mur-20260331

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 March 31, 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 April 30, 2026 was 143,349,576.

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			10

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			15
Note M – Accumulated Other Comprehensive Loss			17
Note N – Environmental and Other Contingencies			17
Note O – Common Stock Issued and Outstanding			19
Note P – Business Segments			20



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 3. Quantitative and Qualitative Disclosures About Market Risk			41
Item 4. Controls and Procedures			41
Part II – Other Information			42
Item 1. Legal Proceedings			42
Item 1A. Risk Factors			42

Item 5. Other Information			43
Item 6. Exhibits			43
Signature			44

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)	March 31, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	378,753	$	377,196
Accounts receivable, net	467,229		346,759
Inventories	58,428		57,284
Prepaid expenses	32,541		35,473

Total current assets	936,951		816,712
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $15,277,325 in 2026 and $15,068,149 in 2025	8,265,324		8,136,346
Operating lease assets	738,315		805,464

Deferred charges and other assets	95,044		74,104

Total assets	$	10,035,634	$	9,832,626
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	2,547	$	2,514
Accounts payable	645,829		572,183
Income taxes payable	19,690		18,209
Other taxes payable	30,418		28,295
Operating lease liabilities	270,214		278,834
Other accrued liabilities	111,858		120,755
Current asset retirement obligations	53,630		41,959
Total current liabilities	1,134,186		1,062,749
Long-term debt, including finance lease obligation	1,548,147		1,382,566
Asset retirement obligations	972,503		970,908
Deferred credits and other liabilities	256,209		263,596
Non-current operating lease liabilities	479,161		537,773
Deferred income taxes	412,548		378,337

Total liabilities	$	4,802,754	$	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 March 31, 2026 and 195,100,628 shares at December 31, 2025	195,101		195,101
Capital in excess of par value	837,327		859,633
Retained earnings	6,694,131		6,691,318
Accumulated other comprehensive loss	(576,572)		(554,227)
Treasury stock	(2,051,091)		(2,073,445)
Murphy Shareholders' Equity	5,098,896		5,118,380
Noncontrolling interest	133,984		118,317
Total equity	5,232,880		5,236,697
Total liabilities and equity	$	10,035,634	$	9,832,626

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars, except per share amounts)		2026		2025
Revenues and other income
Revenue from production		$	732,354	$	672,730

Total revenue from sales to customers		732,354		672,730
Gain (loss) on derivative instruments		—		(9,459)
Gain on sale of assets and other operating income		1,198		2,440
Total revenues and other income		733,552		665,711
Costs and expenses
Lease operating expenses		143,464		205,079
Severance and ad valorem taxes		13,746		8,650
Transportation, gathering and processing		47,061		48,851

Exploration expenses, including undeveloped lease amortization		82,815		14,488
Selling and general expenses		34,870		30,915

Depreciation, depletion and amortization		254,376		194,160
Accretion of asset retirement obligations		14,514		14,045

Other operating expense		4,441		5,629
Total costs and expenses		595,287		521,817
Operating income from continuing operations		138,265		143,894
Other income (loss)
Other income		9,852		2,402
Interest expense, net		(28,977)		(23,523)
Total other loss		(19,125)		(21,121)
Income from continuing operations before income taxes		119,140		122,773
Income tax expense		49,945		32,722
Income from continuing operations		69,195		90,051
Loss from discontinued operations, net of income taxes		(542)		(633)
Net income including noncontrolling interest		68,653		89,418
Less: Net income attributable to noncontrolling interest		15,667		16,382
NET INCOME ATTRIBUTABLE TO MURPHY		$	52,986	$	73,036
NET INCOME PER COMMON SHARE – BASIC
Continuing operations		$	0.37	$	0.51
Discontinued operations		—		—
Net income		$	0.37	$	0.51
NET INCOME PER COMMON SHARE – DILUTED
Continuing operations		$	0.37	$	0.50
Discontinued operations		—		—
Net income		$	0.37	$	0.50
Cash dividends per common share		$	0.350	$	0.325
Average common shares outstanding (thousands)
Basic		143,082		144,284
Diluted		144,381		145,072

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars)		2026		2025
Net income including noncontrolling interest		$	68,653	$	89,418
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		(23,746)		(1,667)
Retirement and postretirement benefit plans		1,401		864


Other comprehensive income (loss)		(22,345)		(803)
Comprehensive income including noncontrolling interest		46,308		88,615
Less: Comprehensive income (loss) attributable to noncontrolling interest		15,667		16,382
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY		$	30,641	$	72,233

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars)	2026		2025
Operating Activities
Net income including noncontrolling interest	$	68,653	$	89,418
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	254,376		194,160
Unsuccessful exploration well costs and previously suspended exploration costs	67,043		190
Deferred income tax expense	36,864		16,343
Accretion of asset retirement obligations	14,514		14,045
Long-term non-cash compensation	15,433		9,905
Amortization of undeveloped leases	2,270		1,654
Loss from discontinued operations	542		633
Unrealized loss on derivative instruments	—		8,916






Other operating activities, net	(30,539)		(11,799)
Net increase in non-cash working capital	(107,972)		(22,784)

Net cash provided by continuing operations activities	321,184		300,681
Investing Activities
Property additions and dry hole costs	(387,838)		(368,421)
Acquisition of oil and natural gas properties	(22,681)		(1,364)


Net cash required by investing activities	(410,519)		(369,785)
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	175,000		250,000
Repayment of revolving credit facility	(275,000)		(50,000)
Issue costs of revolving credit facility	(12,213)		—
Repurchase of common stock, including excise tax	(777)		(100,072)
Cash dividends paid	(50,173)		(47,026)
Distributions to noncontrolling interest	—		(6,955)
Withholding tax on stock-based incentive awards	(7,849)		(7,673)
Finance lease obligation payments	(419)		(116)


Net cash provided by financing activities	90,892		38,158






Effect of exchange rate changes on cash and cash equivalents	—		291
Net increase (decrease) in cash and cash equivalents	1,557		(30,655)
Cash and cash equivalents at beginning of period	377,196		423,569
Cash and cash equivalents at end of period	$	378,753	$	392,914

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

Table of Contents

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars except number of shares)		2026		2025

Common Stock
Balance at beginning and end of period – par $1.00, authorized 450,000,000 shares at March 31, 2026 and March 31, 2025, issued 195,100,628 shares at March 31, 2026 and March 31, 2025		$	195,101	$	195,101


Capital in Excess of Par Value
Balance at beginning of period		859,633		848,950

Restricted stock transactions and other		(30,185)		(27,338)
Share-based compensation		7,879		9,333

Balance at end of period		837,327		830,945
Retained Earnings
Balance at beginning of period		6,691,318		6,773,289
Net income attributable to Murphy		52,986		73,036


Cash dividends paid		(50,173)		(47,026)
Balance at end of period		6,694,131		6,799,299
Accumulated Other Comprehensive Loss
Balance at beginning of period		(554,227)		(628,072)
Foreign currency translation, net of income taxes		(23,746)		(1,667)
Retirement and postretirement benefit plans, net of income taxes		1,401		864


Balance at end of period		(576,572)		(628,875)
Treasury Stock
Balance at beginning of period		(2,073,445)		(1,995,018)
Repurchase of common stock		—		(100,876)
Awarded restricted stock, net of forfeitures		22,354		19,683

Balance at end of period – 51,751,915 shares of common stock at March 31, 2026 and 52,384,566 shares of common stock at March 31, 2025, at cost		(2,051,091)		(2,076,211)
Murphy Shareholders’ Equity		5,098,896		5,120,259
Noncontrolling Interest
Balance at beginning of period		118,317		147,593

Net income attributable to noncontrolling interest		15,667		16,382
Distributions to noncontrolling interest owners		—		(6,955)
Balance at end of period		133,984		157,020
Total Equity		$	5,232,880	$	5,277,279

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note A – Basis of Presentation

The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at March 31, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 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-month period ended March 31, 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 impacts 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

Table of Contents

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-month periods ended March 31, 2026 and 2025 were as follows.


	Three Months Ended March 31,
(Thousands of dollars)				2026			2025
Net crude oil and condensate revenue
United States - Onshore		$	188,348		$	109,458
United States - Offshore 1		333,441			352,362
Canada - Onshore		17,391			14,730
Canada - Offshore		53,336			74,469
Other		2,909			—
Total crude oil and condensate revenue		595,425			551,019
Net natural gas liquids revenue
United States - Onshore		9,275			8,487
United States - Offshore 1		6,363			9,249
Canada - Onshore		1,318			1,747
Total natural gas liquids revenue		16,956			19,483
Net natural gas revenue
United States - Onshore		11,128			7,967
United States - Offshore 1		26,150			19,941
Canada - Onshore		82,695			74,320
Total natural gas revenue		119,973			102,228







Total revenue from sales to customers		732,354			672,730
Gain (loss) on derivative instruments		—			(9,459)
Gain on sale of assets and other operating income		1,198			2,440
Total revenues and other income		$	733,552		$	665,711

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

Contract Balances and Asset Recognition

As of March 31, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $222.1 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

Table of Contents

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 March 31, 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 March 31, 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

10 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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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 March 31, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $266.8 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2026 and 2025.


(Thousands of dollars)	2026		2025
Beginning balance at January 1	$	191,821	$	72,055
Additions pending the determination of proved reserves	84,599		24,790

Capitalized exploratory well costs charged to expense	(9,610)		—
Balance at March 31	$	266,810	$	96,845

Capital additions of $84.6 million, for the three months ended March 31, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire; the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in Vietnam; and the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America. 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 also 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 $24.8 million, for the three months ended March 31, 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 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America.

In the first quarter of 2026, the Company also announced the results of two exploration wells in Côte d’Ivoire; the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and the Caracal-1X (Block CI-102) exploration well, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. Capitalized well costs charged to dry hole expense of $9.6 million, for the three months ended March 31, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire. There were no capitalized well costs charged to dry hole expense for the three months ended March 31, 2025.

The preceding table excludes well costs of $57.5 million incurred and expensed directly to dry hole for the three months ended March 31, 2026. In 2026, these costs primarily related to the Caracal-1X (Block CI-102) and Civette-1X (Block CI-502) exploration wells in Côte d’Ivoire.

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


	March 31,
	2026			2025

(Thousands of dollars)	Amount		No. of Projects		Amount		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	58,556	1		$	9,421	2
One to two years	71,906		2		65,160		3
Two to three years	113,934		3		—		—
Three years or more	22,414		3		22,264		3
	$	266,810	9		$	96,845	8

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

Of the $208.3 million of exploration well costs capitalized and classified as more than one year at March 31, 2026, $107.0 million was in Vietnam, $94.0 million was in the Gulf of America, $4.6 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Property Additions

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 months ended March 31, 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 SOFR Rate” 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 March 31, 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 March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%. At March 31, 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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows


	Three Months Ended March 31,
(Thousands of dollars)	2026		2025
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(120,525)	$	(10,089)
(Increase) decrease in inventories	(479)		(15,851)
(Increase) decrease in prepaid expenses	2,799		10,502
Increase (decrease) in accounts payable and accrued liabilities	8,752		(13,560)
Increase (decrease) in income taxes payable	1,481		6,214
Net (increase) decrease in non-cash working capital	$	(107,972)	$	(22,784)

Supplementary disclosures:

Interest paid, net of amounts capitalized of $3.9 million in 2026 and $1.1 million in 2025	$	4,897	$	6,347

Non-cash investing activities:
Asset retirement costs capitalized	$	8,843	$	8,996
(Increase) decrease in capital expenditure accrual	(54,000)		(42,442)

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 three-month periods ended March 31, 2026 and 2025 are shown in the following table.


(Thousands of dollars)	March 31, 2026		March 31, 2025
Balance at beginning of year	$	1,012,867	$	1,008,884
Accretion	14,514		14,045
Liabilities incurred	10,064		4,996

Revisions of previous estimates	—		3,999
Liabilities settled	(8,941)		(157)



Changes due to translation of foreign currencies	(2,371)		394
Balance at end of period	1,026,133		1,032,161
Current portion of liability	(53,630)		(77,452)
Non-current portion of liability	$	972,503	$	954,709

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

Table of Contents

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-month periods ended March 31, 2026 and 2025.


	Three Months Ended March 31,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2026		2025		2026		2025
Service cost	$	1,865	$	1,683	$	102	$	84
Interest cost	7,752		8,398		750		708
Expected return on plan assets	(8,792)		(8,871)		—		—
Estimated defined contribution provision	70		60		—		—
Amortization of prior service cost (credit)	432		491		(133)		(133)
Recognized actuarial (gain) loss	1,644		1,891		(387)		(1,056)



Total net periodic benefit cost (credit)	$	2,971	$	3,652	$	332	$	(397)

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

During the three-month period ended March 31, 2026, the Company made contributions of $7.0 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 $22.5 million.

Note I – Incentive Plans

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

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

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

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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

During the three months ended March 31, 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.

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

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

During the three months ended March 31, 2026, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Time-Based RSUs 1

56,844

February 4, 2026

31.67

Closing Stock Price

Time-Based RSUs 2

2,150

March 31, 2026

41.25

Closing Stock Price

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

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

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


	Three Months Ended March 31,
(Thousands of dollars)	2026		2025
Compensation charged against income before tax benefit	$	13,900	$	8,864
Related income tax benefit recognized in income	2,279		1,175

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.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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-month periods ended March 31, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31,
(Weighted-average shares, except per share amounts)		2026		2025
Basic method		143,081,801		144,283,946
Dilutive restricted stock units		1,298,790		788,142
Diluted method		144,380,590		145,072,088

NET INCOME PER COMMON SHARE – BASIC		$	0.37	$	0.51



NET INCOME PER COMMON SHARE – DILUTED		$	0.37	$	0.50

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-month periods ended March 31, 2026 and 2025, the Company’s effective income tax rates were as follows:


	2026	2025
Three months ended March 31,	41.9%	26.7%

The effective tax rate for the three-month period ended March 31, 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-month period ended March 31, 2025 was above the U.S. statutory tax rate of 21% primarily due to several factors including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; stock-based compensation; 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.

For the three-month period ended March 31, 2026, the Company received $0.1 million in net cash income tax refunds, compared to $1.6 million in net cash income tax refunds for the three-month period ended March 31, 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 March 31, 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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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 March 31, 2026 and 2025.

Commodity Price Risks

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

During the three months ended March 31, 2026, the Company did not have any crude oil or natural gas derivative contracts. At March 31, 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

3.58

4/1/2025

6/30/2025

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

For the three-month periods ended March 31, 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 March 31,
Type of Derivative Contract	Statement of Operations Location		2026		2025
Commodity swaps	Gain (loss) on derivative instruments		$	—	$	(9,459)

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


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





Liabilities:


Nonqualified employee savings plan	$	21,947	$	—	$	—	$	21,947	$	22,205	$	—	$	—	$	22,205
	$	21,947	$	—	$	—	$	21,947	$	22,205	$	—	$	—	$	22,205

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

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 March 31, 2026 and December 31, 2025.

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


	March 31, 2026				December 31, 2025
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,550,694	$	1,468,657	$	1,385,080	$	1,326,101

Fair Values – Nonrecurring

There were no impairment charges incurred in the three months ended March 31, 2026 and 2025.

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and March 31, 2026, and the changes during the three-month period ended March 31, 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	(23,746)		—		(23,746)
Reclassifications to income ¹	—		1,401		1,401
Net other comprehensive income (loss)	(23,746)		1,401		(22,345)
Balance at March 31, 2026	$	(466,077)	$	(110,495)	$	(576,572)

1 Reclassifications before taxes of $1.7 million are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2026. See Note H for additional information. Related income taxes of $0.3 million are included in "Income tax expense” on the Consolidated Statements of Operations for the three-month period ended March 31, 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;

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.

ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other greenhouse gas (GHG) emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased.

Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $1.0 million threshold.

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

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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 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 three-month periods ended March 31, 2026 and 2025 is shown below.


(Number of shares outstanding)	March 31, 2026	March 31, 2025
Beginning of period	142,785,152	145,845,124

Restricted stock awards 1	563,561	484,388

Treasury shares purchased	—	(3,613,450)
End of period	143,348,713	142,716,062

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

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

During the three months ended March 31, 2026, the Company did not repurchase any shares of its common stock. During the three months ended March 31, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.9 million including excise taxes and fees). As of March 31, 2026, the Company had $550.1 million of its common stock remaining available to repurchase under the program.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments

Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate 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.

Table of Contents

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 March 31, 2026
Revenue from production	$	574.7	$	154.8	$	2.9	$	732.4	$	—	$	732.4

Gain on sale of assets and other operating income	0.8		0.4		—		1.2		—		1.2
Total revenues and other income	575.5		155.2		2.9		733.6		—		733.6
Lease operating expenses
Lease operating expenses and taxes other than income	80.8		41.8		0.8		123.4		—		123.4
Repair and maintenance	12.3		0.7		—		13.0		—		13.0
Workovers	4.7		2.4		—		7.1		—		7.1
Total lease operating expenses	97.8		44.9		0.8		143.5		—		143.5
Severance and ad valorem taxes	12.9		0.8		—		13.7		—		13.7
Transportation, gathering and processing	25.2		21.9		—		47.1		—		47.1

Selling and general expenses	5.5		7.5		2.1		15.1		19.8		34.9
Exploration Expenses
Geological and geophysical	0.8		—		0.8		1.6		—		1.6
Dry holes and previously suspended exploration costs	—		—		67.1		67.1		—		67.1
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	4.9		—		9.2		14.1		—		14.1
Total exploration expenses	5.7		—		77.1		82.8		—		82.8
Depreciation, depletion and amortization	216.9		34.0		1.1		252.0		2.4		254.4

Accretion of asset retirement obligations	11.6		2.6		0.2		14.4		0.1		14.5

Other operating expenses	4.0		0.1		0.3		4.4		—		4.4


Interest Income	(0.2)		—		—		(0.2)		(2.3)		(2.5)
Interest expense, net of capitalization	0.1		0.1		—		0.2		28.8		29.0
Income tax expense
Current income tax expense	1.0		9.6		0.3		10.9		2.2		13.1
Deferred income tax expense (benefit)	37.3		1.6		3.4		42.3		(5.5)		36.8
Total income tax expense (benefit)	38.3		11.2		3.7		53.2		(3.3)		49.9
Other segment costs (income)	1.1		0.4		0.3		1.8		(8.6)		(6.8)
Segment income (loss) - including NCI 1	$	156.6	$	31.7	$	(82.7)	$	105.6	$	(36.9)	$	68.7

Additions to property, plant, equipment	$	254.8	$	62.1	$	71.3	$	388.2	$	9.3	$	397.5
Total assets at quarter-end	6,916.5		1,980.3		660.7		9,557.5		478.1		10,035.6

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

Table of Contents

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 March 31, 2025
Revenue from production	$	507.4	$	165.3	$	—	$	672.7	$	—	$	672.7

Gain on sale of assets and other operating income (loss)	2.1		0.4		—		2.5		(9.5)		(7.0)
Total revenues and other income	509.5		165.7		—		675.2		(9.5)		665.7
Lease operating expenses
Lease operating expenses and taxes other than income	100.3		45.2		0.4		145.9		—		145.9
Repair and maintenance	10.2		1.6		—		11.8		—		11.8
Workovers	47.1		0.3		—		47.4		—		47.4
Total lease operating expenses	157.6		47.1		0.4		205.1		—		205.1
Severance and ad valorem taxes	8.4		0.3		—		8.7		—		8.7
Transportation, gathering and processing	28.7		20.2		—		48.9		—		48.9

Selling and general expenses	2.0		6.0		1.9		9.9		21.0		30.9
Exploration Expenses
Geological and geophysical	3.2		—		0.3		3.5		—		3.5
Dry holes and previously suspended exploration costs	0.2		—		—		0.2		—		0.2
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	2.7		0.1		8.0		10.8		—		10.8
Total exploration expenses	6.1		0.1		8.3		14.5		—		14.5
Depreciation, depletion and amortization	159.4		32.4		0.1		191.9		2.3		194.2

Accretion of asset retirement obligations	11.3		2.5		0.2		14.0		—		14.0

Other operating expenses	2.6		0.9		0.1		3.6		2.0		5.6


Interest Income	(0.4)		—		—		(0.4)		(3.3)		(3.7)
Interest expense, net of capitalization	—		—		—		—		23.5		23.5
Income tax expense
Current income tax expense	0.5		13.7		—		14.2		2.1		16.3
Deferred income tax expense (benefit)	24.5		0.6		—		25.1		(8.7)		16.4
Total income tax expense (benefit)	25.0		14.3		—		39.3		(6.6)		32.7
Other segment costs	0.9		0.4		0.2		1.5		0.4		1.9
Segment income (loss) - including NCI 1	$	107.9	$	41.5	$	(11.2)	$	138.2	$	(48.8)	$	89.4

Additions to property, plant, equipment	$	317.1	$	55.4	$	35.3	$	407.8	$	4.2	$	412.0
Total assets at quarter-end	7,046.3		1,963.4		345.7		9,355.4		464.9		9,820.3

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

Table of Contents

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the quarter ended March 31, 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 first quarter of 2026 were as follows:

•Increased production to 180,053 barrels of oil equivalent (BOE) per day (including NCI), up from 163,374 BOE per day in the first quarter of 2025;

•Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced dry holes at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire;

•Issued $500.0 million of 6.50% senior notes due 2034 (2034 Notes) and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;

•Upsized senior unsecured revolving credit facility from $1.35 billion to $2.0 billion and extended maturity from 2029 to 2031;

•Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.

Subsequent to the first quarter, the Company’s offer for four exploration blocks in offshore Cameroon was accepted, with finalization of the terms pending further discussions with the Republic of Cameroon.

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2026, was $69.2 million compared to net income of $90.1 million for the same period in 2025. The results for 2026 were impacted by higher exploration expense ($68.3 million), higher depreciation, depletion and amortization expenses (DD&A) ($60.2 million), and higher income tax expense ($17.2 million) and were partially offset by higher revenues from production ($59.6 million), lower lease operating expenses ($61.6 million), and lower losses from derivative instruments ($9.5 million).

Higher exploration expenses in the current quarter 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. Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S. and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S. and offshore Canada. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, certain exploration expenses did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available. Higher volumes in the Eagle Ford Shale and onshore Canada were the primary contributors to higher revenues for the period and were partially offset by lower volumes in other segments. Higher realized prices onshore U.S. and both onshore and offshore Canada also contributed to the increase but were partially offset by lower realized prices offshore U.S. Lower lease operating expenses are due to lower

Table of Contents

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

Overview (Continued)

workover costs in the current quarter. Lower losses from derivative instruments were due to having no open derivative contracts during the first quarter of 2026.

For the three months ended March 31, 2026, total hydrocarbon production was 180,053 barrels of oil equivalent per day, an increase of 10% compared to the first quarter of 2025. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in the Gulf of America. Higher production in the Eagle Ford Shale and Canada Onshore was primarily the result of new wells online in the current year at Karnes and Catarina in the U.S., and at Tupper Montney in Canada. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.

At March 31, 2026, the West Texas Intermediate (WTI) crude oil futures price were $82.75 per barrel, whereas the crude oil futures price at the end of April 2026 was $90.56, reflecting a 9% increase in price. As of May 4, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $93.58 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 March 31,
(Millions of dollars)			2026		2025
Exploration and production
United States			$	156.6	$	107.9
Canada			31.7		41.5
Other			(82.7)		(11.2)
Total exploration and production			105.6		138.2
Corporate and other			(36.4)		(48.2)
Income from continuing operations			69.2		90.0
Discontinued operations, net of tax 1			(0.5)		(0.6)
Net income including noncontrolling interest			68.7		89.4
Less: Net income attributable to noncontrolling interest			15.7		16.4
Net income attributable to Murphy			$	53.0	$	73.0

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.

Table of Contents

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 March 31,
(Millions of dollars)		2026		2025
Revenues and other income
Revenue from production		$	732.4	$	672.7

Other income		1.2		2.5
Total revenues and other income		733.6		675.2
Costs and expenses
Lease operating expenses		143.5		205.1
Severance and ad valorem taxes		13.7		8.7
Transportation, gathering and processing		47.1		48.9

Depreciation, depletion and amortization		252.0		191.8

Accretion of asset retirement obligations		14.4		14.0
Exploration expenses, including undeveloped lease amortization		82.8		14.5
Selling and general expenses		15.1		9.9
Other		6.2		4.8
Results of operations before taxes		158.8		177.5
Income tax provisions		53.2		39.3
Results of operations (excluding Corporate segment) 1		$	105.6	$	138.2

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

Table of Contents

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

Results of Operations (Continued)

Pricing

The following table contains the weighted average sales prices for the three-month periods ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(Weighted average sales prices)		2026		2025
Crude oil and condensate – dollars per barrel
United States - Onshore		$	73.44	$	71.65
United States - Offshore 1		70.97		72.32
Canada - Onshore 2		65.89		63.34
Canada - Offshore 2		78.19		74.36
Other 2		71.04		—
Natural gas liquids – dollars per barrel
United States - Onshore		17.60		23.16
United States - Offshore 1		16.45		27.02
Canada - Onshore 2		27.73		36.08
Natural gas – dollars per thousand cubic feet
United States - Onshore		3.74		3.38
United States - Offshore 1		5.68		4.33
Canada - Onshore 2		2.44		2.38

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

2 U.S. dollar equivalent.

The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(Average price for the period)		2026		2025
Oil and NGLs
WTI ($/BBL)		$	71.93	$	71.42
Natural gas
NYMEX ($/MMBTU)		4.87		4.27
AECO (C$/MCF)		2.01		2.17

Table of Contents

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

Results of Operations (Continued)

Production Volumes

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.


	Three Months Ended March 31,
(Barrels per day unless otherwise noted)		2026	2025

Net crude oil and condensate
United States - Onshore		28,497	16,974
United States - Offshore 1		51,839	55,587
Canada - Onshore		2,932	2,584
Canada - Offshore		9,006	8,855
Other		224	255
Total net crude oil and condensate		92,498	84,255
Net natural gas liquids
United States - Onshore		5,856	4,072
United States - Offshore 1		4,298	3,804
Canada - Onshore		528	538
Total net natural gas liquids		10,682	8,414
Net natural gas – thousands of cubic feet per day
United States - Onshore		33,082	26,190
United States - Offshore 1		51,153	51,150
Canada - Onshore		377,001	346,892
Total net natural gas		461,236	424,232
Total net hydrocarbons - including NCI 2,3		180,053	163,374
Noncontrolling interest
Net crude oil and condensate – barrels per day		(5,281)	(5,779)
Net natural gas liquids – barrels per day		(226)	(170)
Net natural gas – thousands of cubic feet per day		(1,857)	(1,234)
Total noncontrolling interest 2,3		(5,817)	(6,154)
Total net hydrocarbons - excluding NCI 2,3		174,236	157,220

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.

Table of Contents

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

Results of Operations (Continued)

Sales Volumes

The following table contains hydrocarbons sold during the three-month periods ended March 31, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.


	Three Months Ended March 31,
(Barrels per day unless otherwise noted)		2026	2025
Net crude oil and condensate
United States - Onshore		28,497	16,974
United States - Offshore 1		52,205	54,133
Canada - Onshore		2,932	2,584
Canada - Offshore		7,579	11,128
Other		455	—
Total net crude oil and condensate		91,668	84,819
Net natural gas liquids
United States - Onshore		5,856	4,072
United States - Offshore 1		4,298	3,804
Canada - Onshore		528	538
Total net natural gas liquids		10,682	8,414
Net natural gas – thousands of cubic feet per day
United States - Onshore		33,082	26,190
United States - Offshore 1		51,153	51,150
Canada - Onshore		377,001	346,892
Total net natural gas		461,236	424,232
Total net hydrocarbons - including NCI 2,3		179,223	163,938
Noncontrolling interest
Net crude oil and condensate – barrels per day		(5,333)	(5,567)
Net natural gas liquids – barrels per day		(226)	(170)
Net natural gas – thousands of cubic feet per day		(1,857)	(1,234)
Total noncontrolling interest 2,3		(5,869)	(5,942)
Total net hydrocarbons - excluding NCI 2,3		173,354	157,996

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.

Table of Contents

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 March 31,
(Millions of dollars)		2026		2025
Revenues from production
United States - Oil		$	521.8	$	461.8
United States - Natural gas liquids		15.6		17.8
United States - Natural gas		37.3		27.9
Canada - Oil		70.8		89.2
Canada - Natural gas liquids		1.3		1.7
Canada - Natural gas		82.7		74.3
Other - Oil		2.9		—
Total revenue from production		$	732.4	$	672.7

Revenues from production for the three months ended March 31, 2026, increased $59.6 million compared to the same period in 2025. New wells in the Karnes and Catarina fields in the Eagle Ford Shale were the primary contributor to higher revenues for the period, contributing both higher volumes and realized prices. Canada also realized higher prices, but overall revenues were lower due to fewer cargoes offshore Canada compared to 2025. In the Gulf of America, both production and realized prices were lower compared to the first quarter of 2025. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

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 March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
			2026		2025		2026		2025
Lease operating expenses
United States - Onshore			$	32.4	$	29.8	$	9.02	$	13.02
United States - Offshore			65.4		127.8		11.17		21.37
Canada - Onshore			33.0		30.2		5.53		5.51
Canada - Offshore			11.9		16.9		17.42		16.89
Other			0.8		0.4		19.55		—
Total lease operating expenses			$	143.5	$	205.1	$	8.89	$	13.90
Transportation, gathering and processing
United States - Onshore			$	2.7	$	2.4	$	0.76	$	1.00
United States - Offshore			22.5		26.4		3.84		4.42
Canada - Onshore			20.5		18.3		3.43		3.34
Canada - Offshore			1.4		1.8		2.02		1.80

Total transportation, gathering and processing			$	47.1	$	48.9	$	2.92	$	3.31

Table of Contents

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

Results of Operations (Continued)

For the three months ended March 31, 2026, lease operating expenses decreased by $61.6 million, and transportation, gathering and processing expenses decreased by $1.8 million compared to the same period in 2025. Lower lease operating expenses are due to lower workover costs in the Gulf of America in the current quarter, particularly at the Samurai field. Further decreases in the Gulf of America are attributable to lower vessel rental costs as a result of the purchase of the Pioneer FPSO in 2025. Offshore Canada realized lower operating costs in the current quarter due to fewer cargoes in 2026 compared to 2025.

Depreciation, Depletion and Amortization Expenses

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


	Three Months Ended March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
			2026		2025		2026		2025
DD&A
United States - Onshore			$	113.3	$	67.1	$	31.58	$	29.35
United States - Offshore			103.6		92.2		17.69		15.42
Canada - Onshore			26.3		24.1		4.42		4.40
Canada - Offshore			7.7		8.3		11.22		8.26
Other			1.1		0.1		26.95		—
Total DD&A			$	252.0	$	191.8	$	15.62	$	13.00

DD&A for the three months ended March 31, 2026 increased by $60.2 million. Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S. and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S. and offshore Canada.

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended March 31,
(Millions of dollars)		2026		2025
Exploration expenses
Dry holes and previously suspended exploration costs		$	67.1	$	0.2
Geological and geophysical		1.6		3.6
Other exploration		11.8		9.1
Undeveloped lease amortization		2.3		1.6
Total exploration expenses, including undeveloped lease amortization		$	82.8	$	14.5

Exploration expenses for the three months ended March 31, 2026 increased by $68.3 million compared to the same period in 2025. Higher exploration expenses in the current quarter 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.

Income Taxes

Income taxes for the three months ended March 31, 2026 increased by $13.9 million compared to the same period 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.

Table of Contents

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

Results of Operations (Continued)

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 $36.4 million for the three months ended March 31, 2026, a favorable variance of $11.8 million, compared to the same period in 2025. The favorable variance was primarily due to no losses on derivative instruments ($9.5 million) in the current quarter and higher foreign exchange gains ($8.8 million). These changes were partially offset by higher interest expense ($5.3 million) due to costs related to 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.

Cash Flows

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


	Three Months Ended March 31,
(Millions of dollars)	2026		2025
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	321.2	$	300.7
Net cash required by investing activities	(410.5)		(369.8)
Net cash provided by financing activities	90.9		38.2

Effect of exchange rate changes on cash and cash equivalents	—		0.3
Net increase (decrease) in cash and cash equivalents	$	1.6	$	(30.7)

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the three months ended March 31, 2026 was $20.5 million higher compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized prices and volumes resulting in higher revenue from production ($59.6 million) and lower lease operating expenses ($61.6 million), partially offset by the timing of net non-cash working capital ($85.2 million) and changes in other operating activities, net ($18.7 million), primarily due to fluctuations in foreign exchange rates ($8.9 million) and higher expenditures for asset retirements ($8.8 million).

Cash Required by Investing Activities

Net cash required by investing activities for the three months ended March 31, 2026 was $40.7 million higher compared to the same period in 2025. The increase was primarily due to higher acquisition capital ($21.3 million) and higher property additions and dry hole costs ($19.4 million).

Table of Contents

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

Financial Condition (Continued)

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


	Three Months Ended March 31,
(Millions of dollars)	2026		2025
Property additions and dry hole costs	$	387.8	$	368.4

Acquisition of oil and natural gas properties	22.7		1.4
Geophysical and other exploration expenses	13.4		11.6
Capital expenditure accrual changes and other	54.0		43.4
Total capital expenditures	$	477.9	$	424.8

Total accrual basis capital expenditures are shown below.


	Three Months Ended March 31,
(Millions of dollars)	2026		2025
Capital Expenditures
Exploration and production	$	468.8	$	420.6
Corporate	9.1		4.2
Total capital expenditures	$	477.9	$	424.8

Higher capital expenditures in the three months ended March 31, 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 drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower field development costs in the Gulf of America due to the prior year spend on the Pioneer FPSO purchase in the Gulf of America.

Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($105.8 million), Eagle Ford Shale ($98.9 million), Tupper Montney and Kaybob Duvernay ($54.8 million), and in Vietnam ($24.0 million). Exploration costs in 2026 were $178.1 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. 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, and activities in Vietnam for the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 exploration well.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2026 increased by $52.7 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), cash dividends to shareholders of $0.350 per share ($50.2 million), and $20.0 million in debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance.

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

Table of Contents

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

Financial Condition (Continued)

Liquidity

At March 31, 2026, the Company had approximately $2.4 billion of liquidity consisting of $378.8 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 March 31, 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 March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%. At March 31, 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 March 31, 2026, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $94.6 million, the majority of which was held in Canada ($35.2 million), Côte d'Ivoire ($24.8 million), Vietnam ($10.5 million), Mexico ($7.9 million), Brunei ($6.9 million), and the U.K. ($6.3 million) . In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

Working Capital


(Millions of dollars)	March 31, 2026		December 31, 2025
Working capital
Total current assets	$	937.0	$	816.7
Total current liabilities	1,134.2		1,062.7
Net working capital liability	$	(197.2)	$	(246.0)

As of March 31, 2026, net working capital increased by $48.8 million compared to December 31, 2025. The increase was primarily attributable to higher accounts receivable ($120.5 million) and lower current operating lease obligations ($8.6 million), partially offset by higher accounts payable ($73.6 million).

Higher accounts receivable and accounts payable were due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively. Lower lease obligations were due to lower day rates related to an offshore drilling rig, ongoing lease amortization and the absence of lease rental payments related to the Pioneer FPSO in the Gulf of America.

Capital Employed

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


	March 31, 2026				December 31, 2025
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,548.1	23.3	%	$	1,382.6	21.3	%
Murphy shareholders' equity	5,098.9		76.7	%	5,118.4		78.7	%
Total capital employed	$	6,647.0	100.0	%	$	6,501.0	100.0	%

At March 31, 2026, long-term debt of $1,548.1 million increased by $165.5 million compared to December 31, 2025, primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.9 years and a weighted average coupon of 6.2%.

Murphy shareholders’ equity decreased by $19.5 million in 2026, primarily due to dividends ($50.2 million), foreign currency translation ($23.7 million), partially offset by net income ($53.0 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Table of Contents

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

Critical Accounting Estimates

As of March 31, 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.

Table of Contents

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 March 31,
(Millions of dollars, except per share amounts)		2026		2025
Net income attributable to Murphy (GAAP) 1		$	53.0	$	73.0
Discontinued operations loss		0.5		0.6
Net income from continuing operations attributable to Murphy		53.5		73.6
Adjustments:

Foreign exchange gain		(9.4)		—
Unrealized loss on derivative instruments		—		8.9
















Total adjustments, before taxes		(9.4)		8.9
Income tax (benefit) expense related to adjustments		2.4		(1.8)

Total adjustments, after taxes		(7.0)		7.1
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)		$	46.5	$	80.7

Net income from continuing operations per average diluted share (GAAP)		$	0.37	$	0.50
Adjusted net income from continuing operations per average diluted share (Non-GAAP)		$	0.32	$	0.56

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

Table of Contents

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 March 31,
(Millions of dollars)		2026		2025
Net income attributable to Murphy (GAAP) 1		$	53.0	$	73.0
Income tax expense		49.9		32.7
Interest expense, net		29.0		23.5
Depreciation, depletion and amortization expense 1		246.9		187.4
EBITDA attributable to Murphy (Non-GAAP) 1		$	378.8	$	316.6
Exploration expenses 1		82.8		14.5
EBITDAX attributable to Murphy (Non-GAAP) 1		$	461.6	$	331.1

EBITDA attributable to Murphy (Non-GAAP) 1		$	378.8	$	316.6

Foreign exchange gain		(9.4)		—
Accretion of asset retirement obligations 1		13.0		12.5
Unrealized loss on derivative instruments		—		8.9



Discontinued operations loss		0.5		0.6






Adjusted EBITDA attributable to Murphy (Non-GAAP) 1		$	382.9	$	338.6
Exploration expenses 1		82.8		14.5
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1		$	465.7	$	353.1

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

Table of Contents

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 March 31,
(Millions of dollars)		2026		2025
Net cash provided by continuing operations activities (GAAP)		$	321.2	$	300.7
Exclude: increase in non-cash working capital		108.0		22.8
Operating cash flow excluding working capital adjustments (Non-GAAP)		429.2		323.5
Less: property additions and dry hole costs 1		(387.8)		(368.4)
Free cash flow (Non-GAAP)		$	41.4	$	(44.9)
Less: cash dividends paid		(50.2)		(47.0)
Less: distributions to noncontrolling interest		—		(7.0)
Less: debt costs		(22.4)		—

Less: withholding tax on stock-based incentive awards		(7.8)		(7.7)
Less: acquisition of oil and natural gas properties		(22.7)		(1.4)
Adjusted free cash flow (Non-GAAP)		$	(61.7)	$	(108.0)

1 Property additions for the three months ended March 31, 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.

Table of Contents

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

As of close on May 4, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.



	2026	2027
WTI ($/BBL)	93.58	76.88
NYMEX ($/MMBTU)	3.39	3.64
AECO (US$ Equivalent/MCF)	1.37	1.79

The regional conflict involving Iran has contributed 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. 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.

On July 4, 2025, the current U.S. Administration signed into law the OBBBA legislation, which includes a broad range of tax reform provisions affecting corporations. The Company evaluated the effects of the OBBBA in accordance with ASC 740, Income Taxes, and determined that the legislation did not have a material impact on its consolidated financial statements for the period ended March 31, 2026. The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA.

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 second quarter of 2026, production is expected to average between 161.0 and 169.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.

The Company’s capital expenditures for 2026 are expected to be between $1,200 million and $1,300 million, excluding noncontrolling interest. This range excludes noncontrolling interest of $53.0 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. In addition, the Company commenced drilling at the Chinook #8 (Walker Ridge 425) development well.

Table of Contents

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

Outlook (Continued)

The Company commenced drilling on its third Côte d’Ivoire exploration well, Bubale-1X (Block CI-709), during the first quarter, with results expected in the second quarter.

The appraisal program at the Hai Su Vang (Golden Sea Lion) prospect in Vietnam is continuing on schedule following the successful completion of the Hai Su Vang-2X (Block 15-2/17) appraisal well in the first quarter. Also in the first quarter, the Company began drilling the Hai Su Vang-3X (Block 15-1/05) appraisal well. Hai Su Vang-3X is then expected to be followed by the Hai Su Vang-4X (Block 15-2/17) appraisal well.

Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with scheduled first oil anticipated in the fourth quarter of 2026.

Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, 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 March 31, 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 May 4, 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$2.94

4/1/2026

6/30/2026

Canada

Natural Gas

Fixed price forward sales

C$2.94

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.

Table of Contents

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 42 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.

Table of Contents

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 March 31, 2026.

Foreign Exchange Risk

There were no derivative foreign exchange contracts in place at March 31, 2026.

Interest Rate Risk

The Company’s senior unsecured Amended RCF provides for variable interest rate borrowings. As of March 31, 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 March 31, 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.

Table of Contents

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.

Table of Contents

ITEM 5. OTHER INFORMATION

During the three months ended March 31, 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)
4 .1						Eighth Supplemental Indenture, dated as of January 23, 2026, between Murphy Oil Corporation and Regions Bank, as trustee (including the Form of 6.500% Notes due 2034) (inc orporate d by reference to Exhibit 4.2 to Form 8-K of Re gistrant filed on January 23, 2026)
1 0.1						Second Amendment to the Credit Agreement dated as of January 2, 2026 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd. as borrowers, Murphy Exploration & Production Company and Murphy Exploration & Production Company – USA, as guarantors, JP Morgan Chase Bank, N.A. as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K of Registrant filed on January 6 , 2026)
*31.1						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2						Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
**32.1						Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101. INS						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101. SCH						Inline XBRL Taxonomy Extension Schema Document
101. CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
101. LAB						Inline XBRL Taxonomy Extension Labels Linkbase Document
101. PRE						Inline XBRL Taxonomy Extension Presentation Linkbase
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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)