mur-20260630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 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 July 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			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			7
Note D – Property, Plant and Equipment			9

Note E – Financing Arrangements and Debt			11
Note F – Other Financial Information			12
Note G – Asset Retirement Obligations			12
Note H – Employee and Retiree Benefit Plans			12
Note I – Incentive Plans			13
Note J – Net Income Per Common Share			15
Note K – Income Taxes			15
Note L – Financial Instruments and Risk Management			16
Note M – Accumulated Other Comprehensive Loss			18
Note N – Environmental and Other Contingencies			18
Note O – Common Stock Issued and Outstanding			20
Note P – Business Segments			20



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25
Item 3. Quantitative and Qualitative Disclosures About Market Risk			45
Item 4. Controls and Procedures			45
Part II – Other Information			46
Item 1. Legal Proceedings			46
Item 1A. Risk Factors			46

Item 5. Other Information			47
Item 6. Exhibits			47
Signature			48

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


(Thousands of dollars, except share amounts)	June 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	483,875	$	377,196
Accounts receivable, net	443,120		346,759
Inventories	62,011		57,284
Prepaid expenses	37,836		35,473

Total current assets	1,026,842		816,712
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $15,470,662 in 2026 and $15,068,149 in 2025	8,434,791		8,136,346
Operating lease assets	702,528		805,464

Deferred charges and other assets	113,973		74,104

Total assets	$	10,278,134	$	9,832,626
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	2,578	$	2,514
Accounts payable	671,238		572,183
Income taxes payable	32,330		18,209
Other taxes payable	36,388		28,295
Operating lease liabilities	280,162		278,834
Other accrued liabilities	120,438		120,755
Current asset retirement obligations	59,231		41,959
Total current liabilities	1,202,365		1,062,749
Long-term debt, including finance lease obligation	1,547,864		1,382,566
Asset retirement obligations	981,355		970,908
Deferred credits and other liabilities	245,770		263,596
Non-current operating lease liabilities	433,128		537,773
Deferred income taxes	464,462		378,337

Total liabilities	$	4,874,944	$	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 June 30, 2026 and 195,100,628 shares at December 31, 2025	195,101		195,101
Capital in excess of par value	844,653		859,633
Retained earnings	6,876,135		6,691,318
Accumulated other comprehensive loss	(606,066)		(554,227)
Treasury stock	(2,050,809)		(2,073,445)
Murphy Shareholders' Equity	5,259,014		5,118,380
Noncontrolling interest	144,176		118,317
Total equity	5,403,190		5,236,697
Total liabilities and equity	$	10,278,134	$	9,832,626

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 OPERATIONS

(UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of dollars, except per share amounts)	2026		2025		2026		2025
Revenues and other income
Revenue from production	$	926,332	$	683,065	$	1,658,686	$	1,355,795

Total revenue from sales to customers	926,332		683,065		1,658,686		1,355,795
Gain on derivative instruments	—		10,808		—		1,349
Gain on sale of assets and other operating income	1,975		1,697		3,173		4,137
Total revenues and other income	928,307		695,570		1,661,859		1,361,281
Costs and expenses
Lease operating expenses	143,719		215,554		287,183		420,633
Severance and ad valorem taxes	14,991		10,828		28,737		19,478
Transportation, gathering and processing	45,274		54,070		92,335		102,921

Exploration expenses, including undeveloped lease amortization	39,303		10,399		122,118		24,887
Selling and general expenses	38,670		36,919		73,540		67,834

Depreciation, depletion and amortization	262,106		259,324		516,482		453,484
Accretion of asset retirement obligations	14,870		14,432		29,384		28,477

Other operating expense	14,706		1,833		19,147		7,462
Total costs and expenses	573,639		603,359		1,168,926		1,125,176
Operating income from continuing operations	354,668		92,211		492,933		236,105
Other income (loss)
Other income (loss)	11,247		(32,304)		21,099		(29,902)
Interest expense, net	(24,917)		(25,053)		(53,894)		(48,576)
Total other loss	(13,670)		(57,357)		(32,795)		(78,478)
Income from continuing operations before income taxes	340,998		34,854		460,138		157,627
Income tax expense	77,030		1,032		126,975		33,754
Income from continuing operations	263,968		33,822		333,163		123,873
Income (loss) from discontinued operations, net of income taxes	(437)		1,302		(979)		669
Net income including noncontrolling interest	263,531		35,124		332,184		124,542
Less: Net income attributable to noncontrolling interest	31,356		12,844		47,023		29,226
NET INCOME ATTRIBUTABLE TO MURPHY	$	232,175	$	22,280	$	285,161	$	95,316
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	1.62	$	0.15	$	2.00	$	0.66
Discontinued operations	—		0.01		(0.01)		—
Net income	$	1.62	$	0.16	$	1.99	$	0.66
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	1.59	$	0.15	$	1.96	$	0.66
Discontinued operations	—		0.01		(0.01)		—
Net income	$	1.59	$	0.16	$	1.95	$	0.66
Cash dividends per common share	$	0.350	$	0.325	$	0.700	$	0.650
Average common shares outstanding (thousands)
Basic	143,351		142,721		143,216		143,502
Diluted	146,149		143,216		145,894		144,144

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 June 30,				Six Months Ended June 30,
(Thousands of dollars)	2026		2025		2026		2025
Net income including noncontrolling interest	$	263,531	$	35,124	$	332,184	$	124,542
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	(30,895)		90,222		(54,641)		88,555
Retirement and postretirement benefit plans	1,401		875		2,802		1,739


Other comprehensive income (loss)	(29,494)		91,097		(51,839)		90,294
Comprehensive income including noncontrolling interest	234,037		126,221		280,345		214,836
Less: Comprehensive income attributable to noncontrolling interest	31,356		12,844		47,023		29,226
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY	$	202,681	$	113,377	$	233,322	$	185,610

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)


	Six Months Ended June 30,
(Thousands of dollars)	2026		2025
Operating Activities
Net income including noncontrolling interest	$	332,184	$	124,542
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	516,482		453,484
Unsuccessful exploration well costs and previously suspended exploration costs	80,585		(776)
Deferred income tax expense	92,549		21,216
Accretion of asset retirement obligations	29,384		28,477
Long-term non-cash compensation	25,693		22,016
Amortization of undeveloped leases	4,835		3,909
(Income) loss from discontinued operations	979		(669)
Unrealized gain on derivative instruments	—		(1,371)






Other operating activities, net	(65,121)		(2)
Net (increase) decrease in non-cash working capital	(40,477)		7,905

Net cash provided by continuing operations activities	977,093		658,731
Investing Activities
Property additions and dry hole costs	(866,159)		(678,043)
Acquisition of oil and natural gas properties	(23,513)		(1,383)


Net cash required by investing activities	(889,672)		(679,426)
Financing Activities
Retirement of debt	(227,489)		—
Early redemption of debt cost	(2,369)		—
Debt issuance	500,000		—
Debt issuance cost	(7,819)		—
Borrowings on revolving credit facility	425,000		350,000
Repayment of revolving credit facility	(525,000)		(150,000)
Issue costs of revolving credit facility	(12,274)		(18)
Repurchase of common stock, including excise tax	(777)		(102,620)
Cash dividends paid	(100,344)		(93,412)
Distributions to noncontrolling interest	(21,164)		(18,165)
Withholding tax on stock-based incentive awards	(7,849)		(7,654)
Finance lease obligation payments	(870)		(486)


Net cash provided (required) by financing activities	19,045		(22,355)






Effect of exchange rate changes on cash and cash equivalents	213		(888)
Net increase (decrease) in cash and cash equivalents	106,679		(43,938)
Cash and cash equivalents at beginning of period	377,196		423,569
Cash and cash equivalents at end of period	$	483,875	$	379,631

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 June 30,				Six Months Ended June 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 June 30, 2026 and June 30, 2025, issued 195,100,628 shares at June 30, 2026 and June 30, 2025	$	195,101	$	195,101	$	195,101	$	195,101


Capital in Excess of Par Value
Balance at beginning of period	837,327		830,945		859,633		848,950

Restricted stock transactions and other	(282)		(398)		(30,467)		(27,736)
Share-based compensation	7,608		11,286		15,487		20,619

Balance at end of period	844,653		841,833		844,653		841,833
Retained Earnings
Balance at beginning of period	6,694,131		6,799,299		6,691,318		6,773,289
Net income attributable to Murphy	232,175		22,280		285,161		95,316


Cash dividends paid	(50,171)		(46,386)		(100,344)		(93,412)
Balance at end of period	6,876,135		6,775,193		6,876,135		6,775,193
Accumulated Other Comprehensive Loss
Balance at beginning of period	(576,572)		(628,875)		(554,227)		(628,072)
Foreign currency translation, net of income taxes	(30,895)		90,222		(54,641)		88,555
Retirement and postretirement benefit plans, net of income taxes	1,401		875		2,802		1,739


Balance at end of period	(606,066)		(537,778)		(606,066)		(537,778)
Treasury Stock
Balance at beginning of period	(2,051,091)		(2,076,211)		(2,073,445)		(1,995,018)
Repurchase of common stock	—		–		—		(100,876)
Awarded restricted stock, net of forfeitures	282		388		22,636		20,071

Balance at end of period – 51,744,796 shares of common stock at June 30, 2026 and 52,374,883 shares of common stock at June 30, 2025, at cost	(2,050,809)		(2,075,823)		(2,050,809)		(2,075,823)
Murphy Shareholders’ Equity	5,259,014		5,198,526		5,259,014		5,198,526
Noncontrolling Interest
Balance at beginning of period	133,984		157,020		118,317		147,593

Net income attributable to noncontrolling interest	31,356		12,844		47,023		29,226
Distributions to noncontrolling interest owners	(21,164)		(11,210)		(21,164)		(18,165)
Balance at end of period	144,176		158,654		144,176		158,654
Total Equity	$	5,403,190	$	5,357,180	$	5,403,190	$	5,357,180

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 June 30, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2026 and 2025, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 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 six months ended June 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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.

U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.

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

Disaggregation of Revenue

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

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


			Three Months Ended June 30,						Six Months Ended June 30,
(Thousands of dollars)			2026			2025			2026			2025
Net crude oil and condensate revenue
United States - Onshore	$	243,270		$	166,101		$	431,619		$	275,559
United States - Offshore 1	455,332			343,080			788,773			695,442
Canada - Onshore	37,142			12,583			54,533			27,313
Canada - Offshore	96,431			45,741			149,766			120,210
Other	—			2,948			2,909			2,948
Total crude oil and condensate revenue	832,175			570,453			1,427,600			1,121,472
Net natural gas liquids revenue
United States - Onshore	14,219			9,893			23,495			18,380
United States - Offshore 1	7,836			8,311			14,199			17,560
Canada - Onshore	1,787			1,523			3,104			3,270
Total natural gas liquids revenue	23,842			19,727			40,798			39,210
Net natural gas revenue
United States - Onshore	7,214			8,099			18,341			16,066
United States - Offshore 1	15,115			16,726			41,264			36,667
Canada - Onshore	47,986			68,060			130,683			142,380
Total natural gas revenue	70,315			92,885			190,288			195,113







Total revenue from sales to customers	926,332			683,065			1,658,686			1,355,795
Gain on derivative instruments	—			10,808			—			1,349
Gain on sale of assets and other operating income	1,975			1,697			3,173			4,137
Total revenues and other income	$	928,307		$	695,570		$	1,661,859		$	1,361,281

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

Contract Balances and Asset Recognition

As of June 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 $213.3 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

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

The Company has not entered into any revenue contracts that have financing components as of June 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, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

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

As of June 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 June 30, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $371.6 million. The following table reflects the net changes in capitalized exploratory well costs during the six months ended June 30, 2026 and 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)


(Thousands of dollars)	2026		2025
Beginning balance at January 1	$	191,821	$	72,055
Additions pending the determination of proved reserves	190,427		38,469

Capitalized exploratory well costs charged to expense	(10,627)		—
Balance at June 30	$	371,621	$	110,524

Capital additions of $190.4 million, for the six months ended June 30, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire; the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America; and the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in 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.

Subsequent to the second quarter of 2026, Murphy spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d’Ivoire and Lac Da Trang North-1X (White Camel) exploration well in Block 15-1/05 offshore 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 $38.5 million, for the six months ended June 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 six months ended June 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 six months ended June 30, 2025.

The preceding table excludes well costs of $70.0 million incurred and expensed directly to dry hole for the six months ended June 30, 2026. In 2026, these costs primarily related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, which encountered non-commercial hydrocarbons, 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.

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


	June 30,
	2026			2025

(Thousands of dollars)	Amount		No. of Projects		Amount		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	—	—		$	16,002	5
One to two years	228,318		3		72,004		3
Two to three years	120,979		3		—		—
Three years or more	22,324		3		22,518		3
	$	371,621	9		$	110,524	11

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

Of the $371.6 million of exploration well costs capitalized and classified as more than one year at June 30, 2026, $150.3 million was in Côte d’Ivoire, $114.0 million was in Vietnam, $100.1 million was in the Gulf of America, $4.5 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

During 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.

Impairments

There were no impairments in the three and six months ended June 30, 2026 and 2025.

Note E – Financing Arrangements and Debt

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 June 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 June 30, 2026, the interest rate in effect on borrowings under the Amended RCF was 5.90%. At June 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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows


	Six Months Ended June 30,
(Thousands of dollars)	2026		2025
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(96,506)	$	(976)
(Increase) decrease in inventories	(6,464)		(9,040)
(Increase) decrease in prepaid expenses	(3,897)		(11,009)
Increase (decrease) in accounts payable and accrued liabilities	52,269		24,141
Increase (decrease) in income taxes payable	14,121		4,789
Net (increase) decrease in non-cash working capital	$	(40,477)	$	7,905

Supplementary disclosures:

Interest paid, net of amounts capitalized of $8.8 million in 2026 and $2.9 million in 2025	$	35,442	$	44,577

Non-cash investing activities:
Asset retirement costs capitalized	$	8,918	$	9,427
(Increase) decrease in capital expenditure accrual	(52,007)		22,748

Note G – Asset Retirement Obligations

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

A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the six months ended June 30, 2026 and 2025 are shown in the following table.


(Thousands of dollars)	June 30, 2026		June 30, 2025
Balance at beginning of year	$	1,012,867	$	1,008,884
Accretion	29,384		28,477
Liabilities incurred	12,256		5,428

Revisions of previous estimates	—		3,999
Liabilities settled	(8,265)		(6,359)



Changes due to translation of foreign currencies	(5,656)		9,784
Balance at end of period	1,040,586		1,050,213
Current portion of liability	(59,231)		(70,104)
Non-current portion of liability	$	981,355	$	980,109

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans (Continued)

the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three and six months ended June 30, 2026 and 2025.


	Three Months Ended June 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2026		2025		2026		2025
Service cost	$	1,865	$	1,683	$	102	$	84
Interest cost	7,752		8,482		750		708
Expected return on plan assets	(8,792)		(8,953)		—		—
Estimated defined contribution provision	70		62		—		—
Amortization of prior service cost (credit)	432		492		(133)		(133)
Recognized actuarial (gain) loss	1,644		1,914		(387)		(1,057)



Total net periodic benefit cost (credit)	$	2,971	$	3,680	$	332	$	(398)

	Six Months Ended June 30,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2026		2025		2026		2025
Service cost	$	3,730	$	3,366	$	204	$	168
Interest cost	15,504		16,880		1,500		1,416
Expected return on plan assets	(17,584)		(17,824)		—		—
Estimated defined contribution provision	140		122		—		—
Amortization of prior service cost (credit)	864		983		(266)		(266)
Recognized actuarial (gain) loss	3,288		3,805		(774)		(2,113)
Total net periodic benefit cost (credit)	$	5,942	$	7,332	$	664	$	(795)

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

During the six months ended June 30, 2026, the Company made contributions of $15.4 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 $15.1 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents, and other stock-based incentives. The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term.

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

During the six months ended June 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

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 six months ended June 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

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.


	Six Months Ended June 30,
(Thousands of dollars)	2026		2025
Compensation charged against income before tax benefit	$	22,772	$	20,758
Related income tax benefit recognized in income	3,476		2,832

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 attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three and six months ended June 30, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,				Six Months Ended June 30,
(Weighted-average shares, except per share amounts)	2026		2025		2026		2025
Basic method	143,350,677		142,720,904		143,216,239		143,502,425
Dilutive restricted stock units	2,797,833		494,710		2,677,629		641,426
Diluted method	146,148,510		143,215,614		145,893,868		144,143,851

NET INCOME PER COMMON SHARE – BASIC	$	1.62	$	0.16	$	1.99	$	0.66



NET INCOME PER COMMON SHARE – DILUTED	$	1.59	$	0.16	$	1.95	$	0.66

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 six months ended June 30, 2026 and 2025, the Company’s effective income tax rates were as follows:


	2026	2025
Three months ended June 30,	22.6%	3.0%
Six months ended June 30,	27.6%	21.4%

The effective tax rate for the three months ended June 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 no tax applied to the pretax income of the noncontrolling interest in MP GOM.

The effective tax rate for the three months ended June 30, 2025 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.

The effective tax rate for the six months ended June 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note K – Income Taxes (Continued)

rates higher than the U.S. federal rate. The impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.

The effective tax rate for the six months ended June 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; 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 six months ended June 30, 2026, the Company paid $5.9 million in net cash income tax payments, compared to $0.4 million in net cash income tax payments for the six months ended June 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 June 30, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2021. 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 June 30, 2026 and 2025.

Commodity Price Risks

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

During the second 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 June 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

3.65

7/1/2025

9/30/2025

Fixed price derivative swap

United States

Natural Gas

3.74

10/1/2025

12/31/2025

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

For the three and six months ended June 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 June 30,				Six Months Ended June 30,
Type of Derivative Contract	Statement of Operations Location	2026		2025		2026		2025
Commodity swaps	Gain on derivative instruments	$	—	$	10,808	$	—	$	1,349

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 June 30, 2026 and December 31, 2025, are shown in the following table.


	June 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	$	23,641	$	—	$	—	$	23,641	$	22,205	$	—	$	—	$	22,205
	$	23,641	$	—	$	—	$	23,641	$	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 June 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 June 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 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.


	June 30, 2026				December 31, 2025
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,550,442	$	1,512,574	$	1,385,080	$	1,326,101

Fair Values – Nonrecurring

There were no impairment charges incurred in the three and six months ended June 30, 2026 and 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and June 30, 2026, and the changes during the six months ended June 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	(54,641)		—		(54,641)
Reclassifications to income ¹	—		2,802		2,802
Net other comprehensive income (loss)	(54,641)		2,802		(51,839)
Balance at June 30, 2026	$	(496,972)	$	(109,094)	$	(606,066)

1 Reclassifications before taxes of $3.3 million are included in the computation of net periodic benefit expense for the six months ended June 30, 2026. See Note H for additional information. Related income taxes of $0.5 million are included in "Income tax expense” on the Consolidated Statements of Operations for the six months ended June 30, 2026.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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

In recent years, there has been an increase in regulatory oversight of the oil and 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, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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

Note O – Common Stock Issued and Outstanding

Activity in the number of shares of common stock issued and outstanding for the six months ended June 30, 2026 and 2025 is shown below.


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

Restricted stock awards 1	570,680	494,071

Treasury shares purchased	—	(3,613,450)
End of period	143,355,832	142,725,745

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

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

During the six months ended June 30, 2026, the Company did not repurchase any shares of its common stock. During the six months ended June 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.9 million including excise taxes and fees). As of June 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 June 30, 2026
Revenue from production	$	743.0	$	183.3	$	—	$	926.3	$	—	$	926.3

Gain on sale of assets and other operating income	1.0		0.3		—		1.3		0.7		2.0
Total revenues and other income	744.0		183.6		—		927.6		0.7		928.3
Lease operating expenses
Lease operating expenses and taxes other than income	69.7		45.3		0.3		115.3		—		115.3
Repair and maintenance	17.8		0.7		—		18.5		—		18.5
Workovers	6.0		3.9		—		9.9		—		9.9
Total lease operating expenses	93.5		49.9		0.3		143.7		—		143.7
Severance and ad valorem taxes	14.1		0.9		—		15.0		—		15.0
Transportation, gathering and processing	24.6		20.7		—		45.3		—		45.3

Selling and general expenses	7.6		7.0		2.7		17.3		21.4		38.7
Exploration Expenses
Geological and geophysical	10.2		—		1.0		11.2		—		11.2
Dry holes and previously suspended exploration costs	(0.4)		—		13.9		13.5		—		13.5
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	5.0		—		9.6		14.6		—		14.6
Total exploration expenses	14.8		—		24.5		39.3		—		39.3
Depreciation, depletion and amortization	220.5		39.2		—		259.7		2.4		262.1

Accretion of asset retirement obligations	11.9		2.7		0.2		14.8		0.1		14.9

Other operating expenses	16.4		—		0.3		16.7		(2.0)		14.7


Interest Income	(0.6)		—		—		(0.6)		(2.3)		(2.9)
Interest expense, net of capitalization	0.1		(0.1)		0.1		0.1		24.8		24.9
Income tax expense
Current income tax expense	1.9		14.5		—		16.4		4.9		21.3
Deferred income tax expense (benefit)	64.1		(3.2)		1.7		62.6		(6.9)		55.7
Total income tax expense (benefit)	66.0		11.3		1.7		79.0		(2.0)		77.0
Other segment costs (income)	0.9		0.1		0.4		1.4		(9.3)		(7.9)
Segment income (loss) - including NCI 1	$	274.2	$	51.9	$	(30.2)	$	295.9	$	(32.4)	$	263.5

Additions to property, plant, equipment	$	263.2	$	64.3	$	128.8	$	456.3	$	7.1	$	463.4
Total assets at quarter-end	6,919.3		1,979.5		801.3		9,700.1		578.0		10,278.1

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 June 30, 2025
Revenue from production	$	552.2	$	127.9	$	2.9	$	683.0	$	—	$	683.0

Gain on sale of assets and other operating income	1.3		0.4		—		1.7		13.1		14.8
Total revenues and other income	553.5		128.3		2.9		684.7		13.1		697.8
Lease operating expenses
Lease operating expenses and taxes other than income	100.0		46.6		0.9		147.5		—		147.5
Repair and maintenance	13.9		1.1		—		15.0		—		15.0
Workovers	52.6		0.5		—		53.1		—		53.1
Total lease operating expenses	166.5		48.2		0.9		215.6		—		215.6
Severance and ad valorem taxes	10.5		0.3		—		10.8		—		10.8
Transportation, gathering and processing	30.3		23.8		—		54.1		—		54.1

Selling and general expenses	4.8		5.7		2.6		13.1		23.8		36.9
Exploration Expenses
Geological and geophysical	0.7		—		0.2		0.9		—		0.9
Dry holes and previously suspended exploration costs	(1.0)		—		0.1		(0.9)		—		(0.9)
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	3.6		—		6.8		10.4		—		10.4
Total exploration expenses	3.3		—		7.1		10.4		—		10.4
Depreciation, depletion and amortization	218.3		38.1		1.2		257.6		1.7		259.3

Accretion of asset retirement obligations	11.6		2.6		0.2		14.4		—		14.4



Other operating expenses	1.3		0.7		(1.4)		0.6		1.2		1.8
Interest income	(0.5)		—		—		(0.5)		(2.7)		(3.2)
Interest expense, net of capitalization	—		0.2		—		0.2		24.9		25.1
Income tax expense
Current income tax expense (benefit)	0.7		0.3		0.2		1.2		(5.0)		(3.8)
Deferred income tax expense (benefit)	19.2		(2.2)		(0.7)		16.3		(11.5)		4.8
Total income tax expense (benefit)	19.9		(1.9)		(0.5)		17.5		(16.5)		1.0
Other segment costs	1.0		0.1		0.1		1.2		35.3		36.5
Segment income (loss) - including NCI 1	$	86.5	$	10.5	$	(7.3)	$	89.7	$	(54.6)	$	35.1

Additions to property, plant, equipment	$	176.2	$	45.7	$	20.8	$	242.6	$	2.7	$	245.4
Total assets at quarter-end	6,984.9		2,038.6		364.4		9,387.9		451.6		9,839.5

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
Six Months Ended June 30, 2026
Revenue from production	$	1,317.7	$	338.1	$	2.9	$	1,658.7	$	—	$	1,658.7

Gain on sale of assets and other operating income	1.8		0.7		—		2.5		0.7		3.2
Total revenues and other income	1,319.5		338.8		2.9		1,661.2		0.7		1,661.9
Lease operating expenses
Lease operating expenses and taxes other than income	150.5		87.1		1.1		238.7		—		238.7
Repair and maintenance	30.1		1.4		—		31.5		—		31.5
Workovers	10.7		6.3		—		17.0		—		17.0
Total lease operating expenses	191.3		94.8		1.1		287.2		—		287.2
Severance and ad valorem taxes	27.0		1.7		—		28.7		—		28.7
Transportation, gathering and processing	49.7		42.6		—		92.3		—		92.3

Selling and general expenses	13.1		14.5		4.7		32.3		41.2		73.5
Exploration Expenses
Geological and geophysical	11.0		—		1.8		12.8		—		12.8
Dry holes and previously suspended exploration costs	(0.4)		—		81.0		80.6		—		80.6
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	9.9		—		18.8		28.7		—		28.7
Total exploration expenses	20.5		—		101.6		122.1		—		122.1
Depreciation, depletion and amortization	437.4		73.2		1.1		511.7		4.8		516.5

Accretion of asset retirement obligations	23.5		5.3		0.4		29.2		0.2		29.4

Other operating expenses	20.4		0.1		0.6		21.1		(2.0)		19.1


Interest Income	(0.8)		—		—		(0.8)		(4.6)		(5.4)
Interest expense, net of capitalization	0.2		—		0.1		0.3		53.6		53.9
Income tax expense
Current income tax expense	2.9		24.2		0.3		27.4		7.1		34.5
Deferred income tax expense (benefit)	101.4		(1.6)		5.1		104.9		(12.4)		92.5
Total income tax expense (benefit)	104.3		22.6		5.4		132.3		(5.3)		127.0
Other segment costs (income)	2.0		0.5		0.7		3.2		(17.8)		(14.6)
Segment income (loss) - including NCI 1	$	430.9	$	83.5	$	(112.8)	$	401.6	$	(69.4)	$	332.2

Additions to property, plant, equipment	$	518.0	$	126.4	$	200.1	$	844.5	$	16.4	$	860.9
Total assets at quarter-end	6,919.3		1,979.5		801.3		9,700.1		578.0		10,278.1

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
Six Months Ended June 30, 2025
Revenue from production	$	1,059.7	$	293.2	$	2.9	$	1,355.8	$	—	$	1,355.8

Gain on sale of assets and other operating income	3.3		0.8		—		4.1		3.6		7.7
Total revenues and other income	1,063.0		294.0		2.9		1,359.9		3.6		1,363.5
Lease operating expenses
Lease operating expenses and taxes other than income	200.3		91.9		1.2		293.4		—		293.4
Repair and maintenance	24.1		2.6		—		26.7		—		26.7
Workovers	99.7		0.8		—		100.5		—		100.5
Total lease operating expenses	324.1		95.3		1.2		420.6		—		420.6
Severance and ad valorem taxes	18.8		0.7		—		19.5		—		19.5
Transportation, gathering and processing	59.0		43.9		—		102.9		—		102.9

Selling and general expenses	6.8		11.7		4.5		23.0		44.8		67.8
Exploration Expenses
Geological and geophysical	3.9		—		0.5		4.4		—		4.4
Dry holes and previously suspended exploration costs	(0.8)		—		0.1		(0.7)		—		(0.7)
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	6.3		0.1		14.8		21.2		—		21.2
Total exploration expenses	9.4		0.1		15.4		24.9		—		24.9
Depreciation, depletion and amortization	377.6		70.5		1.3		449.4		4.1		453.5

Accretion of asset retirement obligations	23.0		5.1		0.4		28.5		—		28.5

Other operating expenses	4.0		1.7		(1.3)		4.4		3.1		7.5


Interest Income	(0.9)		—		—		(0.9)		(6.0)		(6.9)
Interest expense, net of capitalization	—		—		0.1		0.1		48.5		48.6
Income tax expense
Current income tax expense (benefit)	1.3		14.0		0.2		15.5		(2.9)		12.6
Deferred income tax expense (benefit)	43.7		(1.6)		(0.7)		41.4		(20.2)		21.2
Total income tax expense (benefit)	45.0		12.4		(0.5)		56.9		(23.1)		33.8
Other segment costs	1.8		0.6		0.3		2.7		35.6		38.3
Segment income (loss) - including NCI 1	$	194.4	$	52.0	$	(18.5)	$	227.9	$	(103.4)	$	124.5

Additions to property, plant, equipment	$	493.2	$	101.1	$	56.1	$	650.4	$	7.0	$	657.4
Total assets at quarter-end	6,984.9		2,038.6		364.4		9,387.9		451.6		9,839.5

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

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

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

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

•Production was 175,013 barrels of oil equivalent (BOE) per day (including NCI), a decrease from 196,315 BOE per day in the second quarter of 2025;

•Drilled an oil discovery at Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire;

•Concluded the Hai Su Vang (Golden Sea Lion) appraisal program with the completion of Hai Su Vang-4X (Block 15-2/17) appraisal well, which was expensed as a dry hole;

•Completed drilling operations and initiated completion activities at the Chinook #8 (Walker Ridge 425) development well in the Gulf of America;

•Finalized pipeline installation and launched the FSO (Floating Storage and Offloading vessel) at the Lac Da Vang development project in Vietnam; and

•Brought online six Eagle Ford Shale wells and four Kaybob Duvernay wells.

Subsequent to the second quarter:

•Spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d'Ivoire;

•Spud the Lac Da Trang (White Camel) North-1X exploration well in Block 15-1/05 in Vietnam; and

•Completed installation of topsides and mobilized FSO to final location for Lac Da Vang development project.

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2026 was $264.0 million compared to net income of $33.8 million for the same period in 2025. The increase in 2026 was primarily driven by higher revenues from production ($243.3 million), lower lease operating expenses ($71.8 million), higher other income ($43.6 million), and lower transportation, gathering and processing expenses ($8.8 million). These favorable items were partially offset by higher income tax expense ($76.0 million), higher exploration expense ($28.9 million), and higher other operating expenses ($12.9 million).

Higher revenues were primarily driven by higher realized crude oil prices in the United States, partially offset by lower oil sales volumes in the Gulf of America. Canada oil revenues also increased, driven by higher oil prices and increased production and sales at Terra Nova and Hibernia, as well as new wells at Kaybob; these items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Khaleesi, Marmalard and Samurai and

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

Overview (Continued)

lower production handling agreement costs at King’s Quay from lower volumes; these items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale. Higher other income was primarily due to foreign exchange gains driven by favorable currency movements in Canada. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, as well as certain exploration expenses that did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher exploration expenses were largely due to exploration activities in the Gulf of America and costs related to second-quarter appraisal programs in Vietnam and Côte d’Ivoire. Higher other operating expenses were related to the increase in a joint venture settlement provision.

For the three months ended June 30, 2026 total hydrocarbon production was 175,013 barrels of oil equivalent per day, a decrease of 11% compared to the second quarter of 2025. The decrease was principally due to lower offshore production in the Gulf of America, primarily attributable to planned and unplanned downtime at multiple fields, partially offset by higher production in Canada Offshore. Higher Canada Offshore production was driven by increased production at Terra Nova and Hibernia, while higher Canada Onshore production was driven by new wells at Kaybob. Higher Eagle Ford Shale production was primarily the result of new wells online in the current year.

Net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2026 was $333.2 million, an increase of $209.3 million compared to the same period of 2025. Higher net income from continuing operations was primarily driven by higher revenues from production ($302.9 million), lower lease operating expenses ($133.4 million), higher other income ($51.0 million), and lower transportation, gathering and processing expenses ($10.6 million). These favorable items were partially offset by higher exploration expenses ($97.2 million), higher income tax expense ($93.2 million), higher DD&A ($63.0 million), and higher other operating expenses ($11.7 million).

Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the United States contributing the majority of the increase from higher prices in the Gulf of America and both higher prices and volumes in the Eagle Ford Shale from new wells at Karnes and Catarina. Canada oil revenues increased from higher prices along with higher production at Kaybob from new wells; these items were partially offset by lower Canada natural gas revenues, primarily due to reduced production and sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Samurai, Marmalard and Khaleesi, lower production handling agreement costs at King’s Quay from lower volumes, and lower FPSO rental fees at Cascade & Chinook following the vessel purchase in early 2025. Higher other income was primarily due to favorable foreign exchange movements. Higher exploration expenses were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons, and the Hai Su Vang-4X (Golden Sea Lion) Block 15-2/17 appraisal well in Vietnam, which did not encounter hydrocarbons and was also expensed as a dry hole. Exploration activities in the Gulf of America also contributed to the higher exploration costs. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, and certain exploration expenses did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher DD&A was primarily driven by higher sales volumes in the Eagle Ford Shale, combined with higher rates in the Eagle Ford Shale and the Gulf of America, and higher sales volumes at Kaybob from new wells; these items were partially offset by lower sales volumes in the Gulf of America and at Tupper. Higher other operating expenses were related to the increase in a joint venture settlement provision.

For the six months ended June 30, 2026, total hydrocarbon production was 177,519 barrels of oil equivalent per day, a decrease of 1% compared to the same period in 2025. The decrease was principally due to lower production in the Gulf of America, primarily from planned and unplanned downtime at multiple fields, and lower natural gas production at Tupper. These decreases were largely offset by higher production in the Eagle Ford Shale from new wells, higher Canada Offshore production from Terra Nova and Hibernia, and higher Canada Onshore production from new wells at Kaybob.

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

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

Overview (Continued)

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 June 30, 2026, the West Texas Intermediate (WTI) crude oil futures price was $68.96 per barrel, whereas the crude oil futures price at the end of July 2026 was $80.31, reflecting a 16% increase in price. As of August 3, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $76.97 per barrel. Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.

Results of Operations

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


	Income (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Exploration and production
United States	$	274.2	$	86.5	$	430.9	$	194.4
Canada	51.9		10.5		83.5		52.0
Other	(30.2)		(7.3)		(112.8)		(18.5)
Total exploration and production	295.9		89.7		401.6		227.9
Corporate and other	(32.0)		(55.9)		(68.4)		(104.1)
Income from continuing operations	263.9		33.8		333.2		123.8
Discontinued operations, net of tax 1	(0.4)		1.3		(1.0)		0.7
Net income including noncontrolling interest	263.5		35.1		332.2		124.5
Less: Net income attributable to noncontrolling interest	31.3		12.8		47.0		29.2
Net income attributable to Murphy	$	232.2	$	22.3	$	285.2	$	95.3

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 June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Revenues and other income
Revenue from production	$	926.3	$	683.0	$	1,658.7	$	1,355.8

Other income	1.3		1.7		2.5		4.1
Total revenues and other income	927.6		684.7		1,661.2		1,359.9
Costs and expenses
Lease operating expenses	143.7		215.5		287.2		420.6
Severance and ad valorem taxes	15.0		10.8		28.7		19.5
Transportation, gathering and processing	45.3		54.0		92.3		102.9

Depreciation, depletion and amortization	259.7		257.6		511.7		449.4

Accretion of asset retirement obligations	14.8		14.4		29.2		28.5
Exploration expenses, including undeveloped lease amortization	39.3		10.4		122.1		24.9
Selling and general expenses	17.3		13.1		32.3		23.0
Other	17.6		1.6		23.8		6.3
Results of operations before taxes	374.9		107.3		533.9		284.8
Income tax provisions	79.0		17.6		132.3		56.9
Results of operations (excluding Corporate segment) 1	$	295.9	$	89.7	$	401.6	$	227.9

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 six months ended June 30, 2026 and 2025:


	Three Months Ended June 30,				Six Months Ended June 30,
(Weighted average sales prices)	2026		2025		2026		2025
Crude oil and condensate – dollars per barrel
United States - Onshore	$	99.55	$	64.00	$	86.18	$	66.84
United States - Offshore 1	99.36		64.48		84.99		68.23
Canada - Onshore 2	84.08		59.94		77.28		61.73
Canada - Offshore 2	103.88		64.76		93.00		70.39
Other 2	—		70.86		71.04		70.86
Natural gas liquids – dollars per barrel
United States - Onshore	23.08		19.56		20.55		21.07
United States - Offshore 1	21.66		19.35		18.97		22.75
Canada - Onshore 2	34.46		33.84		31.25		35.00
Natural gas – dollars per thousand cubic feet
United States - Onshore	2.41		2.75		3.07		3.03
United States - Offshore 1	3.38		3.47		4.55		3.89
Canada - Onshore 2	1.48		1.65		1.97		1.96

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 six months ended June 30, 2026 and 2025:


	Three Months Ended June 30,				Six Months Ended June 30,
(Average price for the period)	2026		2025		2026		2025
Oil and NGLs
WTI ($/BBL)	$	92.79	$	63.74	$	82.36	$	67.58
Natural gas
Henry Hub ($/MMBTU)	2.94		3.16		3.90		3.72
AECO (C$/MCF)	1.63		1.69		1.82		1.93

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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 six months ended June 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 32.


		Three Months Ended June 30,			Six Months Ended June 30,
(Barrels per day unless otherwise noted)	2026		2025	2026		2025

Net crude oil and condensate
United States - Onshore	26,853		28,519	27,670		22,779
United States - Offshore 1	50,920		58,840	51,377		57,222
Canada - Onshore	4,854		2,307	3,899		2,445
Canada - Offshore	7,880		5,638	8,440		7,237
Other	239		296	232		275
Total net crude oil and condensate	90,746		95,600	91,618		89,958
Net natural gas liquids
United States - Onshore	6,769		5,557	6,315		4,818
United States - Offshore 1	3,976		4,720	4,136		4,265
Canada - Onshore	570		494	549		516
Total net natural gas liquids	11,315		10,771	11,000		9,599
Net natural gas – thousands of cubic feet per day
United States - Onshore	32,861		32,389	32,971		29,306
United States - Offshore 1	49,178		52,964	50,160		52,062
Canada - Onshore	355,672		454,310	366,277		400,898
Total net natural gas	437,711		539,663	449,408		482,266
Total net hydrocarbons - including NCI 2,3	175,013		196,315	177,519		179,935
Noncontrolling interest
Net crude oil and condensate – barrels per day	(5,481)		(6,070)	(5,382)		(5,925)
Net natural gas liquids – barrels per day	(195)		(244)	(210)		(207)
Net natural gas – thousands of cubic feet per day	(2,052)		(1,942)	(1,955)		(1,590)
Total noncontrolling interest 2,3	(6,018)		(6,638)	(5,918)		(6,397)
Total net hydrocarbons - excluding NCI 2,3	168,995		189,677	171,601		173,538

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 six months ended June 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 32.


	Three Months Ended June 30,		Six Months Ended June 30,
(Barrels per day unless otherwise noted)	2026	2025	2026	2025
Net crude oil and condensate
United States - Onshore	26,853	28,520	27,670	22,779
United States - Offshore 1	50,359	58,469	51,277	56,313
Canada - Onshore	4,854	2,307	3,899	2,444
Canada - Offshore	10,201	7,762	8,897	9,436
Other	—	457	226	230
Total net crude oil and condensate	92,267	97,515	91,969	91,202
Net natural gas liquids
United States - Onshore	6,769	5,557	6,315	4,819
United States - Offshore 1	3,976	4,720	4,136	4,264
Canada - Onshore	570	494	549	516
Total net natural gas liquids	11,315	10,771	11,000	9,599
Net natural gas – thousands of cubic feet per day
United States - Onshore	32,861	32,388	32,971	29,306
United States - Offshore 1	49,178	52,964	50,160	52,062
Canada - Onshore	355,672	454,310	366,277	400,898
Total net natural gas	437,711	539,662	449,408	482,266
Total net hydrocarbons - including NCI 2,3	176,534	198,230	177,870	181,179
Noncontrolling interest
Net crude oil and condensate – barrels per day	(5,396)	(6,014)	(5,365)	(5,792)
Net natural gas liquids – barrels per day	(195)	(243)	(210)	(207)
Net natural gas – thousands of cubic feet per day	(2,052)	(1,942)	(1,955)	(1,590)
Total noncontrolling interest 2,3	(5,933)	(6,581)	(5,901)	(6,264)
Total net hydrocarbons - excluding NCI 2,3	170,601	191,649	171,969	174,915

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 June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Revenues from production
United States - Oil	$	698.6	$	509.2	$	1,220.4	$	971.0
United States - Natural gas liquids	22.1		18.1		37.7		35.9
United States - Natural gas	22.3		24.8		59.6		52.7
Canada - Oil	133.5		58.3		204.3		147.5
Canada - Natural gas liquids	1.8		1.5		3.1		3.3
Canada - Natural gas	48.0		68.1		130.7		142.4
Other - Oil	—		2.9		2.9		2.9
Total revenue from production	$	926.3	$	683.0	$	1,658.7	$	1,355.8

Revenue from production for the three months ended June 30, 2026 increased $243.3 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized crude oil prices in the U.S., partially offset by lower oil sales volumes in the Gulf of America due to decreased production at the Mormont, Kodiak, and Samurai fields related to planned and unplanned downtime. Canada oil revenues increased, driven by higher oil prices and increased sales at Terra Nova and Hibernia, as well as new wells at Kaybob. These items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper.

Revenues from production for the six months ended June 30, 2026 increased $302.9 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the U.S. contributing the majority of the increase from higher prices in the Gulf of America and both higher prices and volumes in the Eagle Ford Shale from new wells at Karnes and Catarina. Canada oil revenues also increased, primarily driven by higher prices, as well as higher production at Kaybob from new wells. These items were partially offset by lower Canada natural gas revenues, primarily due to lower production at Tupper due to the natural decline of new wells. U.S. natural gas revenues increased from higher realized prices, while U.S. NGL revenues increased primarily from higher volumes in the Eagle Ford Shale.

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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 June 30,								Six Months Ended June 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	$	34.2	$	29.5	$	9.60	$	8.20	$	66.6	$	59.2	$	9.31	$	10.08
United States - Offshore	59.3		137.0		10.43		20.91		124.7		264.9		10.80		21.13
Canada - Onshore	32.5		35.6		5.52		4.98		65.4		65.8		5.53		5.21
Canada - Offshore	17.5		12.6		18.84		17.86		29.4		29.5		18.24		17.29
Other	0.2		0.8		—		19.95		1.1		1.2		25.74		29.02
Total lease operating expenses	$	143.7	$	215.5	$	8.95	$	11.95	$	287.2	$	420.6	$	8.92	$	12.83
Transportation, gathering and processing
United States - Onshore	$	3.7	$	2.1	$	1.03	$	0.62	$	6.4	$	4.5	$	0.90	$	0.77
United States - Offshore	20.8		28.1		3.66		4.28		43.3		54.5		3.75		4.35
Canada - Onshore	18.9		22.0		3.21		3.08		39.4		40.3		3.32		3.19
Canada - Offshore	1.9		1.8		2.01		2.53		3.2		3.6		2.01		2.10

Total transportation, gathering and processing	$	45.3	$	54.0	$	2.82	$	3.00	$	92.3	$	102.9	$	2.87	$	3.14

For the three months ended June 30, 2026 lease operating expenses decreased by $71.8 million and transportation, gathering and processing expenses decreased by $8.7 million compared to the same period in 2025. Lower expenses were primarily driven by decreased costs in the Gulf of America, where workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Khaleesi, Marmalard, and Samurai, a one-time access fee received at Lucius, and lower production handling agreement costs at King's Quay from lower volumes. These items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale.

Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes in the Gulf of America.

For the six months ended June 30, 2026 lease operating expenses decreased by $133.4 million, and transportation, gathering and processing expenses decreased by $10.6 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America. Workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Samurai, Marmalard, and Khaleesi. In addition, lower production handling agreement costs at King's Quay from lower volumes and lower FPSO rental fees at Cascade & Chinook, following the vessel purchase in early 2025, contributed to the decrease in operating expenses. Canada Offshore expenses decreased due to lower production-related costs at Terra Nova. These items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale.

Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes across multiple Gulf of America fields including Mormont, St. Malo, and Khaleesi. Canada Onshore transportation costs decreased due to lower volumes and ongoing mitigation efforts at Tupper.

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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 June 30,								Six Months Ended June 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	$	113.9	$	107.4	$	32.01	$	29.88	$	227.2	$	174.4	$	31.79	$	29.68
United States - Offshore	106.6		110.9		18.74		16.93		210.2		203.2		18.21		16.21
Canada - Onshore	29.2		30.0		4.96		4.20		55.6		54.1		4.69		4.29
Canada - Offshore	9.9		8.1		10.65		11.47		17.5		16.4		10.89		9.59
Other	0.1		1.2		—		28.38		1.2		1.3		27.84		31.02
Total DD&A	$	259.7	$	257.6	$	16.16	$	14.28	$	511.7	$	449.4	$	15.89	$	13.70

DD&A for the three months ended June 30, 2026 increased by $2.1 million compared to the same period in 2025. Higher DD&A was primarily driven by higher rates in the Eagle Ford Shale and the Gulf of America, as well as higher sales volumes at Canada Offshore from increased cargo deliveries at Terra Nova and Hibernia and higher volumes at Kaybob from new wells. These items were partially offset by lower volumes in the Gulf of America related to planned and unplanned downtime at multiple fields and lower sales volumes at Tupper.

DD&A for the six months ended June 30, 2026 increased by $62.3 million compared to the same period in 2025. Higher DD&A was primarily driven by significantly higher sales volumes in the Eagle Ford Shale from new Alice May wells at Karnes and new wells at Catarina, combined with higher rates in the Eagle Ford Shale and the Gulf of America. Additionally, higher sales volumes at Kaybob from new wells contributed to the increase. These items were partially offset by lower sales volumes in the Gulf of America and at Tupper.

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Exploration expenses
Dry holes and previously suspended exploration costs	$	13.5	$	(0.9)	$	80.6	$	(0.7)
Geological and geophysical	11.2		0.8		12.8		4.4
Other exploration	12.2		8.2		24.0		17.3
Undeveloped lease amortization	2.4		2.3		4.7		3.9
Total exploration expenses, including undeveloped lease amortization	$	39.3	$	10.4	$	122.1	$	24.9

Exploration expenses for the three months ended June 30, 2026 increased by $28.9 million compared to the same period in 2025. Higher exploration expenses in the current quarter were largely due to exploration activities in Côte d’Ivoire, Vietnam, and the Gulf of America. Dry holes and previously suspended exploration costs primarily related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam.

Exploration expenses for the six months ended June 30, 2026 increased by $97.2 million compared to the same period in 2025. Higher exploration expenses in the current period were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam, all of which encountered non-commercial hydrocarbons. Exploration activities in the Gulf of America also contributed to the higher exploration costs.

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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 by $16.0 million and $17.5 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in a joint venture dispute settlement provision.

Income Taxes

Income taxes for the three and six months ended June 30, 2026 increased by $61.4 million and $75.4 million, respectively, compared to the same periods in 2025. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, higher exploration expenses, mainly due to dry hole expenses recognized related to Côte d’Ivoire, did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.

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 $32.0 million for the three months ended June 30, 2026 a favorable variance of $23.9 million compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($44.0 million), driven by favorable currency movements in Canada. These gains were partially offset by no repeat of gains on derivative instruments in 2026 ($10.3 million) and lower income tax benefit ($14.5 million) due to higher current period net income.

The Corporate segment reported a loss of $68.4 million for the six months ended June 30, 2026 a favorable variance of $35.7 million, compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($52.9 million). These favorable items were partially offset by higher income tax expense ($17.8 million), and higher interest expense ($5.2 million) related to costs associated with the redemption of the 2027 Notes and 2028 Notes.

Financial Condition

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


	Six Months Ended June 30,
(Millions of dollars)	2026		2025
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	977.1	$	658.7
Net cash required by investing activities	(889.7)		(679.4)
Net cash provided (required) by financing activities	19.0		(22.4)

Effect of exchange rate changes on cash and cash equivalents	0.3		(0.9)
Net increase (decrease) in cash and cash equivalents	$	106.7	$	(43.9)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the six months ended June 30, 2026 increased by $318.4 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 a $302.9 million increase in revenue from production, and lower lease operating expenses ($133.4 million). These favorable impacts were partially offset by a $65.1 million decrease in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations, as well as a $48.4 million unfavorable change in net non-cash working capital, which was also affected by higher commodity prices.

Cash Required by Investing Activities

Net cash required by investing activities for the six months ended June 30, 2026 was $210.2 million higher compared to the same period in 2025. The increase was primarily due to higher property additions and dry hole costs ($188.1 million) and higher acquisition capital ($22.1 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.


	Six Months Ended June 30,
(Millions of dollars)	2026		2025
Property additions and dry hole costs	$	866.2	$	678.0

Acquisition of oil and natural gas properties	23.5		1.4
Geophysical and other exploration expenses	34.3		19.3
Capital expenditure accrual changes and other	54.2		(20.3)
Total capital expenditures	$	978.2	$	678.4

Total accrual basis capital expenditures are shown below.


	Six Months Ended June 30,
(Millions of dollars)	2026		2025
Capital Expenditures
Exploration and production	$	961.9	$	671.4
Corporate	16.3		7.0
Total capital expenditures	$	978.2	$	678.4

Higher capital expenditures in the six months ended June 30, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory and development drilling in the Gulf of America, and higher development spending in Vietnam, which included progressing the LDV-A platform construction and pipe-laying campaign. These increases were partially offset by lower field

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

Financial Condition (Continued)

development costs in the Gulf of America due to the prior year purchase of the Pioneer FPSO in the Gulf of America.

Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($278.7 million), the Eagle Ford Shale ($187.4 million), the Tupper Montney and the Kaybob Duvernay ($112.8 million), and in Vietnam ($55.0 million).

Exploration costs in 2026 were $314.3 million, primarily comprised of activities in Côte d'Ivoire related to exploration drilling for Bubale-1X (Block CI-709), Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells, and the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05). Exploration costs were also driven by activities in the Gulf of America including lease acquisitions and exploration drilling at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells.

Cash Provided (Required) by Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2026 increased by $41.4 million compared to the same period in 2025.

In 2026, the cash provided by financing activities was principally from a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million. The bond issuance was partially offset by the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), year-to-date cash dividends to shareholders of $0.70 per share ($100.3 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.1 million), and distributions to the noncontrolling interest in MP GOM ($21.2 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 $0.65 per share ($93.4 million), and distributions to the noncontrolling interest in MP GOM ($18.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($200.0 million).

Liquidity

At June 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $483.9 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured Amended RCF with a major banking consortium.

The Company’s $2.0 billion senior unsecured Amended RCF expires in January 2031. As of June 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 June 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 5.90%. At June 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 June 30, 2026 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $160.2 million, the majority of which was held in Canada ($89.4 million), Côte d'Ivoire ($34.6 million), Vietnam ($12.7 million), Mexico ($7.9 million), Brunei ($6.1 million), and the U.K. ($4.6 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.

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

Financial Condition (Continued)

Working Capital


(Millions of dollars)	June 30, 2026		December 31, 2025
Working capital
Total current assets	$	1,026.8	$	816.7
Total current liabilities	1,202.3		1,062.7
Net working capital liability	$	(175.5)	$	(246.0)

As of June 30, 2026 net working capital increased by $70.5 million compared to December 31, 2025. The increase was primarily attributable to a higher cash balance at the end of the period ($106.7 million) and higher accounts receivable ($96.4 million), partially offset by higher accounts payable ($99.1 million), higher current asset retirement obligations ($17.3 million), and higher income taxes payable ($14.1 million).

Higher accounts receivable and accounts payable were primarily due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively. Higher current asset retirement obligations were due to reclassification of certain obligations from long-term to current for anticipated well abandonment activities expected within the next 12 months. Higher income taxes were due to higher pretax net income.

Capital Employed

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


	June 30, 2026				December 31, 2025
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,547.9	22.7	%	$	1,382.6	21.3	%
Murphy shareholders' equity	5,259.0		77.3	%	5,118.4		78.7	%
Total capital employed	$	6,806.9	100.0	%	$	6,501.0	100.0	%

At June 30, 2026, long-term debt of $1,547.9 million increased by $165.3 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 8.7 years and a weighted average coupon of 6.3%.

Murphy shareholders’ equity increased by $140.6 million in 2026, primarily due to net income ($285.2 million) and ($15.5 million) stock award amortization, partially offset by dividends ($100.3 million) and foreign currency translation ($54.6 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

As of June 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 June 30,				Six Months Ended June 30,
(Millions of dollars, except per share amounts)	2026		2025		2026		2025
Net income attributable to Murphy (GAAP) 1	$	232.2	$	22.3	$	285.2	$	95.3
Discontinued operations (income) loss	0.4		(1.3)		1.0		(0.7)
Net income from continuing operations attributable to Murphy	232.6		21.0		286.2		94.6
Adjustments:

Foreign exchange (gain) loss	(9.2)		34.3		(18.6)		34.3
Unrealized gain on derivative instruments	—		(10.3)		—		(1.4)
















Total adjustments, before taxes	(9.2)		24.0		(18.6)		32.9
Income tax (benefit) expense related to adjustments	2.4		(6.5)		4.8		(8.3)

Total adjustments, after taxes	(6.8)		17.5		(13.8)		24.6
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)	$	225.8	$	38.5	$	272.4	$	119.2

Net income from continuing operations per average diluted share (GAAP)	$	1.59	$	0.15	$	1.96	$	0.66
Adjusted net income from continuing operations per average diluted share (Non-GAAP)	$	1.55	$	0.27	$	1.87	$	0.83

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 June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Net income attributable to Murphy (GAAP) 1	$	232.2	$	22.3	$	285.2	$	95.3
Income tax expense	77.0		1.1		127.0		33.8
Interest expense, net	24.9		25.1		53.9		48.6
Depreciation, depletion and amortization expense 1	254.0		250.8		500.8		438.2
EBITDA attributable to Murphy (Non-GAAP) 1	$	588.1	$	299.3	$	966.9	$	615.9
Exploration expenses 1	39.3		10.3		122.1		24.8
EBITDAX attributable to Murphy (Non-GAAP) 1	$	627.4	$	309.6	$	1,089.0	$	640.7

EBITDA attributable to Murphy (Non-GAAP) 1	$	588.1	$	299.3	$	966.9	$	615.9

Foreign exchange (gain) loss	(9.2)		34.3		(18.6)		34.3
Accretion of asset retirement obligations 1	13.4		12.9		26.3		25.4
Unrealized gain on derivative instruments	—		(10.3)		—		(1.4)



Discontinued operations (income) loss	0.4		(1.3)		1.0		(0.7)






Adjusted EBITDA attributable to Murphy (Non-GAAP) 1	$	592.7	$	334.9	$	975.6	$	673.5
Exploration expenses 1	39.3		10.3		122.1		24.8
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1	$	632.0	$	345.2	$	1,097.7	$	698.3

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 June 30,				Six Months Ended June 30,
(Millions of dollars)	2026		2025		2026		2025
Net cash provided by continuing operations activities (GAAP)	$	655.9	$	358.1	$	977.1	$	658.7
Exclude: increase (decrease) in non-cash working capital	(67.5)		(30.7)		40.5		(7.9)
Operating cash flow excluding working capital adjustments (Non-GAAP)	588.4		327.4		1,017.6		650.8
Less: property additions and dry hole costs 1	(478.4)		(309.6)		(866.2)		(678.0)
Free cash flow (Non-GAAP)	$	110.0	$	17.8	$	151.4	$	(27.2)
Adjustments:
Cash dividends paid	(50.1)		(46.4)		(100.3)		(93.4)
Distributions to noncontrolling interest	(21.2)		(11.2)		(21.2)		(18.2)
Debt costs	(0.1)		—		(22.5)		—

Withholding tax on stock-based incentive awards	—		—		(7.8)		(7.7)
Acquisition of oil and natural gas properties	(0.8)		—		(23.5)		(1.4)
Adjusted free cash flow (Non-GAAP)	$	37.8	$	(39.8)	$	(23.9)	$	(147.9)

1 Property additions for the six months ended June 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 32, higher average crude oil and lower natural gas pricing during the second quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.

As of close on August 3, 2026 forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.



	2026	2027
WTI ($/BBL)	76.97	69.99
NYMEX ($/MMBTU)	3.09	3.38
AECO (US$ Equivalent/MCF)	1.35	1.69

The regional conflict involving Iran continues to contribute to heightened geopolitical risk and significant volatility in global energy and shipping markets, primarily due to disruptions affecting transit through the Strait of Hormuz, which is a critical passage for oil, LNG, and other refined products. Although these developments have led to higher commodity prices, these developments have also led to increased transportation and insurance costs, and broader uncertainty across global supply chains, which may indirectly affect the Company through fluctuations in oil and gas prices, changes in demand, and higher operating or input costs. During the period, the Company has not experienced direct physical disruption to its operations, and the Company’s financial and operating results have been favorably impacted by price volatility. Looking forward, a prolonged or escalating conflict could further disrupt global energy flows, exacerbate price volatility, constrain access to markets or services, and adversely affect macroeconomic conditions, which could materially impact the Company’s future operating results, cash flows, and financial position.

Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate. In July 2026, the Trump Administration imposed a 10% or 12.5% tariff on 60 trading partners pursuant to Section 301 of the Trade Act of 1974. Although we are continuing to monitor the economic effects of tariff announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

We cannot predict what impact economic factors (including, but not limited to, inflation, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations. Similarly, we cannot predict the impact that political instability or armed conflict in oil and natural gas producing regions, such as in Russia and Ukraine, the Middle East, and Venezuela, may have on pricing, global supply and demand for oil and gas. It is also uncertain how production quota decisions by OPEC and OPEC+, along with changes in membership, may influence pricing and the global supply–demand balance. Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.

For the third quarter of 2026, production is expected to average between 171.0 and 179.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company now expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million, compared with its prior guidance of $1,200 million to $1,300 million provided in the first quarter. This increase is driven primarily by additional capital related to the Bubale-1X (Block CI-709) discovery and the Bubale West-1X (Block CI-103) appraisal well, incremental Eagle Ford Shale activity, and higher-than-anticipated costs associated with Chinook #8 (Walker Ridge 425) drilling. Noncontrolling interest capital expenditures are expected to be $65 million.

In the Gulf of America, Murphy will continue developing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter of 2026. The Company currently expects these wells to begin production in the fourth quarter of 2027. In addition, the Company has initiated completion activities at the Chinook #8 (Walker Ridge 425) well, and expects the well to come online in the fourth quarter of 2026.

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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 exploration well at Bubale-1X (Block CI-709), and in July 2026 spud its first appraisal well, the Bubale West-1X (Block CI-103). The appraisal program is expected to include up to five wells over the next 18 to 24 months.

The Hai Su Vang (Golden Sea Lion) appraisal program in Vietnam has been completed following the completion of the Hai Su Vang-2X (Block 15-2/17) and Hai Su Vang-3X (Block 15-1/05) appraisal wells, which encountered hydrocarbons, and the Hai Su Vang-4X (Block 15-2/17) appraisal well, which did not and was expensed as a dry hole. The Company is evaluating development alternatives and progressing post-appraisal studies, with a final investment decision currently anticipated in the fourth quarter of 2027. In addition, in July the Company spud the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well. Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with first oil anticipated in the fourth quarter of 2026.

In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally. During the second quarter, Murphy progressed key agreements for offshore exploration blocks in Cameroon and submitted an application for offshore blocks in Mauritania, initiating discussions with the government. The Company anticipates finalizing the contracts in both countries in the second half of 2026.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, as well as changing commodity price environments, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2026 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

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

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

As of August 3, 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$2.81

7/1/2026

9/30/2026

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 current conflict in 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. Securities and Exchange Commission (SEC) and on page 46 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 June 30, 2026.

Foreign Exchange Risk

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

Interest Rate Risk

The Company’s senior unsecured Amended RCF provides for variable interest rate borrowings. As of June 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 June 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

During the three months ended June 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 August 5, 2020 (incorporated by reference to Exhibit 3.2 to Form 10-Q of Registrant filed on August 6, 2020)
10.36						Murphy Oil Corporation 2026 Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit A to definitive proxy statement of Registrant filed on March 27, 2026)
*10.37						Form of non-employee director time-based restricted stock unit grant agreement – A (2026 NED Plan )
*10.38						Form of non-employee director time-based restricted stock unit grant agreement – B (2026 NED Plan)


*31.1						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**32.1						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101. SCH						Inline XBRL Taxonomy Extension Schema Document
101. CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
101. LAB						Inline XBRL Taxonomy Extension Labels Linkbase Document
101. PRE						Inline XBRL Taxonomy Extension Presentation Linkbase
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Table of Contents

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)