Murphy Oil - 10-Q quarterly report FY2026 Q3

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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, 2026


☐			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, 2026 was 143,381,125.

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 (Loss)			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			13
Note G – Asset Retirement Obligations			14
Note H – Employee and Retiree Benefit Plans			14
Note I – Incentive Plans			15
Note J – Net Income Per Common Share			17
Note K – Income Taxes			17
Note L – Financial Instruments and Risk Management			18
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, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	500,301	$	377,196
Accounts receivable, net	459,254		346,759
Inventories	63,965		57,284
Prepaid expenses	41,592		35,473

Total current assets	1,065,112		816,712
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $15,736,096 in 2026 and $15,068,149 in 2025	8,711,907		8,136,346
Operating lease assets	643,138		805,464

Deferred charges and other assets	61,209		74,104

Total assets	$	10,481,366	$	9,832,626
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	11,229	$	2,514
Accounts payable	622,800		572,183

Income taxes payable	20,676		18,209
Other taxes payable	38,744		28,295
Operating lease liabilities	229,478		278,834
Other accrued liabilities	152,510		120,755
Current asset retirement obligations	46,866		41,959

Total current liabilities	1,122,303		1,062,749
Long-term debt, including finance lease obligation	1,623,123		1,382,566
Asset retirement obligations	1,018,528		970,908
Deferred credits and other liabilities	232,690		263,596
Non-current operating lease liabilities	424,278		537,773
Deferred income taxes	506,931		378,337

Total liabilities	$	4,927,853	$	4,595,929
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, 2026 and 195,100,628 shares at December 31, 2025	195,101		195,101
Capital in excess of par value	851,582		859,633
Retained earnings	6,997,071		6,691,318
Accumulated other comprehensive loss	(609,025)		(554,227)
Treasury stock	(2,049,806)		(2,073,445)
Murphy Shareholders' Equity	5,384,923		5,118,380
Noncontrolling interest	168,590		118,317
Total equity	5,553,513		5,236,697
Total liabilities and equity	$	10,481,366	$	9,832,626

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)	2026		2025		2026		2025
Revenues and other income
Revenue from production	$	849,175	$	720,966	$	2,507,861	$	2,076,761


Gain on derivative instruments	—		5,722		—		7,071
Gain on sale of assets and other operating income	5,799		6,297		8,972		10,434
Total revenues and other income	854,974		732,985		2,516,833		2,094,266
Costs and expenses
Lease operating expenses	149,174		184,353		436,357		604,986
Severance and ad valorem taxes	13,561		12,288		42,298		31,766
Transportation, gathering and processing	47,045		48,146		139,380		151,067

Exploration expenses, including undeveloped lease amortization	33,111		32,502		155,229		57,389
Selling and general expenses	40,537		30,858		114,077		98,692

Depreciation, depletion and amortization	271,432		283,465		787,914		736,949
Accretion of asset retirement obligations	15,056		14,676		44,440		43,153
Impairment of assets	—		115,002		—		115,002
Other operating expense	28,574		5,902		47,721		13,364
Total costs and expenses	598,490		727,192		1,767,416		1,852,368
Operating income from continuing operations	256,484		5,793		749,417		241,898
Other income (loss)
Other income (loss)	2,863		15,271		23,962		(14,631)
Interest expense, net	(24,199)		(24,726)		(78,093)		(73,302)
Total other loss	(21,336)		(9,455)		(54,131)		(87,933)
Income (loss) from continuing operations before income taxes	235,148		(3,662)		695,286		153,965
Income tax expense	39,355		4,157		166,330		37,911
Income (loss) from continuing operations	195,793		(7,819)		528,956		116,054
Income (loss) from discontinued operations, net of income taxes	(259)		(497)		(1,238)		172
Net income (loss) including noncontrolling interest	195,534		(8,316)		527,718		116,226
Less: Net income (loss) attributable to noncontrolling interest	24,414		(5,343)		71,437		23,883
NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	171,120	$	(2,973)	$	456,281	$	92,343
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	1.19	$	(0.02)	$	3.19	$	0.64
Discontinued operations	—		—		(0.01)		—
Net income (loss)	$	1.19	$	(0.02)	$	3.18	$	0.64
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	1.17	$	(0.02)	$	3.14	$	0.64
Discontinued operations	—		—		(0.01)		—
Net income (loss)	$	1.17	$	(0.02)	$	3.13	$	0.64
Cash dividends per common share	$	0.350	$	0.325	$	1.050	$	0.975
Average common shares outstanding (thousands)
Basic	143,377		142,731		143,270		143,245
Diluted	146,123		142,731		145,970		143,976

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

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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)	2026		2025		2026		2025
Net income (loss) including noncontrolling interest	$	195,534	$	(8,316)	$	527,718	$	116,226
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	(4,360)		(38,027)		(59,001)		50,528
Retirement and postretirement benefit plans	1,401		874		4,203		2,613


Other comprehensive income (loss)	(2,959)		(37,153)		(54,798)		53,141
Comprehensive income (loss) including noncontrolling interest	192,575		(45,469)		472,920		169,367
Less: Comprehensive income (loss) attributable to noncontrolling interest	24,414		(5,343)		71,437		23,883
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY	$	168,161	$	(40,126)	$	401,483	$	145,484

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

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine Months Ended September 30,
(Thousands of dollars)	2026		2025
Operating Activities
Net income including noncontrolling interest	$	527,718	$	116,226
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	787,914		736,949
Deferred income tax expense	135,277		23,305
Unsuccessful exploration well costs and previously suspended exploration costs	86,699		83
Accretion of asset retirement obligations	44,440		43,153
Long-term non-cash compensation	40,858		28,514
Amortization of undeveloped leases	7,254		6,907
(Income) loss from discontinued operations	1,238		(172)
Unrealized gain on derivative instruments	—		(3,904)





Impairment of assets	—		115,002
Net increase in non-cash working capital	(15,021)		(20,473)
Other operating activities, net	(98,768)		(47,428)

Net cash provided by continuing operations activities	1,517,609		998,162
Investing Activities
Property additions and dry hole costs	(1,333,039)		(827,007)
Acquisition of oil and natural gas properties	(28,647)		(24,405)


Net cash required by investing activities	(1,361,686)		(851,412)
Financing Activities
Retirement of debt	(227,489)		—
Early redemption of debt cost	(2,504)		—
Debt issuance	500,000		—
Debt issuance cost	(8,254)		—
Borrowings on revolving credit facility	700,000		475,000
Repayment of revolving credit facility	(800,000)		(325,000)
Issue costs of revolving credit facility	(12,274)		(18)
Repurchase of common stock, including excise tax	(777)		(102,620)
Cash dividends paid	(150,528)		(139,799)
Distributions to noncontrolling interest	(21,164)		(43,211)
Withholding tax on stock-based incentive awards	(8,496)		(7,669)
Finance lease obligation payments	(1,348)		(543)


Net cash required by financing activities	(32,834)		(143,860)






Effect of exchange rate changes on cash and cash equivalents	16		(499)
Net increase in cash and cash equivalents	123,105		2,391
Cash and cash equivalents at beginning of period	377,196		423,569
Cash and cash equivalents at end of period	$	500,301	$	425,960

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

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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)	2026		2025		2026		2025

Common Stock
Balance at beginning and end of period – par $1.00, authorized 450,000,000 shares at September 30, 2026 and September 30, 2025, issued 195,100,628 shares at September 30, 2026 and September 30, 2025	$	195,101	$	195,101	$	195,101	$	195,101


Capital in Excess of Par Value
Balance at beginning of period	844,653		841,833		859,633		848,950

Restricted stock transactions and other	(1,650)		(241)		(32,117)		(27,977)
Share-based compensation	8,579		9,372		24,066		29,991

Balance at end of period	851,582		850,964		851,582		850,964
Retained Earnings
Balance at beginning of period	6,876,135		6,775,193		6,691,318		6,773,289
Net income attributable to Murphy	171,120		(2,973)		456,281		92,343


Cash dividends paid	(50,184)		(46,387)		(150,528)		(139,799)
Balance at end of period	6,997,071		6,725,833		6,997,071		6,725,833
Accumulated Other Comprehensive Loss
Balance at beginning of period	(606,066)		(537,778)		(554,227)		(628,072)
Foreign currency translation, net of income taxes	(4,360)		(38,027)		(59,001)		50,528
Retirement and postretirement benefit plans, net of income taxes	1,401		874		4,203		2,613


Balance at end of period	(609,025)		(574,931)		(609,025)		(574,931)
Treasury Stock
Balance at beginning of period	(2,050,809)		(2,075,823)		(2,073,445)		(1,995,018)
Repurchase of common stock	—		—		—		(100,876)
Awarded restricted stock, net of forfeitures	1,003		243		23,639		20,314

Balance at end of period – 51,719,503 shares of common stock at September 30, 2026 and 52,368,808 shares of common stock at September 30, 2025, at cost	(2,049,806)		(2,075,580)		(2,049,806)		(2,075,580)
Murphy Shareholders’ Equity	5,384,923		5,121,387		5,384,923		5,121,387
Noncontrolling Interest
Balance at beginning of period	144,176		158,654		118,317		147,593

Net income attributable to noncontrolling interest	24,414		(5,343)		71,437		23,883
Distributions to noncontrolling interest owners	—		(25,046)		(21,164)		(43,211)
Balance at end of period	168,590		128,265		168,590		128,265
Total Equity	$	5,553,513	$	5,249,652	$	5,553,513	$	5,249,652

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

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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, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2026 and 2025, in conformity with the United States 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 2025 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three and nine months ended September 30, 2026 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Income Tax Disclosures. In December 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. The Company adopted this standard in the fourth quarter of 2025. Interim period disclosures are largely unaffected by this update. The adoption did not affect the calculation of income tax expense.

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 are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impact on our results of operations, cash flows and financial condition.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

Disaggregation of Revenue

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

The Company’s revenues and other income for the three and nine months ended September 30, 2026 and 2025 were as follows.


			Three Months Ended September 30,						Nine Months Ended September 30,
(Thousands of dollars)			2026			2025			2026			2025
Net crude oil and condensate revenue
United States - Onshore	$	239,940		$	209,051		$	671,559		$	484,610
United States - Offshore 1	393,507			356,903			1,182,280			1,052,345
Canada - Onshore	28,136			18,115			82,669			45,428
Canada - Offshore	69,432			35,211			219,198			155,421
Other	—			88			2,909			3,036
Total crude oil and condensate revenue	731,015			619,368			2,158,615			1,740,840
Net natural gas liquids revenue
United States - Onshore	16,658			13,736			40,153			32,117
United States - Offshore 1	7,515			8,353			21,714			25,913
Canada - Onshore	1,681			1,094			4,785			4,363
Total natural gas liquids revenue	25,854			23,183			66,652			62,393
Net natural gas revenue
United States - Onshore	8,153			9,571			26,494			25,637
United States - Offshore 1	14,410			15,741			55,674			52,408
Canada - Onshore	69,743			53,103			200,426			195,483
Total natural gas revenue	92,306			78,415			282,594			273,528







Total revenue from sales to customers	849,175			720,966			2,507,861			2,076,761
Gain on derivative instruments	—			5,722			—			7,071
Gain on sale of assets and other operating income	5,799			6,297			8,972			10,434
Total revenues and other income	$	854,974		$	732,985		$	2,516,833		$	2,094,266

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

Contract Balances and Asset Recognition

As of September 30, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $245.9 million and $165.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as of September 30, 2026.

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

Performance Obligations

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,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

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

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

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Natural Gas and NGLs

Q1 2031

Deliveries from dedicated acreage in Eagle Ford Shale

As produced

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at USD index pricing

30 MMCF/D

Canada

Natural Gas

Q4 2028

Contracts to sell natural gas at USD index pricing

20 MMCF/D

Canada

Natural Gas

Q4 2029

Contracts to sell natural gas at USD index pricing

25 MMCF/D

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at CAD fixed pricing

50 MMCF/D

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at CAD fixed pricing

9 MMCF/D

Canada

NGLs

Q4 2026

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, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $494.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine months ended September 30, 2026 and 2025.


(Thousands of dollars)	2026		2025
Beginning balance at January 1	$	191,821	$	72,055
Additions pending the determination of proved reserves	317,581		43,091
Reclassifications to proved properties based on the determination of proved reserves	(4,646)		—
Capitalized exploratory well costs charged to expense	(10,627)		—
Balance at September 30	$	494,129	$	115,146

Capital additions of $317.6 million, for the nine months ended September 30, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) and Bubale West-1X (Block CI-103) wells in Côte d’Ivoire; the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 and Lac Da Trang (White Camel) North-1X, Block 15-1/05 wells in Vietnam; and the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America.

In the third quarter of 2026, Murphy successfully appraised the Bubale discovery offshore Côte d’Ivoire with the Bubale West-1X well, which encountered approximately 88 feet of net oil pay in the Turonian reservoir and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

additional hydrocarbons in the deeper Albian reservoir. The Company also announced an oil discovery at the Lac Da Trang (White Camel) North-1X exploration well offshore Vietnam, encountering approximately 131 feet of net oil pay. Murphy also achieved first oil from the Lac Da Vang (Golden Camel) development offshore Vietnam.

In the second quarter of 2026, Murphy announced a discovery at the Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire, with the well encountering 100 feet of net pay across two reservoirs. In addition, Murphy concluded the Hai Su Vang (Golden Sea Lion) appraisal program for Hai Su Vang-2X (Block 15-2/17), Hai Su Vang-3X (Block 15-1/05) and Hai Su Vang-4X (Block 15-2/17) appraisal wells in Vietnam.

In the first quarter of 2026, Murphy announced the successful discoveries of the Banjo #1 and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, which encountered 50 feet and 30 feet of net pay, respectively. In addition, the Company announced a successful appraisal well Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, in the Cuu Long Basin, located approximately 40 miles offshore of Vietnam.

Capital additions of $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 and long-lead equipment for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America.

Capitalized well costs charged to dry hole expense of $10.6 million, for the nine months ended September 30, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. There were no capitalized well costs charged to dry hole expense for the nine months ended September 30, 2025.

The preceding table excludes well costs of $76.1 million incurred and expensed directly to dry hole for the nine months ended September 30, 2026. In 2026, these costs primarily related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion), Block 15-2/17 appraisal well in Vietnam. There were no capitalized well costs charged to dry hole expense for the nine months ended September 30, 2025.

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


	September 30,
	2026		2025

(Thousands of dollars)	Amount		No. of Projects	Amount		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	10,571	1	$	17,562	5
One to two years	344,780		3	75,171		3
Two to three years	120,946		3	—		—
Three years or more	17,832		2	22,413		3
	$	494,129	9	$	115,146	11

Of the $483.6 million of exploration well costs capitalized and classified as more than one year at September 30, 2026, $261.4 million was in Côte d’Ivoire, $114.0 million was in Vietnam, $105.5 million was in the Gulf of America, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

During the third quarter of 2025, the Company purchased additional working interest in the 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. The Pioneer FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a five-year contract that began in 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

Impairments

There were no impairments in the three and nine months ended September 30, 2026. 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.

Note E – Financing Arrangements and Debt

Long-term debt for the respective periods presented consisted of the following.


	September 30,		December 31,
(Thousands of dollars)	2026		2025
Notes payable
5.875% notes, due December 2027	$	—	$	78,899
6.375% notes, due July 2028	—		148,590
7.050% notes, due May 2029	117,582		117,582
6.000% notes, due October 2032	600,000		600,000
6.500% notes, due February 2034	500,000		—
6.375% notes, due December 2042 ¹	339,761		339,761
Total notes payable	1,557,343		1,284,832
Unamortized debt issuance cost and discount on notes payable	(17,712)		(12,406)
Total notes payable, net of unamortized discount	1,539,631		1,272,426
Finance lease obligations, due through October 2039 ²	94,721		12,654
Total debt including current maturities	1,634,352		1,285,080
Senior unsecured revolving credit facility	—		100,000
Current maturities	(11,229)		(2,514)
Total long-term debt	$	1,623,123	$	1,382,566

1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.

2 Includes finance lease liabilities of $83.9 million at September 30, 2026 for a floating storage and offloading vessel (FSO) in Vietnam. See Note Q - Leases for additional information.

Revolving Credit Facility

In the first quarter of 2026, the Company entered into an amended credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. All terms of the Amended RCF are substantially similar to the previous senior unsecured guaranteed revolving credit facility (RCF) credit agreement, with an exception for the following: The “Adjusted Term Secured Overnight Financing Rate (SOFR)” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero. The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF.

At September 30, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At September 30, 2026, the interest rate in effect on borrowings under the Amended RCF was 6.16%. At September 30, 2026, the Company was in compliance with all covenants related to the Amended RCF.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2027.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note E – Financing Arrangements and Debt (Continued)

Debt Offering

In the first quarter of 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.50% per annum and mature on February 15, 2034. The Company has incurred transaction costs of $8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes.

Debt Extinguishment

In the first quarter of 2026, the Company redeemed the remaining $78.9 million principal amount outstanding of its 5.875% senior notes due 2027 (2027 Notes) and the remaining $148.6 million principal amount outstanding of its 6.375% senior notes due 2028 (2028 Notes), for an aggregate $227.5 million. The total cost of the debt extinguishment of $3.5 million consisted of cash costs of $2.5 million and non-cash costs of $1.0 million.

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows


	Nine Months Ended September 30,
(Thousands of dollars)	2026		2025
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(87,904)	$	(7,567)
(Increase) decrease in inventories	(4,648)		(9,532)
(Increase) decrease in prepaid expenses	(7,666)		15
Increase (decrease) in accounts payable and accrued liabilities	82,730		(5,373)
Increase (decrease) in income taxes payable	2,467		1,984
Net (increase) decrease in non-cash working capital	$	(15,021)	$	(20,473)

Supplementary disclosures:
Interest paid, net of amounts capitalized of $15.7 million in 2026 and $5.3 million in 2025	$	50,612	$	52,426

Non-cash investing activities:
Asset retirement costs capitalized	$	40,491	$	21,756
(Increase) decrease in capital expenditure accrual	(1,920)		(34,210)

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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 months ended September 30, 2026 and 2025 are shown in the following table.


(Thousands of dollars)	September 30, 2026		September 30, 2025
Balance at beginning of year	$	1,012,867	$	1,008,884
Accretion	44,440		43,153
Liabilities incurred	46,829		14,267

Revisions of previous estimates	—		7,489
Liabilities settled	(32,562)		(32,145)



Changes due to translation of foreign currencies	(6,180)		6,147
Balance at end of period	1,065,394		1,047,795
Current portion of liability	(46,866)		(45,876)
Non-current portion of liability	$	1,018,528	$	1,001,919

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 and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2026		2025		2026		2025
Service cost	$	1,865	$	1,683	$	102	$	84
Interest cost	7,744		8,495		750		708
Expected return on plan assets	(8,786)		(8,967)		—		—
Estimated defined contribution provision	69		62		—		—
Amortization of prior service cost (credit)	432		492		(133)		(133)
Recognized actuarial (gain) loss	1,643		1,918		(386)		(1,057)



Total net periodic benefit cost (credit)	$	2,967	$	3,683	$	333	$	(398)

	Nine Months Ended September 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2026		2025		2026		2025
Service cost	$	5,595	$	5,049	$	306	$	252
Interest cost	23,248		25,375		2,250		2,124
Expected return on plan assets	(26,370)		(26,791)		—		—
Estimated defined contribution provision	209		184		—		—
Amortization of prior service cost (credit)	1,296		1,475		(399)		(399)
Recognized actuarial (gain) loss	4,931		5,723		(1,160)		(3,170)
Total net periodic benefit cost (credit)	$	8,909	$	11,015	$	997	$	(1,193)

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 months ended September 30, 2026, the Company made contributions of $22.5 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2026 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.1 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.

The 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) authorizes the Committee to grant shares of the Company’s common stock and stock-based awards to employees. These awards may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents, and other stock-based incentives. The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

Shares issued pursuant to awards granted under the 2025 Long-Term Plan may be shares that are authorized but unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Shares underlying awards that have been canceled, expired, are forfeited, or otherwise not issued under an award shall not count as shares issued under the Plan.

During the nine months ended September 30, 2026, the Committee granted the following awards from the 2025 Long-Term Plan:


Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Performance-based RSUs 1	412,560	February 3, 2026	$	32.67	Monte Carlo
Time-based RSUs (Stock-Settled) 2	811,620	February 3, 2026	$	30.05	Average Stock Price
Time-based RSUs (Cash-Settled) 2	661,960	February 3, 2026	$	30.05	Average Stock Price
Performance-based RSUs 1	25,500	August 31, 2026	$	38.68	Monte Carlo
Time-based RSUs (Stock-Settled) 2	25,500	August 31, 2026	$	36.28	Average Stock Price

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

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

In May 2026, the Company’s shareholders approved the 2026 Stock Plan for Non-Employee Directors (the 2026 NED Plan) to replace the 2021 Stock Plan for Non-Employee Directors (the 2021 NED Plan). All awards granted on or after May 13, 2026, will be made under the 2026 NED Plan. The 2026 NED Plan will expire in 2036 and authorizes the issuance of up to 900,000 shares of common stock over its term. Additional information on the 2026 NED Plan can be found in Exhibit A to the definitive proxy statement filed on March 27, 2026.

Similar to the 2021 NED Plan, the 2026 NED Plan permits the issuance of restricted stock, RSUs and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to directors under the 2026, 2021 and 2018 Stock Plans for Non-Employee Directors.

During the nine months ended September 30, 2026, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan (before May 13, 2026) and the 2026 NED Plan (after May 13, 2026):


Type of Award	Number of Awards Granted	Grant Date	Grant Date Fair Value		Valuation Methodology
Time-Based RSUs 1	56,844	February 4, 2026	$	31.67	Closing Stock Price
Time-Based RSUs 2	2,150	March 31, 2026	$	41.25	Closing Stock Price
Time-Based RSUs 2	2,723	June 30, 2026	$	32.56	Closing Stock Price
Time-Based RSUs 2	2,396	September 30, 2026	$	37.02	Closing Stock Price

1 Non-Employee Directors’ time-based RSUs generally 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.

2 Non-Employee Directors may elect to receive all or a portion of their annual cash 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)	2026		2025
Compensation charged against income before tax benefit	$	36,582	$	33,884
Related income tax benefit recognized in income	5,593		4,882

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 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 and nine months ended September 30, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,				Nine Months Ended September 30,
(Weighted-average shares, except per share amounts)	2026		2025		2026		2025
Basic method	143,376,910		142,730,808		143,269,796		143,245,219
Dilutive restricted stock units 1	2,745,807		—		2,700,355		730,291
Diluted method	146,122,717		142,730,808		145,970,151		143,975,510

NET INCOME (LOSS) PER COMMON SHARE – BASIC	$	1.19	$	(0.02)	$	3.18	$	0.64



NET INCOME (LOSS) PER COMMON SHARE – DILUTED	$	1.17	$	(0.02)	$	3.13	$	0.64

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,
	2026	2025	2026	2025
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 divided by income from continuing operations before income taxes. For the three and nine months ended September 30, 2026 and 2025, the Company’s effective income tax rates were as follows:


	2026	2025
Three months ended September 30,	16.7%	(113.5)%
Nine months ended September 30,	23.9%	24.6%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

The effective tax rate for the three months ended September 30, 2026 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 $11.9 million.

The effective tax rate for the three months ended September 30, 2025 was below the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; 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 unfavorable impact on the effective tax rate was partially offset by the tax effect of stock-based compensation and U.S. state tax expense.

The effective tax rate for the nine months ended September 30, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate. The impacts were partially offset by 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 effective tax rate for the nine months ended September 30, 2025 was above the U.S. statutory tax rate of 21% 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.

For the nine months ended September 30, 2026, the Company paid $14.4 million in net cash income tax, compared to $9.2 million in net cash income tax for the nine months ended September 30, 2025.

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, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2022. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

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.

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 derivative instruments outstanding at September 30, 2026 and 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

Commodity Price Risks

The Company is subject to commodity price risk related to products it produces and sells. During the three and nine months ended September 30, 2026, the Company did not have any crude oil or natural gas derivative contracts.

During the third quarter of 2025, the Company held 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 were 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

For the three and nine months ended September 30, 2026 and 2025, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:



(Thousands of dollars)		Three Months Ended September 30,				Nine Months Ended September 30,
Type of Derivative Contract	Statement of Operations Location	2026		2025		2026		2025
Commodity swaps	Gain on derivative instruments	$	—	$	5,722	$	—	$	7,071

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.

The fair value measurements for these assets and liabilities at September 30, 2026 and December 31, 2025, are shown in the following table.


	September 30, 2026								December 31, 2025
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total





Liabilities:


Nonqualified employee savings plan	$	21,905	$	—	$	—	$	21,905	$	22,205	$	—	$	—	$	22,205
	$	21,905	$	—	$	—	$	21,905	$	22,205	$	—	$	—	$	22,205

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, 2026 and December 31, 2025.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at September 30, 2026 and December 31, 2025. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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, was minimal.


	September 30, 2026				December 31, 2025
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,634,352	$	1,480,834	$	1,385,080	$	1,326,101

Fair Values – Nonrecurring

There were no impairment charges incurred in the three and nine months ended September 30, 2026.

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.

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

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and September 30, 2026, and the changes during the nine months ended September 30, 2026, 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, 2025	$	(442,331)	$	(111,896)	$	(554,227)
Components of other comprehensive income (loss):
Before reclassifications to income	(59,001)		—		(59,001)
Reclassifications to income ¹	—		4,203		4,203
Net other comprehensive income (loss)	(59,001)		4,203		(54,798)
Balance at September 30, 2026	$	(501,332)	$	(107,693)	$	(609,025)

1 Reclassifications before taxes of $5.0 million are included in the computation of net periodic benefit expense for the nine months ended September 30, 2026. See Note H for additional information. Related income taxes of $0.8 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine months ended September 30, 2026.

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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 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 gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the One Big Beautiful Bill Act (OBBBA) passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, United States executive agencies were ordered to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions.

In August 2026, the Company responded to a produced water release from a pipeline on private land in the Tupper Montney West field. The incident was reported by Murphy to the appropriate regulatory authorities, and the affected pipeline was isolated and drained. Murphy continues environmental monitoring and remediation activities while working closely with the British Columbia Energy Regulator and private landowners.

The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently 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 months ended September 30, 2026 and 2025 is shown below.


(Number of shares outstanding)	September 30, 2026	September 30, 2025
Beginning of period	142,785,152	145,845,124

Restricted stock awards 1	595,973	500,146

Treasury shares purchased	—	(3,613,450)
End of period	143,381,125	142,731,820

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note O – Common Stock Issued and Outstanding (Continued)

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors.

During the nine months ended September 30, 2026, the Company did not 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, 2026, the Company had $550.1 million of its common stock remaining available to repurchase under the program.

Note P – Business Segments

Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia and U.S. 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 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 and Discontinued Operations		Consolidated Total
Three Months Ended September 30, 2026
Revenue from production	$	680.2	$	169.0	$	—	$	849.2	$	—	$	849.2

Gain on sale of assets and other operating income	1.5		0.5		—		2.0		3.7		5.7
Total revenues and other income	681.7		169.5		—		851.2		3.7		854.9
Lease operating expenses
Lease operating expenses and taxes other than income	86.6		42.6		0.1		129.3		—		129.3
Repair and maintenance	17.8		5.4		—		23.2		—		23.2
Workovers	(4.9)		1.6		—		(3.3)		—		(3.3)
Total lease operating expenses	99.5		49.6		0.1		149.2		—		149.2
Severance and ad valorem taxes	12.7		0.9		—		13.6		—		13.6
Transportation, gathering and processing	23.4		23.7		—		47.1		—		47.1

Selling and general expenses	7.7		7.5		2.6		17.8		22.8		40.6
Exploration Expenses
Geological and geophysical	2.0		—		15.6		17.6		—		17.6
Dry holes and previously suspended exploration costs	0.9		—		5.2		6.1		—		6.1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	5.3		—		4.1		9.4		—		9.4
Total exploration expenses	8.2		—		24.9		33.1		—		33.1
Depreciation, depletion and amortization	229.3		39.4		0.1		268.8		2.6		271.4

Accretion of asset retirement obligations	12.1		2.7		0.2		15.0		—		15.0

Other operating expenses	11.3		17.1		0.3		28.7		(0.1)		28.6


Interest Income	(0.7)		—		—		(0.7)		(2.2)		(2.9)
Interest expense, net of capitalization	0.1		0.1		—		0.2		24.0		24.2
Income tax expense
Current income tax expense	(0.6)		(1.0)		(0.1)		(1.7)		(1.9)		(3.6)
Deferred income tax expense (benefit)	55.5		8.3		(12.7)		51.1		(8.2)		42.9
Total income tax expense (benefit)	54.9		7.3		(12.8)		49.4		(10.1)		39.3
Other segment costs (income)	0.8		0.3		0.7		1.8		(1.6)		0.2
Segment income (loss) - including NCI 1	$	222.4	$	20.9	$	(16.1)	$	227.2	$	(31.7)	$	195.5

Additions to property, plant, equipment	$	219.9	$	21.2	$	164.0	$	405.1	$	10.8	$	415.9
Total assets at quarter-end	6,859.4		1,951.2		1,076.6		9,887.2		594.2		10,481.4

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 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 sale of assets and other operating income	0.3		0.5		—		0.8		11.4		12.2
Total revenues and other income	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 and Discontinued Operations		Consolidated Total
Nine Months Ended September 30, 2026
Revenue from production	$	1,997.9	$	507.1	$	2.9	$	2,507.9	$	—	$	2,507.9

Gain on sale of assets and other operating income	3.3		1.2		—		4.5		4.4		8.9
Total revenues and other income	2,001.2		508.3		2.9		2,512.4		4.4		2,516.8
Lease operating expenses
Lease operating expenses and taxes other than income	237.1		129.7		1.2		368.0		—		368.0
Repair and maintenance	47.9		6.8		—		54.7		—		54.7
Workovers	5.8		7.9		—		13.7		—		13.7
Total lease operating expenses	290.8		144.4		1.2		436.4		—		436.4
Severance and ad valorem taxes	39.7		2.6		—		42.3		—		42.3
Transportation, gathering and processing	73.1		66.3		—		139.4		—		139.4

Selling and general expenses	20.8		22.0		7.3		50.1		64.0		114.1
Exploration Expenses
Geological and geophysical	13.0		—		17.4		30.4		—		30.4
Dry holes and previously suspended exploration costs	0.5		—		86.2		86.7		—		86.7
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	15.2		—		22.9		38.1		—		38.1
Total exploration expenses	28.7		—		126.5		155.2		—		155.2
Depreciation, depletion and amortization	666.7		112.6		1.2		780.5		7.4		787.9

Accretion of asset retirement obligations	35.6		8.0		0.6		44.2		0.2		44.4

Other operating expenses	31.7		17.2		0.9		49.8		(2.1)		47.7


Interest Income	(1.5)		—		—		(1.5)		(6.8)		(8.3)
Interest expense, net of capitalization	0.3		0.1		0.1		0.5		77.6		78.1
Income tax expense
Current income tax expense	2.3		23.2		0.2		25.7		5.2		30.9
Deferred income tax expense (benefit)	156.9		6.7		(7.6)		156.0		(20.6)		135.4
Total income tax expense (benefit)	159.2		29.9		(7.4)		181.7		(15.4)		166.3
Other segment costs (income)	2.8		0.8		1.4		5.0		(19.4)		(14.4)
Segment income (loss) - including NCI 1	$	653.3	$	104.4	$	(128.9)	$	628.8	$	(101.1)	$	527.7

Additions to property, plant, equipment	$	737.9	$	147.6	$	364.1	$	1,249.6	$	27.2	$	1,276.8
Total assets at quarter-end	6,859.4		1,951.2		1,076.6		9,887.2		594.2		10,481.4

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 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 sale of assets and other operating income	3.6		1.3		—		4.9		15.0		19.9
Total revenues and other income	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 costs	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 Q – Leases

Nature of Leases

The Company has entered into various operating and finance 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 a combination of Company discretion and mutual agreement between the Company and the lessor. Purchase options also exist for certain leases.

During the third quarter of 2026, the Company commenced a finance lease for a floating storage and offloading vessel associated with its Vietnam operations. The lease term extends from September 2026 through October 2039, coinciding with the expiration of the relevant production sharing contract. The Company recognized a finance lease right-of-use asset of $103.4 million and a finance lease liability of $83.9 million in connection with this arrangement, with approximately $19.5 million in lease payments made prior to commencement. Finance lease right-of-use assets are contained in “Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization” on the Consolidated Balance Sheets.

In October 2026, the Company entered into an agreement for the use of a deepwater drillship in the Gulf of America. The initial term of the agreement covers 10 wells. Based on current estimates of well durations and applicable rates, the aggregate consideration associated with the initial term is approximately $225 million to $325 million on a gross basis. Actual payments may differ based on the duration of each well and the contractual rate applicable during periods of operation, movement, standby, or other activities. The agreement also provides the Company with options for up to five additional wells at rates to be agreed upon before exercise of the options. The agreement is anticipated to commence in the first quarter of 2027. As the agreement was executed after September 30, 2026 and had not commenced as of that date, no right-of-use asset or lease liability related to the agreement was recognized in these financial statements.

Maturity of Lease Liabilities


(Thousands of dollars)	Operating Leases		Finance Leases		Total
2026	$	84,456	$	6,399	$	90,855
2027	192,907		15,025		207,932
2028	64,533		15,025		79,558
2029	61,051		14,214		75,265
2030	57,995		13,608		71,603
Remaining	354,124		70,141		424,265
Total future minimum lease payments	815,066		134,412		949,478
Less imputed interest	(161,310)		(39,691)		(201,001)
Present value of lease liabilities 1	$	653,756	$	94,721	$	748,477

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

Lease Term and Discount Rate


	September 30, 2026		December 31, 2025
Weighted average remaining lease term:
Operating leases	8 years		7 years
Finance leases	12 years		5 years
Weighted average discount rate:
Operating leases	5.5	%	5.5	%
Finance leases	7.1	%	5.4	%

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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 period ended September 30, 2026 included under “Item 1. Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2025. 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, Canada and Vietnam. 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 the noncontrolling interest in MP GOM, unless otherwise noted.

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

•Production was 192,283 barrels of oil equivalent (BOE) per day (including NCI), a decrease from 206,936 BOE per day in the third quarter of 2025;

•Advanced the Bubale appraisal program offshore Côte d’Ivoire, with the Bubale West-1X well;

•Drilled an oil discovery at the Lac Da Trang (White Camel) North-1X exploration well offshore Vietnam;

•Achieved first oil from the Lac Da Vang (Golden Camel) development offshore Vietnam;

•Commenced production from the Chinook #8 development well in the Gulf of America; and

•Brought online 14 operated and four non-operated Eagle Ford Shale wells, and eight wells in the Tupper Montney.

Subsequent to the third quarter:

•Secured six exploration blocks from the August Gulf of America federal offshore lease sale.

•Signed agreements with the government of Mauritania for two offshore exploration blocks

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended September 30, 2026 was $195.8 million compared to net loss of $7.8 million for the same period in 2025. The increase in 2026 was primarily driven by higher revenues from production ($128.2 million), no impairment charges in the current year ($115.0 million), and lower lease operating expenses ($35.2 million). These favorable items were partially offset by higher income tax expense ($35.2 million), and higher other operating expenses ($22.7 million).

Higher revenues were driven by higher realized prices in the United States and Canada. These favorable impacts were partially offset by lower volumes in the Eagle Ford Shale and the Gulf of America. The prior-year period included impairment charges related to the Dalmatian field, while no impairment charges were recorded in the current year. Lower lease operating expenses were primarily driven by lower workover activity, insurance proceeds received related to past workovers, and production-related costs in the Gulf of America, partially offset by increased activity in the Eagle Ford Shale and Canada. Higher income tax expense primarily reflected higher pretax income. Higher other operating expenses primarily related to abandonment and environmental remediation costs in the Gulf of America and Canada, respectively.

For the three months ended September 30, 2026 total hydrocarbon production was 192,283 barrels of oil equivalent per day, a decrease of 7% compared to the third quarter of 2025. The decrease was principally due to lower volumes in the Gulf of America and the Eagle Ford Shale. Lower Gulf of America volumes primarily

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

Overview (Continued)

reflected natural declines at various wells, and lower Eagle Ford Shale and Tupper Montney volumes primarily reflected the timing of new wells. These decreases were partially offset by higher Canada Offshore volumes due to less downtime at Terra Nova.

Net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2026 was $529.0 million, an increase of $412.9 million compared to the same period of 2025. Higher net income from continuing operations was primarily driven by higher revenues from production ($431.1 million), lower lease operating expenses ($168.6 million), no impairment charges in the current year ($115.0 million), and higher other income ($38.6 million). These favorable items were partially offset by higher income tax expense ($128.4 million), higher exploration expenses ($97.8 million), higher depreciation, depletion and amortization (DD&A) ($51.0 million), and higher other operating expenses ($34.4 million).

Higher revenues were primarily driven by higher realized crude oil prices across the United States and Canada, together with higher sales volumes at Eagle Ford Shale, Kaybob and Terra Nova. These favorable impacts were partially offset by lower oil sales volumes in the Gulf of America and lower natural gas sales volumes at Tupper Montney. Lower lease operating expenses were primarily driven by substantially lower workover and production-related costs in the Gulf of America, partially offset by higher activity in the Eagle Ford Shale and higher repair, maintenance and workover costs in Canada. The prior-year period included impairment charges, while no impairment charges were recorded in the current year. Higher other income was primarily due to favorable foreign exchange movements. Higher income tax expense primarily reflected higher pretax income. Higher exploration expenses were primarily driven by dry hole costs in Côte d’Ivoire and Vietnam. Higher DD&A was primarily driven by higher sales volumes and depletion rates in the Eagle Ford Shale, higher rates in the Gulf of America and higher sales volumes at Kaybob and offshore Canada, partially offset by lower sales volumes in the Gulf of America and at Tupper Montney. Higher other operating expenses primarily related to abandonment and environmental remediation costs in the Gulf of America and Canada.

For the nine months ended September 30, 2026, total hydrocarbon production was 182,494 barrels of oil equivalent per day, a decrease of 3% compared to the same period in 2025. The decrease was principally due to lower volumes in the Gulf of America as a result of natural decline, and at Tupper Montney in Canada due to fewer new wells online in the current year. These decreases were partially offset by new Eagle Ford Shale production.

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

At September 30, 2026, the West Texas Intermediate (WTI) crude oil futures price was $89.42 per barrel, whereas the crude oil futures price at the end of October 2026 was $104.12, reflecting a 16% increase in price. As of November 2, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $96.46 per barrel. Changes in commodity prices will directly affect 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)	2026		2025		2026		2025
Exploration and production
United States	$	222.4	$	28.9	$	653.3	$	223.3
Canada	20.9		(6.1)		104.4		45.8
Other	(16.1)		(12.0)		(128.9)		(30.4)
Total exploration and production	227.2		10.8		628.8		238.7
Corporate	(31.5)		(18.6)		(99.9)		(122.7)
Income (loss) from continuing operations	195.7		(7.8)		528.9		116.0
Discontinued operations, net of tax 1	(0.2)		(0.5)		(1.2)		0.2
Net income (loss) including noncontrolling interest	195.5		(8.3)		527.7		116.2
Less: Net income (loss) attributable to noncontrolling interest	24.4		(5.3)		71.4		23.9
Net income (loss) attributable to Murphy	$	171.1	$	(3.0)	$	456.3	$	92.3

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)	2026		2025		2026		2025
Revenues and other income
Revenue from production	$	849.2	$	721.0	$	2,507.9	$	2,076.8

Other income	2.0		0.8		4.5		4.9
Total revenues and other income	851.2		721.8		2,512.4		2,081.7
Costs and expenses
Lease operating expenses	149.2		184.4		436.4		605.0
Severance and ad valorem taxes	13.6		12.3		42.3		31.8
Transportation, gathering and processing	47.1		48.1		139.4		151.1

Depreciation, depletion and amortization	268.8		281.4		780.5		730.7
Impairment of assets	—		115.0		—		115.0
Accretion of asset retirement obligations	15.0		14.6		44.2		43.1
Exploration expenses, including undeveloped lease amortization	33.1		32.5		155.2		57.4
Selling and general expenses	17.8		9.5		50.1		32.5
Other	30.0		6.6		53.8		13.0
Results of operations before taxes	276.6		17.4		810.5		302.1
Income tax provisions	49.4		6.6		181.7		63.4
Results of operations (excluding Corporate segment) 1	$	227.2	$	10.8	$	628.8	$	238.7

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 and nine months ended September 30, 2026 and 2025:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Weighted average sales prices)	2026		2025		2026		2025
Crude oil and condensate – dollars per barrel
United States - Onshore	$	86.48	$	65.48	$	86.29	$	66.24
United States - Offshore 1	89.38		67.00		86.40		67.81
Canada - Onshore 2	78.40		56.33		77.66		59.46
Canada - Offshore 2	108.21		69.42		97.33		70.17
Other 2	—		—		71.04		72.97
Natural gas liquids – dollars per barrel
United States - Onshore	23.89		18.57		21.82		19.92
United States - Offshore 1	20.12		20.18		19.35		21.85
Canada - Onshore 2	33.66		26.88		32.05		32.54
Natural gas – dollars per thousand cubic feet
United States - Onshore	2.54		2.64		2.89		2.87
United States - Offshore 1	3.50		3.39		4.22		3.73
Canada - Onshore 2	1.63		1.22		1.84		1.68

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 and nine months ended September 30, 2026 and 2025:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Average price for the period)	2026		2025		2026		2025
Oil and NGLs
WTI ($/BBL)	$	85.79	$	64.93	$	83.50	$	66.70
Natural gas
Henry Hub ($/MMBTU)	2.88		3.03		3.56		3.49
AECO (C$/MCF)	1.56		0.63		1.73		1.50

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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 and nine months ended September 30, 2026 and 2025. 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)	2026		2025	2026		2025
Net crude oil and condensate
United States - Onshore	30,157		34,703	28,509		26,797
United States - Offshore 1	48,183		56,071	50,300		56,835
Canada - Onshore	3,901		3,495	3,899		2,799
Canada - Offshore	6,972		5,518	7,945		6,658
Other	237		278	234		276
Total net crude oil and condensate	89,450		100,065	90,887		93,365
Net natural gas liquids
United States - Onshore	7,580		8,042	6,741		5,905
United States - Offshore 1	4,059		4,500	4,110		4,344
Canada - Onshore	543		442	547		491
Total net natural gas liquids	12,182		12,984	11,398		10,740
Net natural gas – thousands of cubic feet per day
United States - Onshore	34,923		39,411	33,629		32,711
United States - Offshore 1	44,721		50,477	48,327		51,528
Canada - Onshore	464,262		473,431	399,298		425,342
Total net natural gas	543,906		563,319	481,254		509,581
Total net hydrocarbons - including NCI 2,3	192,283		206,936	182,494		189,035
Noncontrolling interest
Net crude oil and condensate – barrels per day	(5,286)		(5,998)	(5,349)		(5,950)
Net natural gas liquids – barrels per day	(197)		(228)	(206)		(214)
Net natural gas – thousands of cubic feet per day	(1,829)		(1,963)	(1,913)		(1,715)
Total noncontrolling interest 2,3	(5,788)		(6,553)	(5,874)		(6,450)
Total net hydrocarbons - excluding NCI 2,3	186,495		200,383	176,620		182,585

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 and nine months ended September 30, 2026 and 2025. 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)	2026	2025	2026	2025
Net crude oil and condensate
United States - Onshore	30,157	34,703	28,509	26,797
United States - Offshore 1	47,856	57,903	50,124	56,849
Canada - Onshore	3,901	3,495	3,899	2,799
Canada - Offshore	6,975	5,513	8,249	8,114
Other	—	—	150	152
Total net crude oil and condensate	88,889	101,614	90,931	94,711
Net natural gas liquids
United States - Onshore	7,580	8,042	6,741	5,905
United States - Offshore 1	4,059	4,500	4,110	4,344
Canada - Onshore	543	442	547	491
Total net natural gas liquids	12,182	12,984	11,398	10,740
Net natural gas – thousands of cubic feet per day
United States - Onshore	34,923	39,411	33,629	32,711
United States - Offshore 1	44,721	50,477	48,327	51,528
Canada - Onshore	464,262	473,431	399,298	425,342
Total net natural gas	543,906	563,319	481,254	509,581
Total net hydrocarbons - including NCI 2,3	191,722	208,484	182,538	190,381
Noncontrolling interest
Net crude oil and condensate – barrels per day	(5,234)	(6,273)	(5,320)	(5,954)
Net natural gas liquids – barrels per day	(197)	(228)	(206)	(214)
Net natural gas – thousands of cubic feet per day	(1,829)	(1,963)	(1,913)	(1,715)
Total noncontrolling interest 2,3	(5,736)	(6,828)	(5,845)	(6,454)
Total net hydrocarbons - excluding NCI 2,3	185,986	201,656	176,693	183,927

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)	2026		2025		2026		2025
Revenues from production
United States - Oil	$	633.4	$	566.0	$	1,853.8	$	1,537.0
United States - Natural gas liquids	24.2		22.1		61.9		58.0
United States - Natural gas	22.6		25.3		82.2		78.0
Canada - Oil	97.6		53.3		301.9		200.9
Canada - Natural gas liquids	1.7		1.1		4.8		4.4
Canada - Natural gas	69.7		53.1		200.4		195.5
Other - Oil	—		0.1		2.9		3.0
Total revenue from production	$	849.2	$	721.0	$	2,507.9	$	2,076.8

Revenue from production for the three months ended September 30, 2026 increased $128.2 million compared to the same period in 2025. The increase was primarily driven by higher realized oil prices in the U.S. and Canada. In Canada, higher volumes at Terra Nova and Kaybob further increased revenues, while higher natural gas prices at Tupper Montney offset lower sales volumes. These favorable impacts were partially offset by lower volumes in the Eagle Ford Shale due to fewer new wells online in the period, and in the Gulf of America due to the natural decline of wells.

Revenues from production for the nine months ended September 30, 2026 increased $431.1 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized oil prices across the U.S. and Canada. The Eagle Ford Shale had higher oil volumes from new wells, while higher volumes at Kaybob and Terra Nova further increased revenues. At Tupper Montney, higher natural gas prices offset lower volumes. These favorable impacts were partially offset by lower Gulf of America oil volumes, particularly at Mormont and Khaleesi due to natural decline.

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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)
	2026		2025		2026		2025		2026		2025		2026		2025
Lease operating expenses
United States - Onshore	$	39.0	$	31.9	$	9.75	$	7.04	$	105.6	$	91.2	$	9.47	$	8.75
United States - Offshore	60.5		109.4		11.08		16.79		185.2		374.2		10.89		19.64
Canada - Onshore	31.9		30.0		4.22		3.94		97.4		95.8		5.02		4.73
Canada - Offshore	17.7		12.7		27.52		24.96		47.0		42.2		20.88		19.05
Other	0.1		0.4		—		—		1.2		1.6		30.43		37.54
Total lease operating expenses	$	149.2	$	184.4	$	8.46	$	9.61	$	436.4	$	605.0	$	8.76	$	11.64
Transportation, gathering and processing
United States - Onshore	$	3.5	$	3.2	$	0.88	$	0.72	$	9.9	$	7.8	$	0.89	$	0.75
United States - Offshore	19.9		20.1		3.64		3.08		63.2		74.6		3.72		3.91
Canada - Onshore	22.0		23.0		2.91		3.02		61.3		63.3		3.16		3.13
Canada - Offshore	1.7		1.8		2.69		3.49		5.0		5.4		2.21		2.42

Total transportation, gathering and processing	$	47.1	$	48.1	$	2.67	$	2.51	$	139.4	$	151.1	$	2.80	$	2.91

For the three months ended September 30, 2026 lease operating expenses decreased by $35.2 million and transportation, gathering and processing expenses decreased by $1.0 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by lower Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and the non-recurrence of prior-year workover costs at Marmalard and Khaleesi. These decreases were partially offset by current-quarter workover costs at Mormont.

For the nine months ended September 30, 2026 lease operating expenses decreased by $168.6 million, and transportation, gathering and processing expenses decreased by $11.7 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by favorable Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and lower workover costs at Samurai and Khaleesi. In addition, lower FPSO rental fees at Cascade & Chinook also decreased lease operating expenses. The Company also received a one-time access fee related to the Lucius field, which further contributed to decreases during the period. These decreases were partially offset by higher Eagle Ford Shale operating costs related to workover costs and increased number of wells.

Lower transportation, gathering and processing expenses were primarily due to lower sales volumes in the Gulf of America.

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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)
	2026		2025		2026		2025		2026		2025		2026		2025
DD&A
United States - Onshore	$	128.3	$	137.5	$	32.03	$	30.30	$	355.6	$	311.9	$	31.88	$	29.95
United States - Offshore	101.0		104.6		18.48		16.06		311.1		307.8		18.30		16.16
Canada - Onshore	32.8		33.5		4.36		4.38		88.4		87.6		4.56		4.32
Canada - Offshore	6.6		5.8		10.36		11.53		24.2		22.2		10.74		10.03
Other	0.1		—		—		—		1.2		1.2		28.74		31.66
Total DD&A	$	268.8	$	281.4	$	15.24	$	14.67	$	780.5	$	730.7	$	15.66	$	14.06

DD&A for the three months ended September 30, 2026 decreased by $12.6 million compared to the same period in 2025. The decrease was primarily driven by lower volumes in the Eagle Ford Shale due to fewer new wells online in the quarter, as well as lower production in the Gulf of America due to the natural decline of wells.

DD&A for the nine months ended September 30, 2026 increased by $49.8 million compared to the same period in 2025. The increase was primarily driven by higher volumes and depletion rates in the Eagle Ford Shale and higher depletion rates in the Gulf of America. These increases were partially offset by lower volumes in the Gulf of America.

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2026		2025		2026		2025
Exploration expenses
Dry holes and previously suspended exploration costs	$	6.1	$	0.8	$	86.7	$	0.1
Geological and geophysical	17.6		20.3		30.4		24.7
Other exploration	6.9		8.5		30.9		25.8
Undeveloped lease amortization	2.5		2.9		7.2		6.8
Total exploration expenses, including undeveloped lease amortization	$	33.1	$	32.5	$	155.2	$	57.4

Exploration expenses for the three months ended September 30, 2026 increased by $0.6 million compared to the same period in 2025. Higher dry hole costs related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) were offset by lower geological and geophysical activity in the Gulf of America.

Exploration expenses for the nine months ended September 30, 2026 increased by $97.8 million compared to the same period in 2025. Higher exploration expenses in the current period were primarily driven by dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam, all of which encountered non-commercial hydrocarbons.

Selling and General Expenses

Selling and general expenses increased $8.3 million and $17.6 million for the three and nine months ended September 30, 2026, respectively, compared with the same periods in 2025. Increases were primarily due to higher compensation costs, incentive awards and professional fees.

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

Results of Operations (Continued)

Other

Other expenses increased $23.4 million for the three months ended September 30, 2026 compared with the same period in 2025, primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney and additional abandonment costs in the Gulf of America.

Other expenses increased $40.8 million for the nine months ended September 30, 2026 compared with the same period in 2025 primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney, combined with the settlement of a joint venture dispute and additional abandonment costs in the Gulf of America.

Income Taxes

Income taxes for the three and nine months ended September 30, 2026 increased by $42.8 million and $118.3 million, respectively, compared to the same periods in 2025. Higher income tax expenses were primarily due to higher pretax income in the United States and Canada. The tax impact was also affected by exploration expenses incurred in foreign jurisdictions where no income tax benefits are currently available. The Company also recognized an income tax deduction for prior years’ Australia exploration spend.

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.

The Corporate segment reported a loss of $31.5 million for the three months ended September 30, 2026, an unfavorable variance of $12.9 million compared to the same period in 2025. The unfavorable variance was primarily due to lower foreign exchange gains ($11.3 million) and the non-repeat of prior year derivative gains ($5.7 million), partially offset by a higher income tax benefit ($7.7 million).

The Corporate segment reported a loss of $99.9 million for the nine months ended September 30, 2026, a favorable variance of $22.8 million compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($41.5 million) and was partially offset by higher net interest expense associated with the 2034 Notes and a lower income tax benefit ($10.1 million).

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF. The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 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)	2026		2025
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	1,517.6	$	998.2
Net cash required by investing activities	(1,361.7)		(851.4)
Net cash required by financing activities	(32.8)		(143.9)

Effect of exchange rate changes on cash and cash equivalents	—		(0.5)
Net increase in cash and cash equivalents	$	123.1	$	2.4

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the nine months ended September 30, 2026 increased by $519.4 million compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized commodity prices, which resulted in an increase in revenue from production ($431.1 million), and lower lease operating expenses ($168.6 million), primarily driven by lower workover expenses in the Gulf of America. These favorable impacts were partially offset by a $51.3 million increase in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations.

Cash Required by Investing Activities

Net cash required by investing activities for the nine months ended September 30, 2026 was $510.3 million higher compared to the same period in 2025. The increase was primarily due to higher property additions and dry hole costs ($506.0 million).

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)	2026		2025
Property additions and dry hole costs	$	1,333.0	$	827.0
Acquisition of oil and natural gas properties	28.6		24.4
Geophysical and other exploration expenses	57.8		46.8
Capital expenditure accrual changes and other	5.4		(30.6)
Total capital expenditures	$	1,424.8	$	867.6

Total accrual basis capital expenditures are shown below.


	Nine Months Ended September 30,
(Millions of dollars)	2026		2025
Capital Expenditures
Exploration and production	$	1,397.6	$	858.4
Corporate	27.2		9.2
Total capital expenditures	$	1,424.8	$	867.6

Higher capital expenditures in the nine months ended September 30, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory spending and development drilling in the Gulf of America and in Vietnam. These increases were partially offset by lower development spending in the Eagle Ford Shale and the prior year purchase of the Pioneer FPSO vessel 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)

Development capital expenditures in 2026 primarily related to development drilling and field development activities in the Gulf of America ($447.8 million), the Eagle Ford Shale ($232.2 million), the Tupper Montney and the Kaybob Duvernay ($128.1 million), and in Vietnam ($99.4 million).

Exploration expenditures in 2026 were $471.0 million, primarily comprised of activities in Côte d’Ivoire related to exploration drilling for the Bubale exploration and appraisal program (Blocks CI-709 and CI-103), and the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells. Exploration spending was also driven by activities in the Gulf of America, including federal lease acquisitions and exploration drilling at the Cello #1 and Banjo #1 exploration wells (Mississippi Canyon 385), and in Vietnam, including the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05) and the Lac Da Trang (White Camel) North (Block 15-1/05) exploration well.

Cash Required by Financing Activities

Net cash required by financing activities for the nine months ended September 30, 2026 decreased by $111.0 million compared to the same period in 2025.

In 2026, net cash required by financing activities was principally from the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), year-to-date cash dividends to shareholders of $1.05 per share ($150.5 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.5 million), and distributions to the noncontrolling interest in MP GOM ($21.2 million). These amounts were partially offset by a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million.

In 2025, net 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 guaranteed RCF ($150.0 million).

Liquidity

At September 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $500.3 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured guaranteed Amended RCF with a major banking consortium.

The Company’s $2.0 billion Amended RCF expires in January 2031. As of September 30, 2026 the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At September 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 6.16%. At September 30, 2026, the Company was in compliance with all covenants related to the Amended RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of September 30, 2026 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $105.1 million, the majority of which was held in Canada ($60.1 million), Côte d'Ivoire ($11.9 million), Vietnam ($9.5 million), Mexico ($7.7 million), Brunei ($5.4 million), and the U.K. ($4.4 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, 2026		December 31, 2025
Working capital
Total current assets	$	1,065.1	$	816.7
Total current liabilities	1,122.3		1,062.7
Net working capital liability	$	(57.2)	$	(246.0)

As of September 30, 2026 net working capital increased by $188.8 million compared to December 31, 2025. The increase was primarily attributable to a higher cash balance at the end of the period ($123.1 million) and higher accounts receivable ($112.5 million), partially offset by higher accounts payable ($50.6 million).

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

Capital Employed

A summary of capital employed at September 30, 2026 and December 31, 2025 follows.


	September 30, 2026				December 31, 2025
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,623.1	23.2	%	$	1,382.6	21.3	%
Murphy shareholders' equity	5,384.9		76.8	%	5,118.4		78.7	%
Total capital employed	$	7,008.0	100.0	%	$	6,501.0	100.0	%

At September 30, 2026, long-term debt of $1,623.1 million increased by $240.5 million compared to December 31, 2025 primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.4 years and a weighted average coupon of 6.3%. In addition, during the quarter, the Company commenced a finance lease for a FSO supporting operations at the Lac Da Vang field in Vietnam, resulting in a $75.3 million increase in long-term debt.

Murphy shareholders’ equity increased by $266.5 million in 2026, primarily due to net income ($456.3 million) and ($24.1 million) stock award amortization, partially offset by dividends ($150.5 million) and foreign currency translation ($59.0 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of September 30, 2026 there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2025.

Accounting Changes and Recent Accounting Pronouncements

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)	2026		2025		2026		2025
Net income (loss) attributable to Murphy (GAAP) ¹	$	171.1	$	(3.0)	$	456.3	$	92.3
Discontinued operations (income) loss	0.2		0.5		1.2		(0.2)
Net income (loss) from continuing operations attributable to Murphy	171.3		(2.5)		457.5		92.1
Adjustments:
Impairment of assets 1	—		92.0		—		92.0
Foreign exchange (gain) loss	(1.5)		(13.4)		(20.1)		20.9
Unrealized gain on derivative instruments	—		(2.5)		—		(3.9)
















Total adjustments, before taxes	(1.5)		76.1		(20.1)		109.0
Income tax (benefit) expense related to adjustments	0.4		(15.5)		5.2		(23.8)
Tax benefits on investments in foreign areas	(11.8)		—		(11.8)		—
Total adjustments, after taxes	(12.9)		60.6		(26.7)		85.2
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)	$	158.4	$	58.1	$	430.8	$	177.3

Net income (loss) from continuing operations per average diluted share (GAAP)	$	1.17	$	(0.02)	$	3.14	$	0.64
Adjusted net income from continuing operations per average diluted share (Non-GAAP)	$	1.08	$	0.41	$	2.95	$	1.23

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)	2026		2025		2026		2025
Net income (loss) attributable to Murphy (GAAP) ¹	$	171.1	$	(3.0)	$	456.3	$	92.3
Income tax expense	39.3		4.1		166.3		37.9
Interest expense, net	24.2		24.7		78.1		73.3
Depreciation, depletion and amortization expense 1	264.1		275.0		764.9		713.2
EBITDA attributable to Murphy (Non-GAAP) 1	$	498.7	$	300.8	$	1,465.6	$	916.7
Exploration expenses 1	33.0		32.5		155.1		57.3
EBITDAX attributable to Murphy (Non-GAAP) 1	$	531.7	$	333.3	$	1,620.7	$	974.0

EBITDA attributable to Murphy (Non-GAAP) 1	$	498.7	$	300.8	$	1,465.6	$	916.7
Impairment of assets 1	—		92.0		—		92.0
Foreign exchange (gain) loss	(1.5)		(13.4)		(20.1)		20.9
Accretion of asset retirement obligations 1	13.5		13.2		39.8		38.6
Unrealized gain on derivative instruments	—		(2.5)		—		(3.9)



Discontinued operations (income) loss	0.2		0.5		1.2		(0.2)






Adjusted EBITDA attributable to Murphy (Non-GAAP) 1	$	510.9	$	390.6	$	1,486.5	$	1,064.1
Exploration expenses 1	33.0		32.5		155.1		57.3
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1	$	543.9	$	423.1	$	1,641.6	$	1,121.4

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)

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.


	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions of dollars)	2026		2025		2026		2025
Net cash provided by continuing operations activities (GAAP)	$	540.5	$	339.4	$	1,517.6	$	998.2
Exclude: increase (decrease) in non-cash working capital	(25.5)		28.4		15.0		20.5
Operating cash flow excluding working capital adjustments (Non-GAAP)	515.0		367.8		1,532.6		1,018.7
Less: property additions and dry hole costs 1	(466.8)		(149.0)		(1,333.0)		(827.0)
Free cash flow (Non-GAAP)	$	48.2	$	218.8	$	199.6	$	191.7
Adjustments:
Cash dividends paid	(50.2)		(46.4)		(150.5)		(139.8)
Distributions to noncontrolling interest	—		(25.0)		(21.2)		(43.2)
Debt costs	(0.6)		—		(23.0)		—

Withholding tax on stock-based incentive awards	(0.7)		—		(8.5)		(7.7)
Acquisition of oil and natural gas properties	(5.1)		(23.0)		(28.6)		(24.4)
Adjusted free cash flow (Non-GAAP)	$	(8.4)	$	124.4	$	(32.2)	$	(23.4)

1 Property additions for the nine months ended September 30, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, including amounts attributable to a noncontrolling interest in MP GOM.

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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, higher average crude oil and natural gas pricing during the third quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on November 2, 2026 forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.



	2026		2027
WTI ($/BBL)	$	96.46	$	86.12
NYMEX ($/MMBTU)	2.86		2.91
AECO (US$ Equivalent/MCF)	1.35		1.41

The regional conflict involving Iran continues to contribute to heightened geopolitical risk and volatility in global energy markets, including disruptions and security risks affecting transit through the Strait of Hormuz. The Company has not experienced any direct physical disruption to its operations as a result of the conflict. However, the conflict may indirectly affect the Company through fluctuations in oil and natural gas prices and demand, increased costs or reduced availability of equipment and services, and broader supply chain pressures. A prolonged or escalating conflict, including further disruptions to critical energy infrastructure or maritime routes, could increase market volatility and adversely affect economic conditions, which could affect the Company’s future operating results, cash flows and financial position.

Changes in tariffs and trade policies may affect the cost and availability of goods and services used in E&P operations or contribute to inflation in the countries in which the Company operates. In July 2026, the Trump Administration implemented tariffs of generally 10% or 12.5% on imports from 60 economies pursuant to Section 301 of the Trade Act of 1974. The Company continues to monitor the actual and potential effects of these tariffs, other trade restrictions and related governmental actions, as well as opportunities to mitigate their impacts. The ultimate effects of these measures on the Company’s supply chain, capital expenditures and operating costs remain uncertain.

The Company cannot predict the impact economic conditions, including inflation, trade policies, tariffs, other trade restrictions and a possible economic recession, may have on future commodity prices or the cost and availability of goods and services used in E&P operations. Similarly, the Company cannot predict the effects of political instability, armed conflict, sanctions, changes in sanctions policy or other governmental actions affecting oil- and natural-gas-producing regions, including Russia and Ukraine, the Middle East and Venezuela. Such developments may affect global oil and natural gas supply, demand and pricing. It is also uncertain how production decisions by OPEC and participating non-OPEC countries, compliance with production targets and changes in participation or production capacity may influence commodity prices and the global supply-demand balance. Lower commodity prices or higher costs, should they occur, would reduce earnings and operating cash flows and could result in material future impairment charges.

For the fourth quarter of 2026, production is expected to average between 174.0 and 182.0 thousand barrels of oil equivalent per day, excluding noncontrolling interest. The Company now also expects full-year 2026 production, excluding noncontrolling interest, to be between 176.0 and 178.0 thousand barrels of oil equivalent per day, compared with its prior guidance of 167.0 to 175.0 thousand barrels of oil equivalent per day. The increased guidance is primarily attributable to accelerated Eagle Ford Shale activity, new well outperformance and lower royalties at Tupper Montney.

The Company expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million.

In the Gulf of America, the Chinook #8 (Walker Ridge 425) well commenced production during the quarter. Murphy will also continue progressing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter of 2026. The Company currently expects these wells to begin production in the fourth quarter of 2027. Finally, the evaluation of multiple blocks acquired in federal lease sales is ongoing.

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

Outlook (Continued)

In Côte d’Ivoire, the Company drilled a successful appraisal well at Bubale West-1X (Block CI-103). Going forward, the Bubale appraisal program is expected to include two to four wells over the next 18 to 24 months.

The Company commenced production at Lac Da Vang (Golden Camel), Block 15-1/05 in Vietnam during the quarter, and also drilled a discovery at the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well. At Hai Su Vang (Golden Sea Lion), the Company is evaluating development alternatives and advancing post-appraisal studies, with a final investment decision currently anticipated in late 2027.

In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally. Subsequent to the third quarter, the Company signed agreements with the government of Mauritania for two offshore exploration blocks, and is working to finalize an agreement in Cameroon before year-end.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, as well as changing commodity price environments, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2026 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or 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, our planned exploration and appraisal program and our bond terms, the Company is currently more likely to use available adjusted free cash flow for share repurchases than bond repayment.

On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of September 30, 2026.

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

As of November 2, 2026 the Company has entered into forward fixed price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

Volumes
(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type 1

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

C$3.00

10/1/2026

12/31/2026

Canada

Natural Gas

Fixed price forward sales

9.5

C$3.14

1/1/2027

12/31/2027

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

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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”, “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 intent 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 environmental, social and governance matters, make capital expenditures, 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 and demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns (including the ongoing conflict in the Middle East involving Iran); 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 markets of health pandemics and related government responses; natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; cyber attacks and other cybersecurity risks; any failure to obtain necessary regulatory approvals; the impact of current and future laws, rulings and governmental regulations; 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. 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. Each forward-looking statement contained in this report speaks only as of the date of this report. Except as required by applicable law, Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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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 no commodity-based derivative contracts in place as of September 30, 2026.

Foreign Exchange Risk

There were no derivative foreign exchange contracts in place at September 30, 2026.

Interest Rate Risk

The Company’s senior unsecured guaranteed Amended RCF provides for variable interest rate borrowings. As of September 30, 2026 we had no outstanding borrowings under the Amended RCF, and therefore, no related exposure to interest rate risk.

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, 2026 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 2025 Form 10-K filed on February 25, 2026. The Company has not identified any additional risk factors not previously disclosed in its 2025 Form 10-K report.

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ITEM 5. OTHER INFORMATION

Amended and Restated By-Laws

On November 4, 2026, the Board of Directors of Murphy Oil Corporation (the “Company”) approved and adopted amendments to Article II, Section 6 of the Company’s By-Laws (the “Amended By-laws”). The Amended By-laws were effective immediately upon adoption.

The foregoing description of the Amended By-Laws does not purport to be complete and is qualified in its entirety by reference to the text of the Amended By-Laws, which are attached hereto as Exhibit 3.2 and incorporated herein by reference.

Trading Plan Arrangements

During the three months ended September 30, 2026 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 November 4 , 2026





*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 4, 2026

(Date)

Murphy Oil - 10-Q quarterly report FY2026 Q3

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