$	14.2867	$	12.5256	$	~~449~~730.47	$	~~421~~643.23	$	1314.7006	$	12.6461

DD&A for the three months ended ~~June~~September 30, 2025 increased by $4459.73 million compared to the same period in 2024. The increase was primarily due to higher sales volumes atin ~~both~~the ~~U.S.~~Eagle ~~and~~Ford ~~Canada~~Shale ~~Onshore~~and ~~areas, in addition to~~ higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

DD&A for the ~~six~~nine months ended ~~June~~September 30, 2025 increased by $2887.24 million. The increase was primarily due to higher sales volumes in the Eagle Ford Shale ~~as a result of new wells~~ and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

Impairment of Assets

~~There~~For ~~were no impairments for~~ the three and ~~six~~nine months ended ~~June~~September 30, 2025, asthe ~~well~~Company asimpaired noassets ~~impairments~~ for $115.0 million related to the ~~three~~partial ~~months~~write-down ~~ended~~of ~~June~~the 30Dalmatian field in the Gulf of America due to reserve reductions in the quarter, ~~2024~~as certain projects in the field were less competitive for capital allocation.

There were no impairments for the three months ended September 30, 2024. Impairment of assets for the ~~six~~nine months ended ~~June~~September 30, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

Exploration Expenses

The Company’s exploration expenses were as follows:

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024		2025		2024
Exploration expenses
Dry holes and previously suspended exploration costs	$	(0.9)8	$	2511.92	$	(0.7)1	$	5869.35
Geological and geophysical	020.83		812.27		424.47		922.63
Other exploration	8.25		5.74		1725.38		1318.59
Undeveloped lease amortization	2.39		31.09		36.98		57.87
Total exploration expenses, including undeveloped lease amortization	$	1032.45	$	4231.82	$	2457.94	$	87118.24

Exploration expenses for the three months ended ~~June~~September 30, 2025 ~~decreased~~increased by $321.43 million compared to the same period in 2024, ~~primarily~~due asto ahigher ~~result~~geological and geophysical costs in the Gulf of America, and were partially offset by lower dry hole costs in the current period. InDry ~~the~~hole ~~second~~costs ~~quarter~~in of 2024, ~~the dry hole costs~~ related to the ~~Orange~~Sebastian #1 (Mississippi Canyon ~~216~~387) ~~non-~~operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

Exploration expenses for the six months ended June 30, 2025 decreased by $62.3 million compared to the same period in 2024. In 2024, there were dry holes and previously suspended exploration costs relating to the Orange 38

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Results of Operations (Continued)

Exploration expenses for the nine months ended September 30, 2025 decreased by $61.0 million compared to the same period in 2024. Lower exploration costs were primarily due to no dry holes recorded in 2025 (2024: Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and ~~for~~ the previously suspended ~~costs~~exploration ~~for~~well at Hoffe Park #1 (Mississippi Canyon 166) ~~exploration well~~ in the Gulf of America). This was partially offset by higher exploration activity in Côte d'Ivoire.

Other

Other expenses from E&P continuing operations for the three months ended September 30, 2025 decreased by $0.1 million compared to the same period in 2024. Other expenses for the nine months ended September 30, 2025 increased by $17.7 million compared to the same period in 2024 due to no interest income received in the current year.

Income Taxes

Income taxes for the three and ~~six~~nine months ended ~~June~~September 30, 2025 decreased by $223.80 million and $2024.90 million, respectively, compared to the same periods in 2024. Lower income tax for each period is primarily the result of lower net income.

Corporate

Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge commodity price) and corporate overhead not allocated to E&P. Realized and unrealized gains and losses on derivative instruments result from ~~increases~~changes in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.

For the three months ended ~~June~~September 30, 2025, the Corporate segment reported a loss of $5518.96 million, ana ~~unfavorable~~favorable variance of $2815.21 million, compared to the same period in 2024. The ~~unfavorable~~favorable variance was primarily due to ~~higher~~a ~~unrealized~~ foreign exchange ~~losses~~gain ($3918.84 million) for the period, primarily relating to our Canadian subsidiary, ~~partially~~combined ~~offset~~with ~~by unrealized~~ gains on derivative instruments ($~~10.~~3.9 million), and partially offset by higher income tax expense of $5.1 million.

The Corporate segment reported a loss of $~~104~~122.17 million for the ~~six~~nine months ended ~~June~~September 30, 2025, an unfavorable variance of $4833.98 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher ~~unrealized~~ foreign exchange losses ($5031.05 million) and higher interest expense ($11.4 million) due to the timing of interest payments on long-term debt, and was partially offset by gains on derivative instruments ($8.4 million) due to fixed price sales contracts.

Financial Condition

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

~~Cash Flows~~39

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

	Six Months EndedJune 30,
(Millions of dollars)	2025		2024
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	658.7	$	866.4
Net cash required by investing activities	(679.4)		(516.9)
Net cash required by financing activities	(22.4)		(334.3)
Effect of exchange rate changes on cash and cash equivalents	(0.9)		1.3
Net (decrease) increase in cash and cash equivalents	$	(43.9)	$	16.5

Cash Provided by Continuing Operations Activities

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

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

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

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


	Nine Months Ended September 30,
(Millions of dollars)	2025		2024
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	998.2	$	1,295.4
Net cash required by investing activities	(851.4)		(733.3)
Net cash required by financing activities	(143.9)		(608.8)

Effect of exchange rate changes on cash and cash equivalents	(0.5)		0.8
Net increase (decrease) in cash and cash equivalents	$	2.4	$	(45.9)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the nine months ended September 30, 2025 was $297.3 million lower compared to the same period in 2024. The decrease in cash flows from operations activities was primarily due to lower revenue from production ($268.5 million), timing of non-cash working capital ($52.3 million) settlements, and an increase in selling and general expenses ($19.8 million), partially offset by lower lease operating expenses ($111.8 million).

Cash Required by Investing Activities

Net cash required by investing activities for the ~~six~~nine months ended ~~June~~September 30, 2025 was $~~162~~118.61 million higher compared to the same period in 2024. The increase was primarily due to a gross payment of $125.0 million for the purchase of an FPSO in the Gulf of America and higher development drilling at Eagle Ford Shale, partially offset by lower development drilling at Gulf of America.

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

	Six Months EndedJune 30,
	Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024
Property additions and dry hole costs per the cash flow statements	$	~~678~~827.0	$	~~516~~733.93
Acquisition of oil properties per the cash flow statements	124.4		—
Geophysical and other exploration expenses	1946.38		1935.05
Capital expenditure accrual changes and other	(2030.36)		287.8
Total capital expenditures	$	~~678~~867.46	$	~~564~~776.76

Total accrual basis capital expenditures are shown below.

	Six Months EndedJune 30,
	Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024
Capital Expenditures
Exploration and production	$	~~671~~858.4	$	~~556~~760.32
Corporate	79.02		816.4
Total capital expenditures	$	~~678~~867.46	$	~~564~~776.76

Higher capital expenditures in the ~~six~~nine months ended ~~June~~September 30, 2025 compared to the same period of 2024 were primarily attributable to ~~higher~~the ~~field~~FPSO ~~development~~purchase ~~costs~~ in the Gulf of America ~~attributable to the FPSO purchase~~ and higher development drilling in the Eagle Ford Shale related to new wells online. ~~Higher~~Also ~~exploratory~~contributing ~~drilling in Vietnam and other development drilling in the Gulf of America also contributed~~ to the increase. ~~These increases~~ were ~~partially~~higher ~~offset~~exploratory bydrilling ~~lower exploration costs~~ and field development ~~drilling costs~~ in ~~the~~Vietnam, ~~Gulf~~which ofincluded ~~America~~progressing ~~due~~the toLDV-A ~~prior~~platform ~~year~~jacket ~~spend~~installation onand ~~the non~~pipe-~~operated~~laying ~~Ocotillo~~campaign. #1These ~~(Mississippi~~increases ~~Canyon~~were ~~40)~~partially ~~and~~offset ~~Orange~~by #1lower ~~(Mississippi Canyon 216)~~ exploration ~~wells,~~costs and ~~Khaleesi~~ development ~~costs,~~drilling ~~respectively.~~

Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($248.1 million), Eagle Ford Shale ($230.2 million), Tupper Montney and Kaybob Duvernay ($92.0 million), and in Vietnam ($29.6 million). Exploration costs in 2025 were $57.2 million, primarily comprised of activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05, and Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 exploration wells, and activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells.40

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

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

Capital expenditures in 2025 primarily relate to development drilling and field development activities in the Gulf of America ($257.6 million), Eagle Ford Shale ($296.4 million), Tupper Montney and Kaybob Duvernay ($113.0 million), and in Vietnam ($57.7 million). Exploration costs in 2025 were $90.9 million, primarily comprised of activities in Vietnam for the Lac Da Hong-1X (Pink Camel), Block 15-1/05; and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17 exploration wells, activities in the Gulf of America related to long lead equipment purchases for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Côte d'Ivoire related to long lead equipment purchases for the Bubale-1X (Block CI-709), Civette-1X (Block CI-502), and Caracal-1X (Block CI-102) exploration wells.

Cash Required by Financing Activities

Net cash required by financing activities for the ~~six~~nine months ended ~~June~~September 30, 2025 decreased by $~~311~~464.9 million compared to the same period in 2024. In 2025, the cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.65 per share ($93.4 million), and distributions to the noncontrolling interest in MP GOM ($18.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($200.0 million).

In ~~2024~~2025, the cash required by financing activities was principally for the repurchase of common shares ($~~105~~102.96 million), year-to-date cash dividends to shareholders of $0.975 per share ($91139.58 million), and distributions to the noncontrolling interest in MP GOM ($6143.2 million), ~~debt~~and ~~repurchases~~was ~~($50.0~~partially ~~million),~~offset ~~and~~by ~~withholding~~net ~~tax~~borrowings on ~~stock-based~~the ~~incentive~~senior ~~awards~~unsecured RCF ($25150.30 million).

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

Liquidity

At ~~June~~September 30, 2025, the Company had approximately $1.56 billion of liquidity consisting of $~~379~~426.60 million in cash and cash equivalents and $1,~~149~~199.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029. As of ~~June~~September 30, 2025, the Company had $~~200~~150.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At ~~June~~September 30, 2025, the interest rate in effect on borrowings under the RCF was 6.6748%. At ~~June~~September 30, 2025, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of ~~June~~September 30, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $~~112~~67.4 million, the majority of which was held in Canada ($7328.~~6 million), Vietnam ($~~9.0 million), Mexico ($8.0 million), ~~and~~ the U.K. ($7.4 million) and Vietnam ($6.7 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

Working Capital

(Millions of dollars)	~~June~~September 30, 2025		December 31, 2024
Working capital
Total current assets	$	~~762~~807.15	$	785.3
Total current liabilities	~~909~~857.37		942.8
Net working capital liability	$	(~~147~~50.2)	$	(157.5)

As of ~~June~~September 30, 2025, net working capital increased by $10107.43 million compared to December 31, 2024. The increase was primarily attributable to lower current operating lease obligations ($6242.54 million), lower ~~other~~accounts ~~accrued~~payable ~~liabilities~~ ($3342.5 million), and higher ~~prepaid~~accounts ~~expenses~~receivable ($11.62 million). ~~These items were partially offset by lower cash and equivalents ($43.9 million), higher accounts payable ($37.1 million) and higher current asset retirement obligations ($22.0 million).~~

Lower lease obligations were due to lower day rates onrelated ~~the~~to ~~Noble~~an ~~Stanley~~offshore ~~Lafosse~~ drilling rig, ongoing lease amortization and the absence of lease rental payments related to the BW Pioneer FPSO in the Gulf of America. Lower other accrued liabilities were related to lower incentive award obligations in the current year, and higher prepaid expenses were primarily due to the renewal of insurance policies. Lower cash and equivalents were due to lower net income, the BW Pioneer FPSO purchase, and returns to shareholders in the form of share repurchases and dividends. Higher accounts payable related to higher production in the Eagle Ford Shale. Higher current asset retirement obligations related to planned abandonment activities in U.S. Offshore in the next 12 months.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Financial Condition (Continued)

Higher accounts receivable were due to higher tax receivables related to increased Vietnam development and exploration expenditures. Lower cash and equivalents were due to lower net income, the BW Pioneer FPSO purchase, and returns to shareholders in the form of share repurchases and dividends. Lower accounts payable related to higher production in the Eagle Ford Shale.

Capital Employed

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

	June 30, 2025				December 31, 2024
	September 30, 2025				December 31, 2024
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,~~475~~425.02	2221.18	%	$	1,274.5	19.7	%
Murphy shareholders' equity	5,~~198~~121.54		7778.92	%	5,194.3		80.3	%
Total capital employed	$	6,~~673~~546.56	100.0	%	$	6,468.8	100.0	%

At ~~June~~September 30, 2025, long-term debt of $1,~~475~~425.02 million increased by $~~200~~150.57 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF. The total of the fixed-rate notes had a weighted average maturity of 8.96 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity ~~increased~~decreased by $472.29 million in 2025, primarily due to ~~foreign~~dividends ~~currency translation~~ ($88139.68 million) and ~~awarded~~shares ~~restricted~~repurchased ~~stock~~ ($20100.19 million), including excise tax, partially offset by ~~shares~~net ~~repurchased~~income ($~~100~~92.93 million), ~~including~~foreign ~~excise~~currency ~~tax~~translation ($50.5 million), and awarded restricted stock ($20.3 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

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

Accounting Changes and Recent Accounting Pronouncements

See Note B to the Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Other Key Performance Metrics

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), 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, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars, except per share amounts)	2025		2024		2025		2024
Net income attributable to Murphy (GAAP) 1	$	22.3	$	127.7	$	95.3	$	217.7
Net income (loss) attributable to Murphy (GAAP) 1	$	(3.0)	$	139.1	$	92.3	$	356.8
Discontinued operations (income) loss	(10.3)5		0.6		(0.72)		12.51
Net income from continuing operations attributable to Murphy	21.0		128.3		94.6		219.2
Net income (loss) from continuing operations attributable to Murphy	(2.5)		139.7		92.1		358.9
Adjustments:
Foreign exchange loss (gain)	34.3		(5.5)		34.3		(16.0)
Impairment of assets 1	92.0		—		92.0		34.5
Mark-to-market (gain) on derivative instruments	(10.3)		—		(1.4)		—
Foreign exchange (gain) loss	(13.4)		5.4		20.9		(10.6)
Impairment of assets	—		—		—		34.5
Unrealized (gain) loss on derivative instruments	(2.5)		1.3		(3.9)		1.3
Write-off of previously suspended exploration well	—		—		—		26.1
Total adjustments, before taxes	2476.01		(56.5)7		32109.90		4451.63
Income tax (benefit) expense related to adjustments	(6.5)		1.4		(8.3)		(8.8)
Income tax benefit related to adjustments	(15.5)		(1.7)		(23.8)		(10.5)
Total adjustments, after taxes	17.5		(4.1)		24.6		35.8
Tax benefits on investments in foreign areas	—		(34.0)		—		(34.0)
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)	$	38.5	$	124.2	$	119.2	$	255.0
Total adjustments, after taxes	60.6		(29.0)		85.2		6.8
Net income from continuing operations per average diluted share (GAAP)	$	0.15	$	0.83	$	0.66	$	1.43
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)	$	58.1	$	110.7	$	177.3	$	365.7
Adjusted net income from continuing operations per average diluted share (Non-GAAP)	$	0.27	$	0.81	$	0.83	$	1.66
Net income (loss) from continuing operations per average diluted share (GAAP)	$	(0.02)	$	0.93	$	0.64	$	2.35
Adjusted net income from continuing operations per average diluted share (Non-GAAP)	$	0.41	$	0.74	$	1.23	$	2.40

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Other Key Performance Metrics (Continued)

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
(Millions of dollars)	2025		2024		2025		2024
Net income attributable to Murphy (GAAP) 1	$	22.3	$	127.7	$	95.3	$	217.7
Net income (loss) attributable to Murphy (GAAP) 1	$	(3.0)	$	139.1	$	92.3	$	356.8
Income tax expense	14.1		322.72		3337.89		6264.79
Interest expense, net	2524.17		21.03		4873.63		4162.03
Depreciation, depletion and amortization expense 1	~~250~~275.80		~~207~~215.37		~~438~~713.2		~~410~~625.18
EBITDA attributable to Murphy (Non-GAAP)	~~299.3~~$	300.8	~~388.7~~$	378.3	~~615.9~~$	916.7	~~731.5~~$	1,109.8
Exploration expenses	1032.35		4231.73		2457.83		87118.14
EBITDAX attributable to Murphy (Non-GAAP)	$	~~309~~333.63	$	~~431~~409.46	$	~~640~~974.70	$	~~818~~1,228.62
EBITDA attributable to Murphy (Non-GAAP)	$	~~299~~300.38	$	~~388~~378.73	$	~~615~~916.97	$	~~731~~1,109.58
Foreign exchange loss (gain)	34.3		(5.4)		34.3		(15.9)
Impairment of assets 1	92.0		—		92.0		34.5
Accretion of asset retirement obligations 1	12.9		11.7		25.4		23.1
Foreign exchange (gain) loss	(13.4)		5.4		20.9		(10.6)
Mark-to-market (gain) on derivative instruments	(10.3)		—		(1.4)		—
Accretion of asset retirement obligations 1	13.2		11.7		38.6		34.9
Impairment of assets	—		—		—		34.5
Unrealized (gain) loss on derivative instruments	(2.5)		1.3		(3.9)		1.3
Write-off of previously suspended exploration well	—		—		—		26.1
Discontinued operations (income) loss	(10.3)5		0.6		(0.72)		12.51
Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	~~334~~390.96	$	~~395~~397.63	$	~~673~~1,064.51	$	~~800~~1,198.81
Other exploration expenses 2	1032.35		4231.73		2457.83		6192.03
Adjusted EBITDAX attributable to Murphy (Non-GAAP)	$	~~345~~423.21	$	~~438~~428.36	$	~~698~~1,121.34	$	~~861~~1,290.84

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.

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Other Key Performance Metrics (Continued)

Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. ~~Adjusted FCF~~ ~~excludes certain items that management believes affect the comparability of results between periods.~~ FCF and Adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.

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

	Three Months EndedJune 30,				Six Months EndedJune 30,
			Nine Months EndedSeptember 30,
(Millions of dollars)	~~2025~~		~~2024~~		2025		2024
Net cash provided by continuing operations activities (GAAP)	$	~~358.1~~	$	~~467.7~~	$	~~658~~998.72	$	~~866~~1,295.4
Exclude: increase (decrease) in non-cash working capital	(30.7)		(25.5)		(7.9)		(1.1)
Exclude: (decrease) increase in non-cash working capital					20.5		(31.8)
Operating cash flow excluding working capital adjustments	~~327.4~~		~~442.2~~		~~650~~1,018.87		~~865~~1,263.36
Less: property additions and dry hole costs 1	~~(309.6)~~		~~(267.8)~~		(~~678~~827.0)		(~~516~~733.93)
Free cash flow (Non-GAAP)	$	~~17.8~~	$	~~174.4~~	$	~~(27~~191.2)7	$	~~348~~530.43
Less: cash dividends paid	~~(46.4)~~		~~(45.8)~~		(93139.48)		(91136.52)
Less: distributions to noncontrolling interest	~~(11.2)~~		~~(38.2)~~		(1843.2)		(6196.26)
Less: withholding tax on stock-based incentive awards	—		—		(7.7)		(25.3)
Less: acquisition of oil and natural gas properties	—		—		(124.4)		—
Adjusted free cash flow (Non-GAAP)	$	~~(39.8)~~	$	~~90.4~~	$	(~~147~~23.94)	$	~~170~~272.42

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Outlook

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 3336, lower average crude oil and higher natural gas pricing during the ~~second~~third quarter of 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on ~~August~~November 43, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the following table.

	2025	2026
WTI ($/BBL)	6561.0305	6260.8737
NYMEX ($/MMBTU)	34.3627	34.9213
AECO (US$ Equivalent/MCF)	12.4552	2.2339

In late June 2025, Shell Canada Energy announced its first cargo of liquefied natural gas (LNG) shipped from the Kitimat facility in British Columbia. Increases in export levels of Canadian liquefied natural gas would impact our natural gas-weighted Canadian business.

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. In August 2025, however, the U.S. Court of Appeals for the Federal Circuit ruled that many of the tariffs imposed under the Trump Administration exceed presidential authority and therefore are invalid, though the decision has been stayed pending U.S. Supreme Court review. This ruling introduces additional uncertainty as to the scope and durability of existing and future tariff measures. 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 and developments, 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 ~~third~~fourth quarter of 2025, production is expected to average between ~~185~~176.0 and ~~193~~184.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company’s capital expenditures for 2025 are 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, and excludes $23.0 million for the purchase of additional working interests in Eagle Ford Shale acreage primarily operated by Murphy. The ~~Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America will be drilled in the third and fourth quarters of 2025. The~~ Company remains on schedule to commence a three-well exploration program in Côte d’Ivoire in the fourth quarter of 2025., Weconsisting ~~will~~of ~~also~~the ~~begin~~Civette-1X ~~drilling~~(Block anCI-502), ~~appraisal~~Caracal-1X ~~well~~(Block atCI-102), ~~our~~and ~~recent~~Bubale-1X (Block CI-709) wells. Murphy is also continuing the drilling of the Hai Su Vang-1X2X (Golden Sea Lion), appraisal well in Block 15/2-2/17, ~~oil~~offshore ~~discovery~~Vietnam, ~~well~~with results anticipated in the ~~third~~fourth quarter,. ~~with~~The ~~results~~Cello ~~expected~~#1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America will also be drilled in the fourth quarter. Inof ~~addition~~2025. Finally, we will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with scheduled first oil anticipated in the fourth quarter of 2026.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2025 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Outlook (Continued)

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

The Company plans to utilize any surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation plan designed to allow for additional shareholder returns and debt reduction. Details of the plan can be found in the “Capital Allocation” section of the Company’s Form 8-K filed on May 7, 2025. Based on current market conditions and our planned exploration and appraisal program, the Company is currently more likely to use available adjusted Free Cash Flow for share repurchases than bond repayment.

~~Subsequent~~On ~~to the balance sheet date, on~~ July 4, 2025, the current U.S. Administration signed into law the OBBBA legislation, which includes a broad range of tax reform provisions affecting corporations. The OBBBA, among other changes, permanently reinstates the "bonus" depreciation provisions that allow for the immediate expensing of 100% of the cost of certain qualified property acquired and placed in service after January 19, 2025, permanently reinstates the elective immediate expensing of domestic research and experimental expenditures paid or incurred in tax years beginning after December 31, 2024 (with a special transition rule that allows accelerated deduction of the remaining unamortized balance of capitalized domestic research and experimental expenditures), and permanently relaxes the limitation on the deductibility of business interest effective for tax years beginning after December 31, 2024. The OBBBA also modifies certain international tax provisions effective for tax years beginning after December 31, 2025. The Company isevaluated ~~currently~~the ~~evaluating~~effects of the ~~impact~~OBBBA ofin ~~these~~accordance ~~tax~~with ~~law~~ASC ~~changes~~740, Income Taxes, and ~~will~~determined ~~recognize~~that the ~~income~~legislation ~~tax~~did ~~effects~~not inhave ~~the~~a material impact on its consolidated financial statements ~~beginning~~for in the period inended ~~which~~September ~~the~~30, ~~OBBBA~~2025. ~~was~~The ~~signed~~Company ~~into~~will ~~law~~continue to monitor any subsequent regulatory guidance related to the OBBBA.

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of ~~June~~September 30, 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 senior unsecured RCF (see Note E).

As of ~~August~~November 43, 2025, 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:

Volumes(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type 1

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

C$2.75

710/1/2025

12/31/2025

Canada

Natural Gas

Fixed price forward sales

C$3.03

1/1/2026

12/31/2026

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

Volumes(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type

Start Date

End Date

United States

Natural Gas

Fixed price derivative swap

$3.65

7/1/2025

9/30/2025

United States

Natural Gas

Fixed price derivative swap

$3.74

10/1/2025

12/31/2025

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Item 1A. Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (SEC) and on page 4750 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, foreign currency exchange rates, and interest rates. As described in Note L, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

Commodity Price Risk

There were commodity-based derivative contracts in place as of ~~June~~September 30, 2025, covering certain future U.S. natural gas sales volumes in 2025. A 10% increase in the respective benchmark price of these commodities would have ~~increased~~decreased the net ~~payable~~receivable associated with these derivative contracts by approximately $4.1.8 million, while a 10% decrease in the respective benchmark price would have ~~decreased~~increased the recorded net ~~payable~~receivable by a similar amount~~, resulting in a receivable~~.

Foreign Exchange Risk

There were no derivative foreign exchange contracts in place at ~~June~~September 30, 2025.

Interest Rate Risk

The Company’s senior unsecured RCF provides for variable interest rate borrowings. As of ~~June~~September 30, 2025, we had $~~200~~150.0 million of outstanding borrowings under the RCF. Assuming no change in the amount of borrowings outstanding under the RCF, a 10% increase in the average interest rate would have increased our quarterly interest expense by approximately $0.3 million. Actual results may vary due to changes in the amount of variable rate debt outstanding.

ITEM 4. CONTROLS AND PROCEDURES

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

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During the quarter ended ~~June~~September 30, 2025, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy and its subsidiaries are engaged in a number of legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in “Item 1A. Risk Factors” in the Company’s 2024 Form 10-K filed on February 27, 2025. The Company has not identified any additional risk factors not previously disclosed in its 2024 Form 10-K report.

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ITEM 5. OTHER INFORMATION

During the three months ended ~~June~~September 30, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 6. EXHIBITS

The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed as indicated by double asterisks (**), or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.

ExhibitNo.						Description
3.1						Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005 (incorporated by reference to Exhibit 3.1 to Form 10-K of Registrant filed on February 28, 2011)
3.2						By-Laws of Murphy Oil Corporation, as amended effective August 5, 2020 (incorporated by reference to Exhibit 3.2 to Form 10-Q of Registrant filed on August 6, 2020)
10.34						Murphy Oil Corporation 2025 Long-Term Incentive Plan (incorporated by reference to Exhibit A to definitive proxy statement on Schedule 14A of Registrant filed on March 28, 2025)
*10.35						Form of employee performance-based restricted stock unit (2025 LTI Plan)
*10.36						Form of employee time-based restricted stock unit – A (2025 LTI Plan)
*31.1						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**32.1						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101. SCH						Inline XBRL Taxonomy Extension Schema Document
101. CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
101. LAB						Inline XBRL Taxonomy Extension Labels Linkbase Document
101. PRE						Inline XBRL Taxonomy Extension Presentation Linkbase
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


			MURPHY OIL CORPORATION
			(Registrant)

			By			/s/ PAUL D. VAUGHAN
						Paul D. Vaughan
						Vice President and Controller
						(Chief Accounting Officer and Duly Authorized Officer)

~~August~~November 65, 2025

(Date)

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