MUR 10-Q Quarterly Report Sept. 30, 2025

MURPHY OIL CORP

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mur-20250930

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 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			12
Note F – Other Financial Information			12
Note G – Asset Retirement Obligations			13
Note H – Employee and Retiree Benefit Plans			13
Note I – Incentive Plans			14
Note J – Net Income (Loss) Per Common Share			16
Note K – Income Taxes			16
Note L – Financial Instruments and Risk Management			17
Note M – Accumulated Other Comprehensive Loss			20
Note N – Environmental and Other Contingencies			21
Note O – Common Stock Issued and Outstanding			22
Note P – Business Segments			23
Note Q – Leases			28


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29





Item 3. Quantitative and Qualitative Disclosures About Market Risk			49
Item 4. Controls and Procedures			49
Part II – Other Information			50
Item 1. Legal Proceedings			50
Item 1A. Risk Factors			50

Item 5. Other Information			51
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)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	425,960	$	423,569
Accounts receivable, net	283,744		272,530
Inventories	62,147		54,858
Prepaid expenses	35,629		34,322

Total current assets	807,480		785,279
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	781,291		777,536

Deferred charges and other assets	58,260		50,011

Total assets	$	9,732,762	$	9,667,479
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	918	$	871
Accounts payable	429,658		472,165
Income taxes payable	20,987		19,003
Other taxes payable	31,573		31,685
Operating lease liabilities	210,769		253,208
Other accrued liabilities	117,965		117,802
Current asset retirement obligations	45,876		48,080
Total current liabilities	857,746		942,814
Long-term debt, including finance lease obligation	1,425,235		1,274,502
Asset retirement obligations	1,001,919		960,804
Deferred credits and other liabilities	249,521		274,345
Non-current operating lease liabilities	582,082		537,381
Deferred income taxes	366,607		335,790

Total liabilities	$	4,483,110	$	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 at September 30, 2025 and 195,100,628 shares at December 31, 2024	195,101		195,101
Capital in excess of par value	850,964		848,950
Retained earnings	6,725,833		6,773,289
Accumulated other comprehensive loss	( 574,931 )		( 628,072 )
Treasury stock	( 2,075,580 )		( 1,995,018 )
Murphy Shareholders' Equity	5,121,387		5,194,250
Noncontrolling interest	128,265		147,593
Total equity	5,249,652		5,341,843
Total liabilities and equity	$	9,732,762	$	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 Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars, except per share amounts)	2025		2024		2025		2024
Revenues and other income
Revenue from production	$	720,966	$	753,169	$	2,076,761	$	2,345,282
Sales of purchased natural gas	—		—		—		3,742
Total revenue from sales to customers	720,966		753,169		2,076,761		2,349,024
Gain (loss) on derivative instruments	5,722		( 1,344 )		7,071		( 1,344 )
Gain on sale of assets and other operating income	6,297		6,506		10,434		9,834
Total revenues and other income	732,985		758,331		2,094,266		2,357,514
Costs and expenses
Lease operating expenses	184,353		222,886		604,986		716,778
Severance and ad valorem taxes	12,288		10,503		31,766		31,006
Transportation, gathering and processing	48,146		47,438		151,067		157,461
Costs of purchased natural gas	—		—		—		3,147
Exploration expenses, including undeveloped lease amortization	32,502		31,284		57,389		118,390
Selling and general expenses	30,858		24,871		98,692		78,925

Depreciation, depletion and amortization	283,465		223,632		736,949		650,309
Accretion of asset retirement obligations	14,676		13,241		43,153		39,068
Impairment of assets	115,002		—		115,002		34,528
Other operating expense	5,902		5,450		13,364		10,497
Total costs and expenses	727,192		579,305		1,852,368		1,840,109
Operating income from continuing operations	5,793		179,026		241,898		517,405
Other income (loss)
Other income (loss)	15,271		( 3,926 )		( 14,631 )		33,870
Interest expense, net	( 24,726 )		( 21,258 )		( 73,302 )		( 62,265 )
Total other loss	( 9,455 )		( 25,184 )		( 87,933 )		( 28,395 )
Income (loss) from continuing operations before income taxes	( 3,662 )		153,842		153,965		489,010
Income tax expense	4,157		2,122		37,911		64,855
Income (loss) from continuing operations	( 7,819 )		151,720		116,054		424,155
Income (loss) from discontinued operations, net of income taxes	( 497 )		( 608 )		172		( 2,123 )
Net income (loss) including noncontrolling interest	( 8,316 )		151,112		116,226		422,032
Less: Net income (loss) attributable to noncontrolling interest	( 5,343 )		12,018		23,883		65,197
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	( 2,973 )	$	139,094	$	92,343	$	356,835
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	( 0.02 )	$	0.93	$	0.64	$	2.37
Discontinued operations	—		—		—		( 0.01 )
Net income (loss)	$	( 0.02 )	$	0.93	$	0.64	$	2.36
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	( 0.02 )	$	0.93	$	0.64	$	2.35
Discontinued operations	—		—		—		( 0.01 )
Net income (loss)	$	( 0.02 )	$	0.93	$	0.64	$	2.34
Cash dividends per common share	$	0.325	$	0.300	$	0.975	$	0.900
Average common shares outstanding (thousands)
Basic	142,731		149,384		143,245		151,401
Diluted	142,731		150,353		143,976		152,437

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 Ended September 30,				Nine Months Ended September 30,
(Thousands of dollars)	2025		2024		2025		2024
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	( 38,027 )		17,764		50,528		( 34,588 )
Retirement and postretirement benefit plans	874		1,174		2,613		2,998


Other comprehensive income (loss)	( 37,153 )		18,938		53,141		( 31,590 )
Comprehensive income including noncontrolling interest	( 45,469 )		170,050		169,367		390,442
Less: Comprehensive income (loss) attributable to noncontrolling interest	( 5,343 )		12,018		23,883		65,197
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY	$	( 40,126 )	$	158,032	$	145,484	$	325,245

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)


	Nine Months Ended September 30,
(Thousands of dollars)	2025		2024
Operating Activities
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	736,949		650,309
Accretion of asset retirement obligations	43,153		39,068
Long-term non-cash compensation	28,514		30,060
Deferred income tax expense	23,305		45,136
Amortization of undeveloped leases	6,907		7,707
Unrealized (gain) loss on derivative instruments	( 3,904 )		1,344
Unsuccessful exploration well costs and previously suspended exploration costs	83		69,548

(Income) loss from discontinued operations	( 172 )		2,123




Impairment of assets	115,002		34,528
Other operating activities, net	( 47,428 )		( 38,260 )
Net decrease (increase) in non-cash working capital	( 20,473 )		31,835

Net cash provided by continuing operations activities	998,162		1,295,430
Investing Activities
Property additions and dry hole costs	( 827,007 )		( 733,289 )
Acquisition of oil and natural gas properties	( 24,405 )		—


Net cash required by investing activities	( 851,412 )		( 733,289 )
Financing Activities
Borrowings on revolving credit facility	475,000		350,000
Repayment of revolving credit facility	( 325,000 )		( 350,000 )
Retirement of debt	—		( 50,000 )


Repurchase of common stock	( 102,620 )		( 300,132 )
Cash dividends paid	( 139,799 )		( 136,208 )
Withholding tax on stock-based incentive awards	( 7,669 )		( 25,310 )
Distributions to noncontrolling interest	( 43,211 )		( 96,618 )
Finance lease obligation payments	( 543 )		( 502 )

Issue costs of revolving debt facility	( 18 )		—

Net cash required by financing activities	( 143,860 )		( 608,770 )






Effect of exchange rate changes on cash and cash equivalents	( 499 )		778
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	$	425,960	$	271,223

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 Ended September 30,				Nine Months Ended September 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 September 30, 2025 and September 30, 2024, issued 195,100,628 shares at September 30, 2025 and September 30, 2024	$	195,101	$	195,101	$	195,101	$	195,101


Capital in Excess of Par Value
Balance at beginning of period	841,833		826,861		848,950		880,297

Restricted stock transactions and other	( 241 )		( 53 )		( 27,977 )		( 70,539 )
Share-based compensation	9,372		8,847		29,991		25,897

Balance at end of period	850,964		835,655		850,964		835,655
Retained Earnings
Balance at beginning of period	6,775,193		6,672,275		6,773,289		6,546,079
Net income (loss) attributable to Murphy	( 2,973 )		139,094		92,343		356,835


Cash dividends paid	( 46,387 )		( 44,663 )		( 139,799 )		( 136,208 )
Balance at end of period	6,725,833		6,766,706		6,725,833		6,766,706
Accumulated Other Comprehensive Loss
Balance at beginning of period	( 537,778 )		( 571,645 )		( 628,072 )		( 521,117 )
Foreign currency translation, net of income taxes	( 38,027 )		17,764		50,528		( 34,588 )
Retirement and postretirement benefit plans, net of income taxes	874		1,174		2,613		2,998


Balance at end of period	( 574,931 )		( 552,707 )		( 574,931 )		( 552,707 )
Treasury Stock
Balance at beginning of period	( 2,075,823 )		( 1,798,872 )		( 1,995,018 )		( 1,737,566 )
Repurchase of common stock	—		( 196,187 )		( 100,876 )		( 302,681 )
Awarded restricted stock, net of forfeitures	243		41		20,314		45,229

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	5,121,387		5,249,737		5,121,387		5,249,737
Noncontrolling Interest
Balance at beginning of period	158,654		178,828		147,593		186,859

Net income (loss) attributable to noncontrolling interest	( 5,343 )		12,018		23,883		65,197
Distributions to noncontrolling interest owners	( 25,046 )		( 35,408 )		( 43,211 )		( 96,618 )
Balance at end of period	128,265		155,438		128,265		155,438
Total Equity	$	5,249,652	$	5,405,175	$	5,249,652	$	5,405,175

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 September 30, 2025 and December 31, 2024, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2025 and 2024, in conformity with U.S. generally accepted accounting principles (GAAP). 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 nine-month periods ended 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.

Table of Contents

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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

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


			Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of dollars)			2025			2024			2025			2024
Net crude oil and condensate revenue
United States - Onshore	$	209,051		$	161,965		$	484,610		$	450,463
United States - Offshore 1	356,903			399,940			1,052,345			1,382,071
Canada - Onshore	18,115			20,852			45,428			54,305
Canada - Offshore	35,211			80,226			155,421			178,327
Other	88			( 795 )			3,036			3,414
Total crude oil and condensate revenue	619,368			662,188			1,740,840			2,068,580

Net natural gas liquids revenue
United States - Onshore	13,736			8,134			32,117			23,281
United States - Offshore 1	8,353			9,812			25,913			29,523
Canada - Onshore	1,094			2,402			4,363			5,434
Total natural gas liquids revenue	23,183			20,348			62,393			58,238

Net natural gas revenue
United States - Onshore	9,571			4,265			25,637			11,893
United States - Offshore 1	15,741			12,311			52,408			35,700
Canada - Onshore	53,103			54,057			195,483			170,871
Total natural gas revenue	78,415			70,633			273,528			218,464

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

Sales of purchased natural gas 2



Canada - Onshore	—			—			—			3,742
Total sales of purchased natural gas	—			—			—			3,742

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

Gain (loss) on derivative instruments	5,722			( 1,344 )			7,071			( 1,344 )
Gain on sale of assets and other operating income	6,297			6,506			10,434			9,834
Total revenues and other income	$	732,985		$	758,331		$	2,094,266		$	2,357,514

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

The Company has not entered into any revenue contracts that have financing components as of 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 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 September 30, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $ 115.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2025 and 2024.


(Thousands of dollars)	2025		2024
Beginning balance at January 1	$	72,055	$	49,118
Additions pending the determination of proved reserves	43,091		28,452

Capitalized exploratory well costs charged to expense	—		( 26,471 )
Balance at September 30	$	115,146	$	51,099

Capital additions of $ 43.1 million, for the nine months ended September 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam. The Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration well in Vietnam encountered 106 feet of net oil pay from one reservoir and continues to progress post-drill evaluations. Capital additions also included long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385)

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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 $ 28.5 million, for the nine months ended September 30, 2024, were mainly for the non-operated Ocotillo #1 (Mississippi Canyon 40) exploration well in the Gulf of America and Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam.

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

The preceding table excludes well costs of $ 43.0 million incurred and expensed directly to dry hole for the nine months ended September 30, 2024. These costs primarily included $ 25.8 million for the non-operated Orange #1 (Mississippi Canyon 216) and $ 11.8 million for the Sebastian #1 (Mississippi Canyon 387) exploration wells in the Gulf of America.

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


	September 30,
	2025			2024

(Thousands of dollars)	Amount		No. of Wells		Amount		No. of Wells
Aging of capitalized well costs:
Zero to one year	$	17,562	5		$	28,552	3
One to two years	75,171		3		—		—
Two to three years	—		—		—		—
Three years or more	22,413		3		22,547		3
	$	115,146	11		$	51,099	6

Of the $ 97.6 million of exploration well costs capitalized and classified as more than one year at September 30, 2025, $ 68.2 million was in Vietnam, $ 22.1 million was in the Gulf of America, $ 4.6 million was in Canada, and $ 2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

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

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

Impairments

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt

Revolving Credit Facility

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

Debt Extinguishment

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

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


	Nine Months Ended September 30,
(Thousands of dollars)	2025		2024
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	( 7,567 )	$	80,603
(Increase) decrease in inventories	( 9,532 )		1,823
(Increase) decrease in prepaid expenses	15		( 8,131 )
Increase (decrease) in accounts payable and accrued liabilities	( 5,373 )		( 43,231 )
Increase (decrease) in income taxes payable	1,984		771
Net decrease (increase) in non-cash working capital	$	( 20,473 )	$	31,835

Supplementary disclosures:
Net cash income taxes paid	$	9,217	$	12,519
Interest paid, net of amounts capitalized of $ 5.3 million in 2025 and $ 10.8 million in 2024	52,426		48,708

Non-cash investing activities:
Asset retirement costs capitalized	$	21,756	$	19,949
(Increase) decrease in capital expenditure accrual	34,210		( 2,177 )

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note G – Asset Retirement Obligations

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

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


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

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.

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.

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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 nine-month period ended September 30, 2025, the Company made contributions of $ 26.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 4.5 million.

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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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

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

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


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 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.

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


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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

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


	Nine Months Ended September 30,
(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

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 nine-month periods ended September 30, 2025 and 2024. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2025	2024	2025	2024
Basic method	142,730,808	149,384,354	143,245,219	151,400,726
Dilutive restricted stock units 1	—	968,428	730,291	1,036,653
Diluted method	142,730,808	150,352,782	143,975,510	152,437,379

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

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


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

Note K – Income Taxes

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


	2025	2024
Three months ended September 30,	( 113.5 )%	1.4 %
Nine months ended September 30,	24.6 %	13.3 %

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

The effective tax rate for the three-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend, which resulted in an income tax benefit of $ 33.7 million.

The effective tax rate for the nine-month period ended September 30, 2025 was above the U.S. statutory tax rate of 21% primarily due to several factors including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. 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 nine-month period ended September 30, 2024 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend and no tax applied to the pretax income of the noncontrolling interest in MP GOM.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of September 30, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

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

Note L – Financial Instruments and Risk Management

Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Foreign Currency Exchange Risks

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

Commodity Price Risks

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

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

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural Gas

3.74

10/1/2025

12/31/2025

During the nine months ended September 30, 2025 and September 30, 2024, the Company did no t have any crude oil derivative contracts. At September 30, 2024, the Company had natural gas derivative contracts outstanding for 20 MMCF/d at an average price of $ 3.20 /MCF.

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


(Thousands of dollars)	Asset (Liability) Derivatives Fair Value
Type of Derivative Contract	Balance Sheet Location	September 30, 2025		December 31, 2024
Commodity swaps	Accounts receivable	$	2,197	$	—
Commodity swaps	Accounts payable	$	—	$	( 1,707 )

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


		Gain (Loss)			Gain (Loss)
(Thousands of dollars)		Three Months Ended September 30,			Nine Months Ended September 30,
Type of Derivative Contract	Statement of Operations Location		2025		2024		2025		2024
Commodity swaps	Gain (loss) on derivative instruments		$	5,722	$	( 1,344 )	$	7,071	$	( 1,344 )

Fair 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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


	September 30, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
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 of commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in the fair value of natural gas derivative contracts is recorded in “Gain (loss) on derivative instruments” in the Consolidated Statements of Operations.

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 September 30, 2025 and December 31, 2024.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2025 and December 31, 2024. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. 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.


	September 30, 2025				December 31, 2024
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,426,153	$	1,366,561	$	1,275,374	$	1,185,961

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Fair Values – Nonrecurring

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

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

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

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


	Nine Months Ended September 30, 2025
							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	$	—	$	—	$	42,397	$	157,399	$	115,002


	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 September 30, 2025, and the changes during the nine-month period ended September 30, 2025, are presented net of taxes in the following table.


(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Total
Balance at December 31, 2024	$	( 516,324 )	$	( 111,748 )	$	( 628,072 )
Components of other comprehensive income (loss):
Before reclassifications to income	50,528		—		50,528
Reclassifications to income ¹	—		2,613		2,613
Net other comprehensive income (loss)	50,528		2,613		53,141
Balance at September 30, 2025	$	( 465,796 )	$	( 109,135 )	$	( 574,931 )

1 Reclassifications before taxes of $ 3.1 million are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2025. See Note H for additional information. Related income taxes of $ 0.5 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine-month period ended September 30, 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. 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 unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

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

Note O – Common Stock Issued and Outstanding

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


( Number of shares outstanding )	September 30, 2025	September 30, 2024
Beginning of period	145,845,124	152,748,642

Restricted stock awards 1	500,146	1,103,503

Treasury shares purchased	( 3,613,450 )	( 8,008,786 )
End of period	142,731,820	145,843,359

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 September 30, 2025, the Company did no t repurchase any shares of its common stock. During the nine months ended September 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $ 100.0 million ($ 100.9 million including excise taxes and fees). As of September 30, 2025, the Company had $ 550.1 million of its common stock remaining available to repurchase under the program.

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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 )	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Three Months Ended September 30, 2025
Revenue from production	$	613.4	$	107.5	$	0.1	$	721.0	$	—	$	721.0

Gain on sales of assets and other operating income	0.3		0.5		—		0.8		11.4		12.2
Revenues from external customers	613.7		108.0		0.1		721.8		11.4		733.2
Lease operating expenses
Lease operating expenses and taxes other than income	95.6		41.2		0.4		137.2		—		137.2
Repair and maintenance	13.9		1.4		—		15.3		—		15.3
Workovers	31.8		0.1		—		31.9		—		31.9
Total lease operating expenses	141.3		42.7		0.4		184.4		—		184.4
Severance and ad valorem taxes	11.9		0.4		—		12.3		—		12.3
Transportation, gathering and processing	23.3		24.8		—		48.1		—		48.1

Selling and general expenses	1.9		5.4		2.2		9.5		21.4		30.9
Exploration Expenses
Geological and geophysical	19.1		0.1		1.1		20.3		—		20.3
Dry holes and previously suspended exploration costs	( 0.1 )		—		0.9		0.8		—		0.8
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	3.5		0.1		7.8		11.4		—		11.4
Total exploration expenses	22.5		0.2		9.8		32.5		—		32.5
Depreciation, depletion and amortization	242.1		39.3		—		281.4		2.1		283.5
Impairment of assets	115.0		—		—		115.0		—		115.0
Accretion of asset retirement obligations	11.8		2.6		0.2		14.6		0.1		14.7

Other operating expenses	5.7		0.1		0.2		6.0		( 0.1 )		5.9


Interest Income	( 0.4 )		—		—		( 0.4 )		( 2.7 )		( 3.1 )
Interest expense, net of capitalization	—		0.1		—		0.1		24.6		24.7
Income tax expense
Current income tax expense (benefit)	1.0		( 1.7 )		—		( 0.7 )		2.8		2.1
Deferred income tax expense (benefit)	7.9		( 0.2 )		( 0.4 )		7.3		( 5.2 )		2.1
Total income tax expense (benefit)	8.9		( 1.9 )		( 0.4 )		6.6		( 2.4 )		4.2
Other segment costs (income)	0.8		0.4		( 0.3 )		0.9		( 12.5 )		( 11.6 )
Segment income (loss) - including NCI 1	$	28.9	$	( 6.1 )	$	( 12.0 )	$	10.8	$	( 19.1 )	$	( 8.3 )

Additions to property, plant, equipment	$	111.6	$	26.0	$	41.1	$	178.7	$	2.3	$	181.0
Total assets at quarter-end	6,848.1		1,981.8		411.8		9,241.7		491.1		9,732.8

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)


	Exploration and Production
( Millions of dollars )	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Three Months Ended September 30, 2024
Revenue from production	$	596.5	$	157.6	$	( 0.8 )	$	753.1	$	—	$	753.1

Gain on sales of assets and other operating income	0.5		0.3		—		1.0		4.2		5.2
Revenues from external customers	597.0		157.9		( 0.8 )		754.1		4.2		758.3
Lease operating expenses
Lease operating expenses and taxes other than income	108.0		51.7		0.3		160.0		—		160.0
Repair and maintenance	15.1		1.8		—		16.9		—		16.9
Workovers	45.7		0.3		—		46.0		—		46.0
Total lease operating expenses	168.8		53.8		0.3		222.9		—		222.9
Severance and ad valorem taxes	10.1		0.3		—		10.5		—		10.5
Transportation, gathering and processing	26.3		21.2		—		47.5		—		47.5

Selling and general expenses	( 1.7 )		4.7		1.9		4.9		20.0		24.9
Exploration Expenses											—
Geological and geophysical	9.9		0.1		2.8		12.8		—		12.8
Dry holes and previously suspended exploration costs	10.8		—		0.4		11.2		—		11.2
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	2.5		0.2		4.7		7.3		—		7.3
Total exploration expenses	23.2		0.3		7.9		31.3		—		31.3
Depreciation, depletion and amortization	179.3		42.8		—		222.1		1.5		223.6
Impairment of assets	—		—		—		—		—		—
Accretion of asset retirement obligations	10.9		2.1		0.2		13.2		—		13.2



Other operating expenses	4.8		0.1		0.5		5.4		0.1		5.5
Interest income	( 0.8 )		—		—		( 0.8 )		( 3.1 )		( 3.9 )
Interest expense, net of capitalization	0.3		—		—		0.3		21.0		21.3
Income tax expense
Current income tax expense (benefit)	0.8		8.2		( 0.1 )		8.9		2.1		11.0
Deferred income tax expense (benefit)	34.4		0.2		( 34.0 )		0.6		( 9.5 )		( 8.9 )
Total income tax expense (benefit)	35.2		8.4		( 34.1 )		9.5		( 7.4 )		2.1
Other segment costs (income)	1.8		—		0.1		1.9		6.4		8.3
Segment income (loss) - including NCI 1	$	138.8	$	24.2	$	22.4	$	185.4	$	( 34.3 )	$	151.1

Additions to property, plant, equipment	$	130.2	$	13.5	$	20.5	$	164.2	$	8.0	$	172.2
Total assets at quarter-end	7,088.3		2,043.0		266.6		9,397.9		318.5		9,716.4

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)


	Exploration and Production
( Millions of dollars )	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Nine Months Ended September 30, 2025
Revenue from production	$	1,673.1	$	400.7	$	3.0	$	2,076.8	$	—	$	2,076.8

Gain on sales of assets and other operating income	3.6		1.3		—		4.9		15.0		19.9
Revenues from external customers	1,676.7		402.0		3.0		2,081.7		15.0		2,096.7
Lease operating expenses
Lease operating expenses and taxes other than income	295.9		133.1		1.6		430.6		—		430.6
Repair and maintenance	38.0		4.0		—		42.0		—		42.0
Workovers	131.5		0.9		—		132.4		—		132.4
Total lease operating expenses	465.4		138.0		1.6		605.0		—		605.0
Severance and ad valorem taxes	30.7		1.1		—		31.8		—		31.8
Transportation, gathering and processing	82.4		68.7		—		151.1		—		151.1

Selling and general expenses	8.7		17.1		6.7		32.5		66.2		98.7
Exploration Expenses
Geological and geophysical	23.0		0.1		1.6		24.7		—		24.7
Dry holes and previously suspended exploration costs	( 0.9 )		—		1.0		0.1		—		0.1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	9.8		0.2		22.6		32.6		—		32.6
Total exploration expenses	31.9		0.3		25.2		57.4		—		57.4
Depreciation, depletion and amortization	619.7		109.8		1.2		730.7		6.2		736.9
Impairment of assets	115.0		—		—		115.0		—		115.0
Accretion of asset retirement obligations	34.8		7.7		0.6		43.1		0.1		43.2

Other operating expenses	9.7		1.8		( 1.1 )		10.4		3.0		13.4


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)	2.2		12.3		0.2		14.7		( 0.1 )		14.6
Deferred income tax expense (benefit)	51.6		( 1.8 )		( 1.1 )		48.7		( 25.4 )		23.3
Total income tax expense (benefit)	53.8		10.5		( 0.9 )		63.4		( 25.5 )		37.9
Other segment cost	2.6		1.1		—		3.7		23.1		26.8
Segment income (loss) - including NCI 1	$	223.3	$	45.8	$	( 30.4 )	$	238.7	$	( 122.5 )	$	116.2

Additions to property, plant, equipment	$	586.4	$	127.0	$	94.4	$	807.8	$	9.2	$	817.0
Total assets at quarter-end	6,848.1		1,981.8		411.8		9,241.7		491.1		9,732.8

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)


	Exploration and Production
( Millions of dollars )	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Nine Months Ended September 30, 2024
Revenue from production	$	1,933.0	$	408.9	$	3.4	$	2,345.3	$	—	$	2,345.3
Sales of purchased natural gas	—		3.7		—		3.7		—		3.7
Gain on sales of assets and other operating income	3.1		1.2		—		4.3		4.2		8.5
Revenues from external customers	1,936.1		413.8		3.4		2,353.3		4.2		2,357.5
Lease operating expenses
Lease operating expenses and taxes other than income	348.6		142.1		1.0		491.7		—		491.7
Repair and maintenance	41.9		3.2		—		45.1		—		45.1
Workovers	177.2		2.8		—		180.0		—		180.0
Total lease operating expenses	567.7		148.1		1.0		716.8		—		716.8
Severance and ad valorem taxes	29.9		1.1		—		31.0		—		31.0
Transportation, gathering and processing	97.1		60.4		—		157.5		—		157.5
Costs of purchased natural gas	—		3.1		—		3.1		—		3.1
Selling and general expenses	( 5.2 )		14.2		4.9		13.9		65.0		78.9
Exploration Expenses
Geological and geophysical	13.5		0.2		8.6		22.3		—		22.3
Dry holes and previously suspended exploration costs	67.9		—		1.7		69.6		—		69.6
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	9.6		0.2		16.7		26.5		—		26.5
Total exploration expenses	91.0		0.4		27.0		118.4		—		118.4
Depreciation, depletion and amortization	528.3		114.1		0.9		643.3		7.0		650.3
Impairment of assets	34.5		—		—		34.5		—		34.5
Accretion of asset retirement obligations	32.0		6.4		0.6		39.0		0.1		39.1

Other operating expenses	8.0		2.1		0.6		10.7		( 0.2 )		10.5


Interest Income	( 21.6 )		—		—		( 21.6 )		( 8.6 )		( 30.2 )
Interest expense, net of capitalization	0.3		0.2		0.1		0.6		61.7		62.3
Income tax expense
Current income tax expense	2.9		10.5		0.2		13.6		6.2		19.8
Deferred income tax expense (benefit)	106.9		0.7		( 33.7 )		73.9		( 28.8 )		45.1
Total income tax expense (benefit)	109.8		11.2		( 33.5 )		87.5		( 22.6 )		64.9
Other segment costs (income)	5.3		—		0.3		5.6		( 7.2 )		( 1.6 )
Segment income (loss) - including NCI 1	$	459.0	$	52.5	$	1.5	$	513.0	$	( 91.0 )	$	422.0

Additions to property, plant, equipment	$	511.3	$	122.9	$	44.6	$	678.8	$	16.4	$	695.2
Total assets at quarter-end	7,088.3		2,043.0		266.6		9,397.9		318.5		9,716.4

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

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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	%

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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 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 third quarter of 2025 were as follows:

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

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

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

Murphy Oil Corporation’s net loss from continuing operations, including noncontrolling interest, for the three months ended September 30, 2025, was $7.8 million compared to net income of $151.7 million for the same period in 2024. The results for 2025 were impacted by higher impairment expense ($115.0 million), higher depreciation, depletion and amortization expenses (DD&A) ($59.8 million), and lower revenues from production ($32.2 million). These changes were partially offset by lower lease operating expenses ($38.5 million) and higher other income ($19.2 million).

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

For the three months ended September 30, 2025, total hydrocarbon production was 206,936 barrels of oil equivalent per day, an increase of 8% compared to the third quarter of 2024. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in both the U.S. 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 performance at Tupper Montney. Lower production in the Gulf of America and Canada Offshore was due to natural decline and both planned and unplanned downtime for mechanical issues.

Net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2025, was $116.1 million, a decrease of $308.1 million compared to the same period in 2024. Lower net income from continuing operations was largely driven by lower revenues from production ($268.5

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

Overview (Continued)

million), higher DD&A ($86.6 million), higher impairment expense ($80.5 million), and lower other income ($48.5 million). These changes were partially offset by lower lease operating expenses ($111.8 million), lower exploration expenses ($61.0 million), and lower income tax expenses ($26.9 million).

Lower revenues were primarily due to the lower price of oil, combined with lower production in the Gulf of America, and were partially offset by higher production in the Eagle Ford Shale, and the higher price of natural gas. Higher DD&A was due to higher production in the Eagle Ford Shale and higher rates in the Gulf of America, partially offset by lower production volumes in the Gulf of America. Higher impairment expense was related to the Dalmatian field in the Gulf or America. Lower other income was primarily the result of unrealized foreign exchange losses. Lower lease operating expenses related to lower workover costs and production handling fees in the Gulf of America, combined with lower operating costs due to the acquisition of the BW Pioneer FPSO earlier this year. Cost reduction activities in the Eagle Ford Shale also contributed to overall lower lease operating expenses. Lower exploration expenses were primarily due to no dry hole expense recorded in 2025 (2024: Sebastian #1 (Mississippi Canyon 387) operated exploration well, the Orange #1 (Mississippi Canyon 216) non-operated exploration well, and the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) in the Gulf of America). Lower dry hole costs were partially offset by higher exploration activity in Côte d'Ivoire. Lower income tax expense was due to lower net income for the period.

For the nine months ended September 30, 2025, total hydrocarbon production was 189,035 barrels of oil equivalent per day, an increase of 2% compared to the same period in 2024. Higher production in the Eagle Ford Shale was primarily the result of new wells online in the current year in Karnes and Catarina. Higher production in Canada Onshore relates to better well performance at Tupper Montney. Lower production in the Gulf of America related to planned and unplanned downtime, and was partially offset by new wells online.

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 September 30, 2025, the West Texas Intermediate (WTI) crude oil price was $62.37 per barrel, whereas the crude oil price at the end of October 2025 was $60.98, reflecting a 2% decrease in price. As of November 3, 2025 closing, the NYMEX WTI forward curve price for the remainder of 2025 was $61.05 per barrel. Reductions in commodity prices will reduce the Company’s future profits and operating cash flows.

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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 Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2025		2024		2025		2024
Exploration and production
United States	$	28.9	$	138.8	$	223.3	$	459.0
Canada	(6.1)		24.2		45.8		52.5
Other	(12.0)		22.4		(30.4)		1.5
Total exploration and production	10.8		185.4		238.7		513.0
Corporate and other	(18.6)		(33.7)		(122.7)		(88.9)
Income (loss) from continuing operations	(7.8)		151.7		116.0		424.1
Discontinued operations, net of tax 1	(0.5)		(0.6)		0.2		(2.1)
Net income (loss) including noncontrolling interest	(8.3)		151.1		116.2		422.0
Less: Net income (loss) attributable to noncontrolling interest	(5.3)		12.0		23.9		65.2
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 Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2025		2024		2025		2024
Revenues and other income
Revenue from production	$	721.0	$	753.2	$	2,076.8	$	2,345.3
Sales of purchased natural gas	—		—		—		3.7
Other income	0.8		0.9		4.9		4.3
Total revenues and other income	721.8		754.1		2,081.7		2,353.3
Costs and expenses
Lease operating expenses	184.4		222.9		605.0		716.8
Severance and ad valorem taxes	12.3		10.5		31.8		31.0
Transportation, gathering and processing	48.1		47.5		151.1		157.5
Costs of purchased natural gas	—		—		—		3.1
Depreciation, depletion and amortization	281.4		222.1		730.7		643.3
Impairment of assets	115.0		—		115.0		34.5
Accretion of asset retirement obligations	14.6		13.2		43.1		39.0
Exploration expenses, including undeveloped lease amortization	32.5		31.2		57.4		118.4
Selling and general expenses	9.5		5.0		32.5		14.0
Other	6.6		6.7		13.0		(4.7)
Results of operations before taxes	17.4		195.0		302.1		600.4
Income tax provisions	6.6		9.6		63.4		87.4
Results of operations (excluding Corporate segment) 1	$	10.8	$	185.4	$	238.7	$	513.0

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 nine-month periods ended September 30, 2025 and 2024:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Weighted average sales prices)	2025		2024		2025		2024
Crude oil and condensate – dollars per barrel
United States - Onshore	$	65.48	$	75.49	$	66.24	$	77.55
United States - Offshore 1	67.00		75.65		67.81		78.42
Canada - Onshore 2	56.33		66.18		59.46		68.62
Canada - Offshore 2	69.42		80.06		70.17		82.83
Other 2	—		—		72.97		78.20
Natural gas liquids – dollars per barrel
United States - Onshore	18.57		19.05		19.92		19.71
United States - Offshore 1	20.18		22.50		21.85		23.20
Canada - Onshore 2	26.88		34.00		32.54		34.64
Natural gas – dollars per thousand cubic feet
United States - Onshore	2.64		1.77		2.87		1.77
United States - Offshore 1	3.39		2.28		3.73		2.30
Canada - Onshore 2	1.22		1.34		1.68		1.56

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

2 U.S. dollar equivalent.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(Average price for the period)	2025		2024		2025		2024
Oil and NGLs
WTI ($/BBL)	$	64.93	$	75.10	$	66.70	$	77.54
Natural gas
NYMEX ($/MMBTU)	3.03		2.09		3.49		2.18
AECO (C$/MCF)	0.63		0.69		1.50		1.45

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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 nine-month periods ended September 30, 2025 and 2024. For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 .


	Three Months Ended September 30,		Nine Months Ended September 30,
(Barrels per day unless otherwise noted)	2025	2024	2025	2024

Net crude oil and condensate
United States - Onshore	34,703	23,320	26,797	21,199
United States - Offshore 1	56,071	59,282	56,835	64,042
Canada - Onshore	3,495	3,425	2,799	2,888
Canada - Offshore	5,518	7,880	6,658	7,219
Other	278	171	276	221
Total net crude oil and condensate	100,065	94,078	93,365	95,569
Net natural gas liquids
United States - Onshore	8,042	4,640	5,905	4,312
United States - Offshore 1	4,500	4,739	4,344	4,644
Canada - Onshore	442	768	491	572
Total net natural gas liquids	12,984	10,147	10,740	9,528
Net natural gas – thousands of cubic feet per day
United States - Onshore	39,411	26,223	32,711	24,556
United States - Offshore 1	50,477	58,747	51,528	56,565
Canada - Onshore	473,431	437,316	425,342	400,012
Total net natural gas	563,319	522,286	509,581	481,133
Total net hydrocarbons - including NCI 2,3	206,936	191,273	189,035	185,286
Noncontrolling interest
Net crude oil and condensate – barrels per day	(5,998)	(6,188)	(5,950)	(6,467)
Net natural gas liquids – barrels per day	(228)	(193)	(214)	(207)
Net natural gas – thousands of cubic feet per day	(1,963)	(1,947)	(1,715)	(2,008)
Total noncontrolling interest 2,3	(6,553)	(6,706)	(6,450)	(7,009)
Total net hydrocarbons - excluding NCI 2,3	200,383	184,567	182,585	178,277

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.

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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 nine-month periods ended September 30, 2025 and 2024. For further discussion on volumes, please see the “ Revenues from Production ” section on page 36 .


	Three Months Ended September 30,		Nine Months Ended September 30,
(Barrels per day unless otherwise noted)	2025	2024	2025	2024
Net crude oil and condensate
United States - Onshore	34,703	23,320	26,797	21,199
United States - Offshore 1	57,903	57,467	56,849	64,317
Canada - Onshore	3,495	3,425	2,799	2,888
Canada - Offshore	5,513	10,892	8,114	7,857
Other	—	—	152	159
Total net crude oil and condensate	101,614	95,104	94,711	96,420
Net natural gas liquids
United States - Onshore	8,042	4,640	5,905	4,312
United States - Offshore 1	4,500	4,739	4,344	4,644
Canada - Onshore	442	768	491	572
Total net natural gas liquids	12,984	10,147	10,740	9,528
Net natural gas – thousands of cubic feet per day
United States - Onshore	39,411	26,223	32,711	24,556
United States - Offshore 1	50,477	58,747	51,528	56,565
Canada - Onshore	473,431	437,316	425,342	400,012
Total net natural gas	563,319	522,286	509,581	481,133
Total net hydrocarbons - including NCI 2,3	208,484	192,299	190,381	186,137
Noncontrolling interest
Net crude oil and condensate – barrels per day	(6,273)	(5,920)	(5,954)	(6,503)
Net natural gas liquids – barrels per day	(228)	(193)	(214)	(207)
Net natural gas – thousands of cubic feet per day	(1,963)	(1,947)	(1,715)	(2,008)
Total noncontrolling interest 2,3	(6,828)	(6,438)	(6,454)	(7,045)
Total net hydrocarbons - excluding NCI 2,3	201,656	185,861	183,927	179,092

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.

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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 Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2025		2024		2025		2024
Revenues from production
United States - Oil	$	566.0	$	561.9	$	1,537.0	$	1,832.6
United States - Natural gas liquids	22.1		17.9		58.0		52.8
United States - Natural gas	25.3		16.6		78.0		47.6
Canada - Oil	53.3		101.1		200.9		232.6
Canada - Natural gas liquids	1.1		2.4		4.4		5.4
Canada - Natural gas	53.1		54.1		195.5		170.9
Other - Oil	0.1		(0.8)		3.0		3.4
Total revenue from production	$	721.0	$	753.2	$	2,076.8	$	2,345.3

Revenues from production for the three months ended September 30, 2025, decreased by $32.2 million compared to the same period in 2024. Revenues decreased primarily due to lower crude oil prices, reduced oil production in the Gulf of America from downtime relating to planned maintenance and ongoing workovers, and downtime in offshore Canada at Terra Nova and Hibernia related to well issues in the quarter. These reductions were partially offset by higher production at Karnes and Catarina in the Eagle Ford Shale related to better well performance and new wells online, and higher sales volumes at Cascade & Chinook in the Gulf of America.

Revenues from production for the nine months ended September 30, 2025, decreased $268.5 million compared to the same period in 2024. Lower revenues were primarily driven by lower crude oil prices, as well as decreased production in the Gulf of America due to well issues at Samurai, natural decline of new wells, and downtime for maintenance at Khaleesi. These decreases were partially offset by increased production in Eagle Ford Shale due to new wells at Karnes and Catarina, as well as in the Gulf of America at Mormont and Neidermeyer.

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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 Ended September 30,								Nine Months Ended September 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	$	31.9	$	32.9	$	7.04	$	11.03	$	91.2	$	105.4	$	8.75	$	13.00
United States - Offshore	109.4		136.0		16.79		20.54		374.2		462.3		19.64		21.52
Canada - Onshore	30.0		35.2		3.94		4.96		95.8		101.4		4.73		5.28
Canada - Offshore	12.7		18.5		24.96		18.51		42.2		46.7		19.05		21.67
Other	0.4		0.3		—		—		1.6		1.0		37.54		23.66
Total lease operating expenses	$	184.4	$	222.9	$	9.61	$	12.60	$	605.0	$	716.8	$	11.64	$	14.05
Transportation, gathering and processing
United States - Onshore	$	3.2	$	2.2	$	0.72	$	0.73	$	7.8	$	7.3	$	0.75	$	0.89
United States - Offshore	20.1		24.1		3.08		3.64		74.6		89.8		3.91		4.18
Canada - Onshore	23.0		20.1		3.02		2.84		63.3		56.9		3.13		2.96
Canada - Offshore	1.8		1.1		3.49		1.06		5.4		3.5		2.42		1.63

Total transportation, gathering and processing	$	48.1	$	47.5	$	2.51	$	2.68	$	151.1	$	157.5	$	2.91	$	3.09

For the three months ended September 30, 2025, lease operating expenses decreased by $38.5 million and transportation, gathering and processing expenses increased by $0.6 million compared to the same period in 2024. In the Gulf of America, decreases in lease operating expenses primarily related to lower production volumes and handling fees and lower operating charges as a result of the acquisition of the BW Pioneer FPSO. In addition, current quarter workover costs at Marmalard, Khaleesi and Samurai were lower than expenditures at Neidermeyer and Dalmatian in the prior year. In the Eagle Ford Shale, lower operating expenses were due to cost-savings initiatives including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimization throughout the year, and were largely offset by higher production.

For the nine months ended September 30, 2025, lease operating expenses decreased by $111.8 million, and transportation, gathering and processing expenses decreased by $6.4 million compared to the same period in 2024. In the Gulf of America, decreases primarily related to lower workover costs due to expenditures at Neidermeyer and Dalmatian in the prior year, which were partially offset by current year workovers at Marmalard, Khaleesi and Samurai. Lower operating charges also occured as a result of the acquisition of the BW Pioneer FPSO earlier in the year. In the Eagle Ford Shale, lower operating costs resulted from cost-savings initiatives, including workforce reductions at the end of 2024, lower repairs and maintenance, and equipment optimizations, were partially offset by higher volume related costs.

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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 Ended September 30,								Nine Months Ended September 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	$	137.5	$	88.0	$	30.30	$	29.60	$	311.9	$	237.2	$	29.95	$	29.25
United States - Offshore	104.6		91.3		16.06		13.78		307.8		291.1		16.16		13.55
Canada - Onshore	33.5		34.5		4.38		4.87		87.6		93.5		4.32		4.87
Canada - Offshore	5.8		8.3		11.53		8.27		22.2		20.6		10.03		9.58
Other	—		—		—		—		1.2		0.9		31.66		20.82
Total DD&A	$	281.4	$	222.1	$	14.67	$	12.56	$	730.7	$	643.3	$	14.06	$	12.61

DD&A for the three months ended September 30, 2025 increased by $59.3 million compared to the same period in 2024. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

DD&A for the nine months ended September 30, 2025 increased by $87.4 million. The increase was primarily due to higher sales volumes in the Eagle Ford Shale and higher rates at U.S. Offshore, partially offset by lower production in the Gulf of America.

Impairment of Assets

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

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

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2025		2024		2025		2024
Exploration expenses
Dry holes and previously suspended exploration costs	$	0.8	$	11.2	$	0.1	$	69.5
Geological and geophysical	20.3		12.7		24.7		22.3
Other exploration	8.5		5.4		25.8		18.9
Undeveloped lease amortization	2.9		1.9		6.8		7.7
Total exploration expenses, including undeveloped lease amortization	$	32.5	$	31.2	$	57.4	$	118.4

Exploration expenses for the three months ended September 30, 2025 increased by $1.3 million compared to the same period in 2024 due to higher geological and geophysical costs in the Gulf of America, and were partially offset by lower dry hole costs in the current period. Dry hole costs in 2024 related to the Sebastian #1 (Mississippi Canyon 387) operated exploration well in the Gulf of America that encountered non-commercial hydrocarbons.

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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 the previously suspended exploration well at Hoffe Park #1 (Mississippi Canyon 166) 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 nine months ended September 30, 2025 decreased by $3.0 million and $24.0 million, respectively, compared to the same periods in 2024. Lower income tax for each period is primarily the result of lower net income.

Corporate

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

For the three months ended September 30, 2025, the Corporate segment reported a loss of $18.6 million, a favorable variance of $15.1 million, compared to the same period in 2024. The favorable variance was primarily due to a foreign exchange gain ($18.4 million) for the period, primarily relating to our Canadian subsidiary, combined with gains on derivative instruments ($3.9 million), and partially offset by higher income tax expense of $5.1 million.

The Corporate segment reported a loss of $122.7 million for the nine months ended September 30, 2025, an unfavorable variance of $33.8 million, compared to the same period in 2024. The unfavorable variance was primarily due to higher foreign exchange losses ($31.5 million) and higher interest expense ($11.4 million) due to the timing of interest payments on long-term debt, and was partially offset by gains on derivative instruments ($8.4 million) due to fixed price sales contracts.

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 twelve months and the foreseeable future.

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

Financial Condition (Continued)

Cash 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 nine months ended September 30, 2025 was $118.1 million higher compared to the same period in 2024. The increase was primarily due to a gross payment of $125.0 million for the purchase of an FPSO in the Gulf of America and higher development drilling at Eagle Ford Shale, partially offset by lower development drilling at Gulf of America.

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


	Nine Months Ended September 30,
(Millions of dollars)	2025		2024
Property additions and dry hole costs per the cash flow statements	$	827.0	$	733.3

Acquisition of oil properties per the cash flow statements	24.4		—
Geophysical and other exploration expenses	46.8		35.5
Capital expenditure accrual changes and other	(30.6)		7.8
Total capital expenditures	$	867.6	$	776.6

Total accrual basis capital expenditures are shown below.


	Nine Months Ended September 30,
(Millions of dollars)	2025		2024
Capital Expenditures
Exploration and production	$	858.4	$	760.2
Corporate	9.2		16.4
Total capital expenditures	$	867.6	$	776.6

Higher capital expenditures in the nine months ended September 30, 2025 compared to the same period of 2024 were primarily attributable to the FPSO purchase in the Gulf of America and higher development drilling in the Eagle Ford Shale related to new wells online. Also contributing to the increase were higher exploratory drilling and field development in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower exploration costs and development drilling

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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 nine months ended September 30, 2025 decreased by $464.9 million compared to the same period in 2024.

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

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

Liquidity

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

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

Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $67.4 million, the majority of which was held in Canada ($28.9 million), Mexico ($8.0 million), the U.K. ($7.4 million) and Vietnam ($6.7 million). 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)	September 30, 2025		December 31, 2024
Working capital
Total current assets	$	807.5	$	785.3
Total current liabilities	857.7		942.8
Net working capital liability	$	(50.2)	$	(157.5)

As of September 30, 2025, net working capital increased by $107.3 million compared to December 31, 2024. The increase was primarily attributable to lower current operating lease obligations ($42.4 million), lower accounts payable ($42.5 million), and higher accounts receivable ($11.2 million).

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

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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 September 30, 2025 and December 31, 2024 follows.


	September 30, 2025				December 31, 2024
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,425.2	21.8	%	$	1,274.5	19.7	%
Murphy shareholders' equity	5,121.4		78.2	%	5,194.3		80.3	%
Total capital employed	$	6,546.6	100.0	%	$	6,468.8	100.0	%

At September 30, 2025, long-term debt of $1,425.2 million increased by $150.7 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF. The total of the fixed-rate notes had a weighted average maturity of 8.6 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $72.9 million in 2025, primarily due to dividends ($139.8 million) and shares repurchased ($100.9 million), including excise tax, partially offset by net income ($92.3 million), foreign currency translation ($50.5 million), and awarded restricted stock ($20.3 million). A summary of transactions in stockholders’ equity accounts is presented in the “ Consolidated Statements of Stockholders’ Equity ” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of 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 Ended September 30,				Nine Months Ended September 30,
(Millions of dollars, except per share amounts)	2025		2024		2025		2024
Net income (loss) attributable to Murphy (GAAP) 1	$	(3.0)	$	139.1	$	92.3	$	356.8
Discontinued operations (income) loss	0.5		0.6		(0.2)		2.1
Net income (loss) from continuing operations attributable to Murphy	(2.5)		139.7		92.1		358.9
Adjustments:
Impairment of assets 1	92.0		—		92.0		34.5
Foreign exchange (gain) loss	(13.4)		5.4		20.9		(10.6)
Unrealized (gain) loss on derivative instruments	(2.5)		1.3		(3.9)		1.3
Write-off of previously suspended exploration well	—		—		—		26.1















Total adjustments, before taxes	76.1		6.7		109.0		51.3
Income tax benefit related to adjustments	(15.5)		(1.7)		(23.8)		(10.5)
Tax benefits on investments in foreign areas	—		(34.0)		—		(34.0)
Total adjustments, after taxes	60.6		(29.0)		85.2		6.8
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)	$	58.1	$	110.7	$	177.3	$	365.7

Net income (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 Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2025		2024		2025		2024
Net income (loss) attributable to Murphy (GAAP) 1	$	(3.0)	$	139.1	$	92.3	$	356.8
Income tax expense	4.1		2.2		37.9		64.9
Interest expense, net	24.7		21.3		73.3		62.3
Depreciation, depletion and amortization expense 1	275.0		215.7		713.2		625.8
EBITDA attributable to Murphy (Non-GAAP)	$	300.8	$	378.3	$	916.7	$	1,109.8
Exploration expenses	32.5		31.3		57.3		118.4
EBITDAX attributable to Murphy (Non-GAAP)	$	333.3	$	409.6	$	974.0	$	1,228.2

EBITDA attributable to Murphy (Non-GAAP)	$	300.8	$	378.3	$	916.7	$	1,109.8
Impairment of assets 1	92.0		—		92.0		34.5
Foreign exchange (gain) loss	(13.4)		5.4		20.9		(10.6)
Accretion of asset retirement obligations 1	13.2		11.7		38.6		34.9
Unrealized (gain) loss on derivative instruments	(2.5)		1.3		(3.9)		1.3
Write-off of previously suspended exploration well	—		—		—		26.1


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






Adjusted EBITDA attributable to Murphy (Non-GAAP)	$	390.6	$	397.3	$	1,064.1	$	1,198.1
Other exploration expenses 2	32.5		31.3		57.3		92.3
Adjusted EBITDAX attributable to Murphy (Non-GAAP)	$	423.1	$	428.6	$	1,121.4	$	1,290.4

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

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. 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.


	Nine Months Ended September 30,
(Millions of dollars)		2025		2024
Net cash provided by continuing operations activities (GAAP)		$	998.2	$	1,295.4
Exclude: (decrease) increase in non-cash working capital		20.5		(31.8)
Operating cash flow excluding working capital adjustments		1,018.7		1,263.6
Less: property additions and dry hole costs 1		(827.0)		(733.3)
Free cash flow (Non-GAAP)		$	191.7	$	530.3
Less: cash dividends paid		(139.8)		(136.2)
Less: distributions to noncontrolling interest		(43.2)		(96.6)

Less: withholding tax on stock-based incentive awards		(7.7)		(25.3)
Less: acquisition of oil and natural gas properties		(24.4)		—
Adjusted free cash flow (Non-GAAP)		$	(23.4)	$	272.2

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

As of close on November 3, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the following table.



	2025	2026
WTI ($/BBL)	61.05	60.37
NYMEX ($/MMBTU)	4.27	4.13
AECO (US$ Equivalent/MCF)	2.52	2.39

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 fourth quarter of 2025, production is expected to average between 176.0 and 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 Company remains on schedule to commence a three-well exploration program in Côte d’Ivoire in the fourth quarter of 2025, consisting of the Civette-1X (Block CI-502), Caracal-1X (Block CI-102), and Bubale-1X (Block CI-709) wells. Murphy is also continuing the drilling of the Hai Su Vang-2X (Golden Sea Lion) appraisal well in Block 15-2/17, offshore Vietnam, with results anticipated in the fourth quarter. The Cello #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 of 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/

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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.

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

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 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 November 3, 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

10/1/2025

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

$3.74

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 50 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 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 decreased the net receivable associated with these derivative contracts by approximately $1.8 million, while a 10% decrease in the respective benchmark price would have increased the recorded net receivable by a similar amount.

Foreign Exchange Risk

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

Interest Rate Risk

The Company’s senior unsecured RCF provides for variable interest rate borrowings. As of September 30, 2025, we had $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 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 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.


Exhibit No.						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 )
*10.35						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)

November 5, 2025

(Date)

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Part I Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations (continued)Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 5. Other Information Item 6. Exhibits

Exhibits

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) *10.35 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

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MUR 10-Q Quarter ended Sept. 30, 2025

Exhibits