Murphy Oil - 10-Q quarterly report FY2025 Q1

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2025


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

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


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

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


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

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

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

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

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at April 30, 2025 was 142,716,062.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


			Page
Part I – Financial Information			2
Item 1. Financial Statements			2
Consolidated Balance Sheets			2
Consolidated Statements of Operations			3
Consolidated Statements of Comprehensive Income			4
Consolidated Statements of Cash Flows			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Note A – Basis of Presentation			7
Note B – New Accounting Principles and Recent Accounting Pronouncements			7
Note C – Revenue from Contracts with Customers			8
Note D – Property, Plant and Equipment			10

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



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23





Item 3. Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. Controls and Procedures			39
Part II – Other Information			40
Item 1. Legal Proceedings			40
Item 1A. Risk Factors			40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 5. Other Information			41
Item 6. Exhibits			41
Signature			42

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, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	392,914	$	423,569
Accounts receivable, net	282,249		272,530
Inventories	71,048		54,858
Prepaid expenses	25,200		34,322

Total current assets	771,411		785,279
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $14,007,994 in 2025 and $13,811,539 in 2024	8,279,284		8,054,653
Operating lease assets	714,091		777,536

Deferred charges and other assets	55,537		50,011

Total assets	$	9,820,323	$	9,667,479
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease	$	892	$	871
Accounts payable	538,290		472,165
Income taxes payable	25,217		19,003
Other taxes payable	32,874		31,685
Operating lease liabilities	243,232		253,208
Other accrued liabilities	90,566		117,802
Current asset retirement obligations	77,452		48,080
Total current liabilities	1,008,523		942,814
Long-term debt, including finance lease obligation	1,474,828		1,274,502
Asset retirement obligations	954,709		960,804
Deferred credits and other liabilities	269,334		274,345
Non-current operating lease liabilities	483,370		537,381
Deferred income taxes	352,280		335,790

Total liabilities	$	4,543,044	$	4,325,636
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	$	—	$	—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares in 2025 and 195,100,628 shares in 2024	195,101		195,101
Capital in excess of par value	830,945		848,950
Retained earnings	6,799,299		6,773,289
Accumulated other comprehensive loss	(628,875)		(628,072)
Treasury stock	(2,076,211)		(1,995,018)
Murphy Shareholders' Equity	5,120,259		5,194,250
Noncontrolling interest	157,020		147,593
Total equity	5,277,279		5,341,843
Total liabilities and equity	$	9,820,323	$	9,667,479

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

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars, except per share amounts)		2025		2024
Revenues and other income
Revenue from production		$	672,730	$	794,603
Sales of purchased natural gas		—		245
Total revenue from sales to customers		672,730		794,848
(Loss) on derivative instruments		(9,459)		—
Gain on sale of assets and other operating income		2,440		1,564
Total revenues and other income		665,711		796,412
Costs and expenses
Lease operating expenses		205,079		234,264
Severance and ad valorem taxes		8,650		10,086
Transportation, gathering and processing		48,851		56,553
Costs of purchased natural gas		—		160
Exploration expenses, including undeveloped lease amortization		14,488		44,429
Selling and general expenses		30,915		31,161

Depreciation, depletion and amortization		194,160		211,134
Accretion of asset retirement obligations		14,045		12,774
Impairment of assets		—		34,528
Other operating expense		5,629		7,266
Total costs and expenses		521,817		642,355
Operating income from continuing operations		143,894		154,057
Other income (loss)
Other income		2,402		11,551
Interest expense, net		(23,523)		(20,021)
Total other loss		(21,121)		(8,470)
Income from continuing operations before income taxes		122,773		145,587
Income tax expense		32,722		30,057
Income from continuing operations		90,051		115,530
Loss from discontinued operations, net of income taxes		(633)		(872)
Net income including noncontrolling interest		89,418		114,658
Less: Net income attributable to noncontrolling interest		16,382		24,656
NET INCOME ATTRIBUTABLE TO MURPHY		$	73,036	$	90,002
NET INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations		$	0.51	$	0.60
Discontinued operations		—		(0.01)
Net income		$	0.51	$	0.59
NET INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations		$	0.50	$	0.60
Discontinued operations		—		(0.01)
Net income		$	0.50	$	0.59
Cash dividends per common share		$	0.325	$	0.300
Average common shares outstanding (thousands)
Basic		144,284		152,664
Diluted		145,072		153,817

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

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars)		2025		2024
Net income including noncontrolling interest		$	89,418	$	114,658
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		(1,667)		(35,528)
Retirement and postretirement benefit plans		864		910


Other comprehensive income (loss)		(803)		(34,618)
Comprehensive income including noncontrolling interest		88,615		80,040
Less: Comprehensive income attributable to noncontrolling interest		16,382		24,656
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY		$	72,233	$	55,384

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

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars)	2025		2024
Operating Activities
Net income including noncontrolling interest	$	89,418	$	114,658
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization	194,160		211,134
Deferred income tax expense	16,343		19,478
Accretion of asset retirement obligations	14,045		12,774
Long-term non-cash compensation	9,905		9,851
Mark-to-market loss on derivative instruments	8,916		—
Amortization of undeveloped leases	1,654		2,793

Loss from discontinued operations	633		872




Unsuccessful exploration well costs and previously suspended exploration costs	190		32,437
Impairment of assets	—		34,528
Other operating activities, net	(11,799)		(15,381)
Net (increase) in non-cash working capital	(22,784)		(24,353)

Net cash provided by continuing operations activities	300,681		398,791
Investing Activities
Property additions and dry hole costs	(368,421)		(249,085)
Acquisition of oil and natural gas properties	(1,364)		—


Net cash required by investing activities	(369,785)		(249,085)
Financing Activities
Borrowings on revolving credit facility	250,000		100,000
Repayment of revolving credit facility	(50,000)		(100,000)



Repurchase of common stock	(100,072)		(50,000)
Cash dividends paid	(47,026)		(45,773)
Withholding tax on stock-based incentive awards	(7,673)		(25,270)
Distributions to noncontrolling interest	(6,955)		(23,001)
Finance lease obligation payments	(116)		(164)



Net cash provided (required) by financing activities	38,158		(144,208)






Effect of exchange rate changes on cash and cash equivalents	291		858
Net (decrease) increase in cash and cash equivalents	(30,655)		6,356
Cash and cash equivalents at beginning of period	423,569		317,074
Cash and cash equivalents at end of period	$	392,914	$	323,430

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

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)


	Three Months Ended March 31,
(Thousands of dollars except number of shares)		2025		2024

Common Stock
Balance at beginning and end of period – par $1.00, authorized 450,000,000 shares at March 31, 2025 and March 31, 2024, issued 195,100,628 shares at March 31, 2025 and March 31, 2024		$	195,101	$	195,101


Capital in Excess of Par Value
Balance at beginning of period		848,950		880,297

Restricted stock transactions and other		(27,338)		(70,387)
Share-based compensation		9,333		6,905

Balance at end of period		830,945		816,815
Retained Earnings
Balance at beginning of period		6,773,289		6,546,079
Net income attributable to Murphy		73,036		90,002


Cash dividends paid		(47,026)		(45,773)
Balance at end of period		6,799,299		6,590,308
Accumulated Other Comprehensive Loss
Balance at beginning of period		(628,072)		(521,117)
Foreign currency translation, net of income taxes		(1,667)		(35,528)
Retirement and postretirement benefit plans, net of income taxes		864		910


Balance at end of period		(628,875)		(555,735)
Treasury Stock
Balance at beginning of period		(1,995,018)		(1,737,566)
Repurchase of common stock		(100,876)		(50,049)
Awarded restricted stock, net of forfeitures		19,683		45,117

Balance at end of period – 52,384,566 shares of common stock in 2025 and 42,524,472 shares of common stock in 2024, at cost		(2,076,211)		(1,742,498)
Murphy Shareholders’ Equity		5,120,259		5,303,991
Noncontrolling Interest
Balance at beginning of period		147,593		186,859

Net income attributable to noncontrolling interest		16,382		24,656
Distributions to noncontrolling interest owners		(6,955)		(23,001)
Balance at end of period		157,020		188,514
Total Equity		$	5,277,279	$	5,492,505

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note A – Basis of Presentation

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

Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2024 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month period ended March 31, 2025 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Reportable Segment Disclosures. In November 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The standard requires additional disclosures about operating segments, including segment expense information provided to the chief operating decision maker, and extends certain disclosure requirements to interim periods. The Company adopted this standard in the fourth quarter of 2024. The adoption did not impact the determination of significant segments and had no material impact on the Company’s consolidated financial statements. These new disclosure requirements are applied retrospectively to all prior periods included in the financial statements. Refer to Note P.

Recent Accounting Pronouncements

Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

Income Tax Disclosures. In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The standard becomes effective for annual periods beginning after December 15, 2024. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. We expect this ASU to only impact our disclosures with no impacts to our results of operations, cash flows and financial condition.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively referred to as oil and natural gas) in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the United States (U.S.) and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil, natural gas and natural gas liquids (NGLs).

For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.

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

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

Disaggregation of Revenue

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C - Revenue from Contracts with Customers (Continued)

The Company’s revenues and other income for the three-month periods ended March 31, 2025 and 2024 were as follows.


	Three Months Ended March 31,
(Thousands of dollars)		2025		2024
Net crude oil and condensate revenue
United States - Onshore		$	109,458	$	142,543
United States - Offshore 1		352,362		480,439
Canada - Onshore		14,730		13,873
Canada - Offshore		74,469		54,775
Other		—		(98)
Total crude oil and condensate revenue		551,019		691,532

Net natural gas liquids revenue
United States - Onshore		8,487		7,836
United States - Offshore 1		9,249		10,374
Canada - Onshore		1,747		1,437
Total natural gas liquids revenue		19,483		19,647

Net natural gas revenue
United States - Onshore		7,967		4,276
United States - Offshore 1		19,941		12,889
Canada - Onshore		74,320		66,259
Total natural gas revenue		102,228		83,424

Revenue from production		672,730		794,603

Sales of purchased natural gas 2



Canada - Onshore		—		245
Total sales of purchased natural gas		—		245

Total revenue from sales to customers		672,730		794,848

(Loss) on derivative instruments		(9,459)		—
Gain on sale of assets and other operating income		2,440		1,564
Total revenues and other income		$	665,711	$	796,412

1 Includes revenue attributable to noncontrolling interest in MP GOM.

2 Purchases of natural gas are reported on a gross basis when Murphy takes control of the product and has risks and rewards of ownership. Sales of purchased natural gas are reported when the contractual performance obligations are satisfied. This occurs at the time the product is delivered to a third-party purchaser at the contractually determinable price.

Contract Balances and Asset Recognition

As of March 31, 2025, and December 31, 2024, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $203.7 million and $178.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any revenue contracts that have financing components as of March 31, 2025.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note C – Revenue from Contracts with Customers (Continued)

Performance Obligations

The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

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

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

As of March 31, 2025, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:

Location

Commodity

End Date

Description

Approximate Volumes

U.S.

Natural Gas and NGLs

Q2 2030

Deliveries from dedicated acreage in Eagle Ford Shale

As produced

Canada

Natural Gas

Q4 2025

Contracts to sell natural gas at USD index pricing

25 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at USD index pricing

49 MMCFD

Canada

Natural Gas

Q4 2027

Contracts to sell natural gas at USD index pricing

30 MMCFD

Canada

Natural Gas

Q4 2028

Contracts to sell natural gas at USD index pricing

10 MMCFD

Canada

Natural Gas

Q4 2025

Contracts to sell natural gas at CAD fixed pricing

40 MMCFD

Canada

Natural Gas

Q4 2026

Contracts to sell natural gas at CAD fixed pricing

50 MMCFD

Canada

NGLs

Q2 2025

Contracts to sell NGLs at CAD index pricing

As produced

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

Note D – Property, Plant and Equipment

Exploratory Wells

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

As of March 31, 2025, the Company had total capitalized drilling costs pending the determination of proved reserves of $96.8 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2025 and 2024.


(Thousands of dollars)	2025		2024
Beginning balance at January 1	$	72,055	$	49,118
Additions pending the determination of proved reserves	24,790		11,538

Capitalized exploratory well costs charged to expense	—		(26,471)
Balance at March 31	$	96,845	$	34,185

Capital additions of $24.8 million, for the quarter ended March 31, 2025, are mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15/2-17 and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam and long-lead equipment for the Cello #1 and Banjo #1 exploration wells (Mississippi Canyon 385) in the Gulf of America. The Lac Da Hong-1X (Pink Camel) exploration well in Vietnam encountered 106 feet of net oil pay from one reservoir. There were no capitalized well costs charged to dry hole expense for the three months ended

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note D – Property, Plant and Equipment (Continued)

March 31, 2025. Capitalized well costs charged to dry hole expense of $26.5 million for the three months ended March 31, 2024 were related to the Hoffe Park #1 (Mississippi Canyon 166) exploration well in the Gulf of America. The preceding table excludes well costs of $0.2 million and $5.9 million incurred and expensed directly to dry hole for the three months ended March 31, 2025 and 2024, respectively. In 2025, the amount primarily relates to the finalization of previous dry hole wells, and in 2024, the amount primarily relates to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

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


	March 31,
	2025			2024

(Thousands of dollars)	Amount		No. of Wells		Amount		No. of Wells
Aging of capitalized well costs:
Zero to one year	$	9,421	2		$	11,641	4
One to two years	65,160		3		—		—
Two to three years	—		—		—		—
Three years or more	22,264		3		22,544		3
	$	96,845	8		$	34,185	7

Of the $87.4 million of exploration well costs capitalized more than one year at March 31, 2025, $59.0 million was in Vietnam, $21.2 million was in the Gulf of America, $4.4 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, subject to customary closing adjustments. This acquisition includes an initial $100.0 million payment in the first quarter of 2025. The remaining balance will be due when certain contractual obligations are met, which is expected by the end of the second quarter of 2025. The FPSO will remain at its current location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited will continue to provide operations and maintenance services under a new five-year contract.

Impairments

There were no impairments in the three months ended March 31, 2025. There were pretax impairments of $34.5 million in the three months ended March 31, 2024 related to the Calliope field in Mississippi Canyon in the Gulf of America, in which operational issues led to a reserve reduction.

Note E – Financing Arrangements and Debt

As of March 31, 2025, the Company had a $1.35 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires on October 7, 2029. At March 31, 2025, the Company had $200.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At March 31, 2025, the interest rate in effect on borrowings under the RCF was 6.67%. At March 31, 2025, the Company was in compliance with all covenants related to the RCF.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note F – Other Financial Information

Supplemental Information to Statement of Cash Flows


	Three Months Ended March 31,
(Thousands of dollars)	2025		2024
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(10,089)	$	(13,174)
(Increase) decrease in inventories	(15,851)		4,860
(Increase) decrease in prepaid expenses	10,502		5,110
Increase (decrease) in accounts payable and accrued liabilities	(13,560)		(24,852)
Increase (decrease) in income taxes payable	6,214		3,703
Net (increase) in non-cash working capital	$	(22,784)	$	(24,353)

Supplementary disclosures:
Net cash income taxes (refunded) paid	$	(1,632)	$	405
Interest paid, net of amounts capitalized of $1.1 million in 2025 and $3.9 million in 2024	6,347		11,062

Non-cash investing activities:
Asset retirement costs capitalized	$	8,996	$	10,955
(Increase) decrease in capital expenditure accrual	(42,442)		(12,948)

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, 2025 and 2024 are shown in the following table.


(Thousands of dollars)	March 31, 2025		March 31, 2024
Balance at beginning of year	$	1,008,884	$	914,763
Accretion	14,045		12,774
Liabilities incurred	4,996		8,960

Revisions of previous estimates	3,999		1,995
Liabilities settled	(157)		(737)



Changes due to translation of foreign currencies	394		(3,143)
Balance at end of period	1,032,161		934,612
Current portion of liability	(77,452)		(17,797)
Non-current portion of liability	$	954,709	$	916,815

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note H – Employee and Retiree Benefit Plans

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

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2025 and 2024.


	Three Months Ended March 31,
	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2025		2024		2025		2024
Service cost	$	1,683	$	1,706	$	84	$	135
Interest cost	8,398		8,391		708		782
Expected return on plan assets	(8,871)		(8,357)		—		—
Estimated defined contribution provision	60		55		—		—
Amortization of prior service cost (credit)	491		579		(133)		(133)
Recognized actuarial loss (gain)	1,891		2,360		(1,056)		(812)



Total net periodic benefit expense	$	3,652	$	4,734	$	(397)	$	(28)

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, 2025, the Company made contributions of $7.3 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2025 for the Company’s defined benefit pension and postretirement plans is anticipated to be $23.6 million.

Note I – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

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 2020 Long-Term Incentive Plan (2020 Long-Term Plan) authorizes the Committee to make grants of the Company’s common stock and stock-based awards to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2020 Long-Term Plan expires in 2030. A total of 5 million shares of common stock are issuable during the life of the 2020 Long-Term Plan. Shares issued pursuant to awards granted under the 2020 Long-Term Plan may be shares that are authorized and unissued or shares that were reacquired by the Company, including shares purchased in the open market. Share awards that have been canceled, expired, forfeited or otherwise not issued under an award shall not count as shares issued under the 2020 Long-Term Plan. In addition, the 2020 Long-Term Plan authorizes the Committee to grant cash-settled equity awards to employees. These cash-settled RSU awards do not require issuance of the Company’s common stock, are time-based, and generally vest on the third anniversary of the date of grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note I – Incentive Plans (Continued)

During the three months ended March 31, 2025, the Committee granted the following awards from the 2020 Long-Term Plan:


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

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

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

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

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

During the three months ended March 31, 2025, the Committee granted the following awards to NEDs under the 2021 NED Plan:

Type of Award

Number of Awards Granted

Grant Date

Grant Date Fair Value

Valuation Methodology

Time-Based RSUs 1

74,970

February 5, 2025

26.68

Closing Stock Price

Time-Based RSUs 2

2,114

March 31, 2025

28.40

Closing Stock Price

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

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

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)	2025		2024
Compensation charged against income before tax benefit	$	8,864	$	8,937
Related income tax benefit recognized in income	1,175		1,014

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 Tax Cuts and Jobs Act (2017 Tax Act).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note J – Net Income (Loss) 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, 2025 and 2024. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31,
(Weighted-average shares)		2025	2024
Basic method		144,283,946	152,664,422
Dilutive stock options and restricted stock units		788,142	1,152,204
Diluted method		145,072,088	153,816,626

Note K – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) from continuing operations before income taxes. For the three-month periods ended March 31, 2025 and 2024, the Company’s effective income tax rates were as follows:


	2025	2024
Three months ended March 31,	26.7%	20.6%

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.

The effective tax rate for the three-month period ended March 31, 2024 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and partially offset by 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; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available.

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, 2025, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2016; and Malaysia – 2018. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

Note L – Financial Instruments and Risk Management

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivatives outstanding at March 31, 2025 and 2024.

Commodity Price Risks

The Company is subject to commodity price risk related to products it produces and sells. During the three months ended March 31, 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.

At March 31, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts are as follows:

NYMEX Henry Hub

Area

Commodity

Volumes MMCF/d

Price/MCF

Start Date

End Date

Fixed price derivative swap

United States

Natural Gas

3.58

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

At March 31, 2024, the Company did not have any crude oil or natural gas derivative contracts.

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

(Thousands of dollars)

Asset (Liability) Derivatives Fair Value

Type of Derivative Contract

Balance Sheet Location

March 31, 2025

December 31, 2024

Commodity swaps

Accounts payable

(8,916)

(1,707)

For the three-month periods ended March 31, 2025 and 2024, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:


		Gain (Loss)
(Thousands of dollars)		Three Months Ended March 31,
Type of Derivative Contract	Statement of Operations Location		2025		2024
Commodity swaps	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, 2025 and December 31, 2024, are shown in the following table:


	March 31, 2025								December 31, 2024
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total





Liabilities:

Commodity swaps	$	—	$	8,916	$	—	$	8,916	$	—	$	1,707	$	—	$	1,707
Nonqualified employee savings plan	18,479		—		—		18,479		19,469		—		—		19,469
	$	18,479	$	8,916	$	—	$	27,394	$	19,469	$	1,707	$	—	$	21,176

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note L – Financial Instruments and Risk Management (Continued)

The commodity swaps liability as of March 31, 2025 was $8.9 million and recorded as “Accounts payable” in the Consolidated Balance Sheets. The fair value of commodity swaps was based on active market quotes for NYMEX Henry Hub natural gas. The before tax income effect of changes in the fair value of natural gas derivative contracts is recorded in “Loss on derivative instruments” in the Consolidated Statements of Operations.

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.

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

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


	March 31,				December 31,
	2025				2024
(Thousands of dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial liabilities:
Current and long-term debt	$	1,475,720	$	1,379,962	$	1,275,374	$	1,185,961

Fair Values – Nonrecurring

There were no impairment expenses incurred in the first quarter of 2025.

In the first quarter of 2024, an impairment charge of $34.5 million was triggered for the Calliope field, due to operational issues that led to reserve reductions.

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

The fair value information associated with the impaired properties is presented in the following table:


	Three Months Ended March 31, 2024
							Net Book Value Prior to Impairment		Total Pretax Impairment
	Fair Value
(Thousands of dollars)	Level 1		Level 2		Level 3







2024
Assets:
Impaired proved properties
United States - Offshore	$	—	$	—	$	437	$	34,965	$	34,528

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note M – Accumulated Other Comprehensive Loss

The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2024 and March 31, 2025 and the changes during the three-month periods ended March 31, 2025 are presented net of taxes in the following table.


(Thousands of dollars)	Foreign Currency Translation Gains (Losses)		Retirement and Postretirement Benefit Plan Adjustments		Total
Balance at December 31, 2024	$	(516,324)	$	(111,748)	$	(628,072)
Components of other comprehensive income (loss):
Before reclassifications to income	(1,667)		—		(1,667)
Reclassifications to income ¹	—		864		864
Net other comprehensive income (loss)	(1,667)		864		(803)
Balance at March 31, 2025	$	(517,991)	$	(110,884)	$	(628,875)

1 Reclassifications before taxes of $1.0 million are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2025. See Note H for additional information. Related income taxes of $0.2 million are included in "Income tax expense” on the Consolidated Statements of Operations for the three-month period ended March 31, 2025.

Note N – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; trade policies, tariffs and other trade restrictions; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note N – Environmental and Other Contingencies (Continued)

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

In recent years, there has been an increase in regulatory oversight of the oil and natural gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and natural gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the U.S. EPA. In November 2024, the U.S. EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule was disapproved by a joint Congressional resolution in March 2025. 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. Although the U.S. officially withdrew from the Paris Agreement on November 4, 2020, the U.S. rejoined the Paris Agreement in 2021. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement again. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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, 2025 and 2024 is shown below.


(Number of shares outstanding)	March 31, 2025	March 31, 2024
Beginning of period	145,845,124	152,748,642

Restricted stock awards 1	484,388	1,100,759

Treasury shares purchased	(3,613,450)	(1,273,245)
End of period	142,716,062	152,576,156

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, 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, 2025, the Company had $550.1 million of its common stock remaining available to repurchase under the program.

Note P – Business Segments

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

Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the Chief Operating Decision Maker (CODM).

“Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM, or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income from short-term investment accounts attributed to the Canada segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Three Months Ended March 31, 2025
Revenue from production	$	507.4	$	165.3	$	—	$	672.7	$	—	$	672.7
Sales of purchased natural gas	—		—		—		—		—		—
Gain on sales of assets and other operating income	2.1		0.4		—		2.5		(9.5)		(7.0)
Revenues from external customers	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
Costs of purchased natural gas	—		—		—		—		—		—
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	25.0		14.3		—		39.3		(6.6)		32.7
Other segment costs (income)	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 a noncontrolling interest in MP GOM.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note P – Business Segments (Continued)


	Exploration and Production
(Millions of dollars)	United States 1		Canada		Other		Total E&P		Corporate, Other, and Discontinued Operations		Consolidated Total
Three Months Ended March 31, 2024
Revenue from production	$	658.4	$	136.3	$	(0.1)	$	794.6	$	—	$	794.6
Sales of purchased natural gas	—		0.2		—		0.2		—		0.2
Gain on sales of assets and other operating income	1.2		0.4		—		1.6		—		1.6
Revenues from external customers	659.6		136.9		(0.1)		796.4		—		796.4
Lease operating expenses
Lease operating expenses and taxes other than income	120.2		46.7		0.2		167.1		—		167.1
Repair and maintenance	11.0		0.6		—		11.6		—		11.6
Workovers	55.4		0.2		—		55.6		—		55.6
Total lease operating expenses	186.6		47.5		0.2		234.3		—		234.3
Severance and ad valorem taxes	9.8		0.3		—		10.1		—		10.1
Transportation, gathering and processing	36.6		19.9		—		56.5		0.1		56.6
Costs of purchased natural gas	—		0.2		—		0.2		—		0.2
Selling and general expenses	(0.2)		5.1		1.2		6.1		25.0		31.1
Exploration Expenses
Geological and geophysical	0.6		—		0.8		1.4		—		1.4
Dry holes and previously suspended exploration costs	31.2		—		1.2		32.4		—		32.4
Other exploratory costs, including undeveloped lease amortization and delay lease rentals	3.4		0.1		7.1		10.6		—		10.6
Total exploration expenses	35.2		0.1		9.1		44.4		—		44.4
Depreciation, depletion and amortization	174.0		34.3		—		208.3		2.8		211.1
Impairment of assets	34.5		—		—		34.5		—		34.5
Accretion of asset retirement obligations	10.4		2.1		0.3		12.8		—		12.8



Other operating expenses	6.3		0.9		0.1		7.3		—		7.3
Interest Income	(0.7)		—		—		(0.7)		(2.9)		(3.6)
Interest expense, net of capitalization	—		0.1		—		0.1		19.9		20.0
Income tax expense
Current income tax expense	1.0		5.8		—		6.8		3.9		10.7
Deferred income tax expense (benefit)	29.8		1.1		(0.3)		30.6		(11.2)		19.4
Total income tax expense (benefit)	30.8		6.9		(0.3)		37.4		(7.3)		30.1
Other segment costs (income)	1.8		0.1		0.1		2.0		(9.2)		(7.2)
Segment income (loss) - including NCI 1	$	134.5	$	19.4	$	(10.8)	$	143.1	$	(28.4)	$	114.7

Additions to property, plant, equipment	$	155.3	$	67.2	$	2.9	$	225.4	$	4.2	$	229.6
Total assets at quarter-end	7,030.7		2,059.1		210.2		9,300.0		368.7		9,668.7

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

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

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, 2025 included under “Item 1 . Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2024. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.

Overview

Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The Company has more than a century-long history of demonstrating strong execution and innovative, full-cycle development capabilities with a focus on value creation that drives shareholder returns. The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire.

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

Significant Company financial and operational highlights during the first quarter of 2025 were as follows:

•Drilled an oil discovery at Lac Da Hong-1X (Pink Camel) in offshore Vietnam and encountered 106 feet of net oil pay from one reservoir

•Closed the strategic acquisition of the BW Pioneer FPSO in the Gulf of America for $125.0 million gross purchase price

•Paid quarterly dividend of $0.325 per share or $1.30 per share annualized

•Repurchased $100.0 million ($100.9 million including excise taxes and fees) of common stock, or 3.6 million shares

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2025, was $90.0 million, a decrease of $25.6 million compared to the same period of 2024. Lower net income from continuing operations was largely driven by lower revenues from production ($121.9 million) and was partially offset by lower impairment of assets ($34.5 million), lower exploration expenses ($29.9 million), and lower lease operating expenses ($29.2 million). Lower revenues were primarily driven by lower crude oil production in the U.S., resulting from workover and turnaround-related downtime, and well performance, combined with lower crude oil prices. This was partially offset by increased crude oil sales at Canada Offshore, as 2024 had lower production build-up following the completion of the non-operated Terra Nova asset life extension project. In 2024, there were asset impairment charges relating to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction. Lower lease operating expenses were primarily driven by lower sales volumes in the U.S. and lower operating costs at the non-operated Terra Nova field as 2024 had higher asset restart costs, partially offset by increased sales volumes at the non-operated Terra Nova field. Exploration expenses decreased in 2025, as 2024 had additional expenses for dry holes and previously suspended exploration costs relating to Hoffe Park #1 (Mississippi Canyon 166) exploration well and costs related to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

For the three months ended March 31, 2025, total hydrocarbon production was 163,374 barrels of oil equivalent per day, a decrease of 8% compared to the first quarter of 2024. The decrease was principally due to lower production in the U.S., partially offset by higher production in Canada. Decreases in the Gulf of America resulted from workover and turnaround-related downtime, and well performance, while decreases in the Eagle Ford Shale were due to natural decline and well downtime related to workovers and winter weather. Higher

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

Overview (Continued)

production in Canada primarily related to the non-operated Terra Nova field following the asset resuming operations.

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

For the three months ended March 31, 2025, West Texas Intermediate (WTI) crude oil price at the end of the first quarter of 2025 was $71.48 per barrel, whereas the crude oil price at the end of April 2025 was $58.21, reflecting a 19% reduction in price. The average sales price in April 2025 was $63.79 per barrel. As of May 5, 2025 closing, the NYMEX WTI forward curve price for remainder of 2025 was $56.46 per barrel. Reductions in commodity prices will reduce 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)		2025		2024
Exploration and production
United States		$	107.9	$	134.5
Canada		41.5		19.4
Other		(11.2)		(10.8)
Total exploration and production		138.2		143.1
Corporate and other		(48.2)		(27.5)
Income from continuing operations		90.0		115.6
Loss from discontinued operations ¹		(0.6)		(0.9)
Net income including noncontrolling interest		89.4		114.7
Net income attributable to noncontrolling interest		16.4		24.7
Net income attributable to Murphy		$	73.0	$	90.0

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.

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

Results of Operations (Continued)

Exploration and Production Continuing Operations

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

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


	Three Months Ended March 31,
(Millions of dollars)		2025		2024
Revenues and other income
Revenue from production		$	672.7	$	794.6
Sales of purchased natural gas		—		0.2
Other income		2.5		1.6
Total revenues and other income		675.2		796.4
Cost and Expenses
Lease operating expenses		205.1		234.3
Severance and ad valorem taxes		8.7		10.1
Transportation, gathering and processing		48.9		56.5
Costs of purchased natural gas		—		0.2
Depreciation, depletion and amortization		191.8		208.3
Impairments of assets		—		34.5
Accretion of asset retirement obligations		14.0		12.7
Total exploration expenses, including undeveloped lease amortization		14.5		44.4
Selling and general expenses		9.9		6.1
Other		4.8		8.8
Results of operations before taxes		177.5		180.5
Income tax provisions		39.3		37.4
Results of operations (excluding Corporate segment) 1		$	138.2	$	143.1

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

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

Results of Operations (Continued)

Pricing

The following table contains the weighted average sales prices for the three-month periods ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(Weighted average sales prices)		2025		2024
Crude oil and condensate – dollars per barrel
United States - Onshore		$	71.65	$	76.85
United States - Offshore 1		72.32		77.58
Canada - Onshore 2		63.34		67.59
Canada - Offshore 2		74.36		85.99

Natural gas liquids – dollars per barrel
United States - Onshore		23.16		20.67
United States - Offshore 1		27.02		24.32
Canada - Onshore 2		36.08		34.84
Natural gas – dollars per thousand cubic feet
United States - Onshore		3.38		1.94
United States - Offshore 1		4.33		2.66
Canada - Onshore 2		2.38		2.05

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, 2025 and 2024:


	Three Months Ended March 31,
(Average price for the period)		2025		2024
Oil and NGLs
WTI ($/BBL)		$	71.42	$	76.96
Natural gas
NYMEX ($/MMBTU)		4.27		2.42
AECO (C$/MCF)		2.17		2.50

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

Results of Operations (Continued)

Production Volumes

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2025 and 2024. 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)		2025	2024

Net crude oil and condensate
United States - Onshore		16,974	20,382
United States - Offshore 1		55,587	66,078
Canada - Onshore		2,584	2,255
Canada - Offshore		8,855	6,264
Other		255	245
Total net crude oil and condensate		84,255	95,224
Net natural gas liquids
United States - Onshore		4,072	4,166
United States - Offshore 1		3,804	4,687
Canada - Onshore		538	453
Total net natural gas liquids		8,414	9,306
Net natural gas – thousands of cubic feet per day
United States - Onshore		26,190	24,231
United States - Offshore 1		51,150	53,161
Canada - Onshore		346,892	355,455
Total net natural gas		424,232	432,847
Total net hydrocarbons - including NCI 2,3		163,374	176,671
Noncontrolling interest
Net crude oil and condensate – barrels per day		(5,779)	(6,499)
Net natural gas liquids – barrels per day		(170)	(211)
Net natural gas – thousands of cubic feet per day		(1,234)	(2,074)
Total noncontrolling interest 2,3		(6,154)	(7,056)
Total net hydrocarbons - excluding NCI 2,3		157,220	169,615

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

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

Results of Operations (Continued)

Sales Volumes

The following table contains hydrocarbons sold during the three-month periods ended March 31, 2025 and 2024. 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)		2025	2024
Net crude oil and condensate
United States - Onshore		16,974	20,382
United States - Offshore 1		54,133	68,056
Canada - Onshore		2,584	2,255
Canada - Offshore		11,128	7,000
Other		—	11
Total net crude oil and condensate		84,819	97,704
Net natural gas liquids
United States - Onshore		4,072	4,166
United States - Offshore 1		3,804	4,687
Canada - Onshore		538	453
Total net natural gas liquids		8,414	9,306
Net natural gas – thousands of cubic feet per day
United States - Onshore		26,190	24,231
United States - Offshore 1		51,150	53,161
Canada - Onshore		346,892	355,455
Total net natural gas		424,232	432,847
Total net hydrocarbons - including NCI 2,3		163,938	179,151
Noncontrolling interest
Net crude oil and condensate – barrels per day		(5,567)	(6,805)
Net natural gas liquids – barrels per day		(170)	(211)
Net natural gas – thousands of cubic feet per day		(1,234)	(2,074)
Total noncontrolling interest 2,3		(5,942)	(7,362)
Total net hydrocarbons - excluding NCI 2,3		157,996	171,789

1 Includes net volumes attributable to a noncontrolling interest in MP GOM.

2 Natural gas converted on an energy equivalent basis of 6:1.

3 NCI – noncontrolling interest in MP GOM.

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

Results of Operations (Continued)

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

Revenues from Production

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


	Three Months Ended March 31,
(Millions of dollars)		2025		2024
Revenues from production
United States - Oil		$	461.8	$	623.0
United States - Natural gas liquids		17.8		18.2
United States - Natural gas		27.9		17.2
Canada - Oil		89.2		68.6
Canada - Natural gas liquids		1.7		1.4
Canada - Natural gas		74.3		66.3
Other - Oil		—		(0.1)
Total revenue from production		$	672.7	$	794.6

Revenues from production for the three months ended March 31, 2025 decreased by $121.9 million compared to the same period in 2024. Revenue was lower in the Gulf of America, mostly driven by workover and turnaround-related downtime, well performance, and lower sales volumes at Cascade and Chinook fields as a result of the timing of sales cargos, partially offset by new well production at the Mormont field. Lower crude oil pricing was partially offset by higher natural gas pricing in the Gulf of America. Eagle Ford Shale revenues decreased due to natural decline, as well as lower crude oil prices. Revenues in Canada Offshore increased due to higher sales volumes at non-operated Terra Nova as a result of lower production in the first quarter of 2024 with production build-up after the completion of the asset life extension project, lower crude oil pricing, and the timing of sales cargos in 2025. Canada Onshore revenues increased due to higher pricing on natural gas at Tupper Montney and additional new well production volumes, partially offset by higher royalty rates.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. “Sales of purchased natural gas” is included in “Total revenues and other income” and “Cost of purchased natural gas” is included in “Costs and Expenses” in the summarized statement of operations for E&P continuing operations on page 25.

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

Results of Operations (Continued)

Lease Operating and Transportation, Gathering and Processing Expenses

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


	Three Months Ended March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
			2025		2024		2025		2024
Lease operating expenses
United States - Onshore			$	29.8	$	35.6	$	13.02	$	13.68
United States - Offshore			127.8		151.0		21.37		20.34
Canada - Onshore			30.2		31.0		5.51		5.49
Canada - Offshore			16.9		16.5		16.89		25.91
Other			0.4		0.2		—		—
Total lease operating expenses			$	205.1	$	234.3	$	13.90	$	14.37
Transportation, gathering and processing
United States - Onshore			$	2.4	$	2.7	$	1.00	$	1.04
United States - Offshore			26.4		33.9		4.42		4.57
Canada - Onshore			18.3		18.0		3.34		3.19
Canada - Offshore			1.8		1.9		1.80		3.03

Total transportation, gathering and processing			$	48.9	$	56.5	$	3.31	$	3.47

For the three months ended March 31, 2025, lease operating expenses decreased by $29.2 million and transportation, gathering and processing expenses decreased by $7.6 million compared to the same period in 2024. Lower lease operating expenses in the Gulf of America were largely driven by lower sales volumes. Operating expenses at Canada Offshore decreased by $9.02 per barrel due to lower production and higher restart costs in the first quarter of 2024 associated the non-operated Terra Nova field. Lower transportation, gathering and processing expenses during the quarter were a result of overall lower production volumes in the Gulf of America.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization (DD&A) expense by geographic area were as follows:


	Three Months Ended March 31,
		(Millions of dollars)	(Dollars per equivalent barrel)
			2025		2024		2025		2024
DD&A expense
United States - Onshore			$	67.1	$	74.1	$	29.35	$	28.52
United States - Offshore			92.2		99.9		15.42		13.46
Canada - Onshore			24.1		28.1		4.40		4.99
Canada - Offshore			8.3		6.2		8.26		9.68
Other			0.1		—		—		20.38
Total DD&A expense			$	191.8	$	208.3	$	13.00	$	12.77

DD&A expense for the three months ended March 31, 2025 decreased by $16.5 million compared to the same period in 2024. The decrease is primarily due to lower sales volumes in the Gulf of America and at Eagle Ford Shale and lower rates at Canada Offshore resulting from ARO adjustments, partially offset by higher sales volumes in Canada Offshore and higher rates in the Gulf of America resulting from increased drilling, completions and facilities developments costs.

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

Results of Operations (Continued)

Impairment of Assets

For the three months ended March 31, 2025, there were no impairments.

Impairment of assets for the three months ended March 31, 2024 was $34.5 million and related to the Calliope field in Mississippi Canyon in the Gulf of America, as a result of operational issues that led to a reserve reduction.

Exploration Expenses

The Company’s exploration expenses were as follows:


	Three Months Ended March 31,
(Millions of dollars)		2025		2024
Exploration expenses
Dry holes and previously suspended exploration costs		$	0.2	$	32.4
Geological and geophysical		3.6		1.4
Other exploration		9.1		7.8
Undeveloped lease amortization		1.6		2.8
Total exploration expenses, including undeveloped lease amortization		$	14.5	$	44.4

Exploration expenses for the three months ended March 31, 2025 decreased by $29.9 million compared to the same period in 2024. In 2024, there were dry holes and previously suspended exploration costs relating to the previously suspended costs for Hoffe Park #1 (Mississippi Canyon 166) exploration well and additional costs related to the non-operated Oso #1 (Atwater Valley 138) exploration well in the Gulf of America.

Income Taxes

Income taxes for the three months ended March 31, 2025 increased by $1.9 million compared to the same period in 2024. Higher income taxes were primarily the result of higher taxes in foreign jurisdictions, partially offset by lower year-to-date pretax income.

Corporate

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

Corporate activities reported a loss of $48.2 million for the three months ended March 31, 2025, an unfavorable variance of $20.7 million compared to the same period of 2024. The unfavorable variance was primarily due to lower unrealized foreign exchange gains ($10.2 million) and unrealized losses on derivative instruments ($8.9 million).

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured RCF. The Company’s liquidity requirements, both in the short-term and long-term, consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company

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

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)	2025		2024
Net cash provided (required) by:
Net cash provided by continuing operations activities	$	300.7	$	398.8
Net cash required by investing activities	(369.8)		(249.1)
Net cash provided (required) by financing activities	38.2		(144.2)

Effect of exchange rate changes on cash and cash equivalents	0.3		0.9
Net (decrease) increase in cash and cash equivalents	$	(30.7)	$	6.4

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities for the three months ended March 31, 2025 was $98.1 million lower compared to the same period in 2024. The decrease in cash flows from operations activities was primarily attributable to lower revenue from production ($121.9 million), partially offset by lower lease operating expenses ($29.2 million).

Cash Required by Investing Activities

Net cash required by investing activities for the three months ended March 31, 2025 was $120.7 million higher compared to the same period in 2024. The increase was primarily due to higher property additions and dry hole costs ($119.3 million), which included a gross payment of $100.0 million for the purchase of a FPSO in the Gulf of America.

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


	Three Months Ended March 31,
(Millions of dollars)	2025		2024
Property additions and dry hole costs per the cash flow statements	$	368.4	$	249.1

Acquisition of oil properties per the cash flow statements	1.4		—
Geophysical and other exploration expenses	11.6		7.2
Capital expenditure accrual changes and other	43.4		15.0
Total capital expenditures	$	424.8	$	271.3

Total accrual basis capital expenditures are shown below.


	Three Months Ended March 31,
(Millions of dollars)	2025		2024
Capital Expenditures
Exploration and production	$	420.6	$	267.1
Corporate	4.2		4.2
Total capital expenditures	$	424.8	$	271.3

Higher capital expenditures in the three months ended March 31, 2025 compared to the same period of 2024 was primarily attributable to higher field development costs in the Gulf of America, including the purchase of a

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

FPSO, increased exploratory drilling in Vietnam, and higher development drilling at Eagle Ford Shale. The purchased FPSO in the Gulf of America will remain at its current location, and continue supporting operations at the Cascade and Chinook fields.

Capital expenditures in 2025 primarily relate to development drilling and field development activities at Eagle Ford Shale ($92.7 million), the Gulf of America ($214.8 million), Tupper Montney and Kaybob Duvernay ($50.2 million), and the non-operated Hibernia field ($4.6 million) in Canada. Other international field development activities were largely in Vietnam ($18.6 million). Exploration costs in 2025 were $39.1 million, primarily comprised of activities in Vietnam 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 and activities in the Gulf of America related to long lead equipment purchases for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells.

Cash Provided by Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2025 increased by $182.4 million compared to the same period in 2024. In 2025, the cash provided by financing activities was due to 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 of $0.33 per share ($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). In 2024, cash required by financing activities was for the repurchase of common shares ($50.0 million), cash dividends to shareholders ($45.8 million), withholding tax on stock-based incentive awards ($25.3 million), and distributions to the noncontrolling interest in MP GOM ($23.0 million).

Liquidity

At March 31, 2025, the Company had approximately $1.5 billion of liquidity consisting of $392.9 million in cash and cash equivalents and $1,149.6 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $1.35 billion senior unsecured RCF expires in October 2029. As of March 31, 2025, the Company had $200.0 million of outstanding borrowings under the RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. At March 31, 2025, the interest rate in effect on borrowings under the RCF was 6.67%. At March 31, 2025, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of March 31, 2025, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $83.1 million, the majority of which was held in Canada ($48.5 million), Vietnam ($9.0 million), and the U.K. ($7.8 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, 2025		December 31, 2024
Working capital
Total current assets	$	771.4	$	785.3
Total current liabilities	1,008.5		942.8
Net working capital liability	$	(237.1)	$	(157.5)

As of March 31, 2025, net working capital decreased by $79.6 million compared to December 31, 2024. The decrease was primarily attributable to higher accounts payable ($66.1 million), lower cash balance ($30.7 million), and higher current asset retirement obligations ($29.4 million), partially offset by lower other accrued liabilities ($27.2 million) and higher inventory balances ($16.2 million). Higher accounts payable was primarily due to the timing of drilling and completions work and accruals relating to the purchase of the FPSO in the Gulf of America. Higher current asset retirement obligations were primarily attributable to planned abandonment activities in U.S. Offshore in the next 12 months. Lower other accrued liabilities were due to incentive payments

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

and operating lease payments made in 2025. Inventory balances increased primarily due to timing of sales cargos at U.S. Offshore.

Capital Employed

A summary of capital employed at March 31, 2025 and December 31, 2024 follows.


	March 31, 2025				December 31, 2024
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,474.8	22.4	%	$	1,274.5	19.7	%
Murphy shareholders' equity	5,120.3		77.6	%	5,194.3		80.3	%
Total capital employed	$	6,595.1	100.0	%	$	6,468.8	100.0	%

At March 31, 2025, long-term debt of $1,474.8 million increased by $200.3 million compared to December 31, 2024, primarily as a result of amounts drawn on the senior unsecured RCF. The total of the fixed-rate notes had a weighted average maturity of 9.1 years and a weighted average coupon of 6.1%.

Murphy shareholders’ equity decreased by $74.0 million in 2025, primarily due to shares repurchased ($100.9 million, including excise tax) and cash dividends paid ($47.0 million), partially offset by net income earned ($73.0 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

Critical Accounting Estimates

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

Accounting Changes and Recent Accounting Pronouncements

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

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

Other Key Performance Metrics

The Company uses other operational performance and income metrics to review operational performance.

Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income 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 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)		2025		2024
Net income attributable to Murphy (GAAP) 1		$	73.0	$	90.0
Discontinued operations loss		0.6		0.9
Net income from continuing operations attributable to Murphy		73.6		90.9
Adjustments:
Mark-to-market loss on derivative instruments		8.9		—
Impairment of assets		—		34.5
Write-off of previously suspended exploration well		—		26.1
Foreign exchange (gain)		—		(10.5)















Total adjustments, before taxes		8.9		50.1
Income tax (benefit) related to adjustments		(1.8)		(10.2)

Total adjustments after taxes		7.1		39.9
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP)		$	80.7	$	130.8

Net income from continuing operations per average diluted share (GAAP)		$	0.50	$	0.60
Adjusted net income from continuing operations per average diluted share (Non-GAAP)		$	0.56	$	0.85

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

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

Other Key Performance Metrics (Continued)

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


	Three Months Ended March 31,
(Millions of dollars)		2025		2024
Net income attributable to Murphy (GAAP) 1		$	73.0	$	90.0
Income tax expense		32.7		30.1
Interest expense, net		23.5		20.0
Depreciation, depletion and amortization expense 1		187.4		202.7
EBITDA attributable to Murphy (Non-GAAP)		316.6		342.8
Exploration expenses		14.5		44.4
EBITDAX attributable to Murphy (Non-GAAP)		$	331.1	$	387.2

EBITDA attributable to Murphy (Non-GAAP)		$	316.6	$	342.8
Accretion of asset retirement obligations 1		12.5		11.4
Mark-to-market loss on derivative instruments		8.9		—
Impairment of assets		—		34.5
Write-off of previously suspended exploration well		—		26.1

Foreign exchange (gain)		—		(10.5)

Discontinued operations loss		0.6		0.9






Adjusted EBITDA attributable to Murphy (Non-GAAP)		$	338.6	$	405.2
Other exploration expenses 2		14.5		18.3
Adjusted EBITDAX attributable to Murphy (Non-GAAP)		$	353.1	$	423.5

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

2 Other exploration expenses consist of exploration expenses as reported in the consolidated statement of operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.

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

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 2025 compared to the same period in 2024 directly impacted the Company’s product sales revenue.

As of close on May 5, 2025, forward price curves for existing forward contracts for the remainder of 2025 and 2026 are shown in the table below:



	2025	2026
WTI ($/BBL)	56.46	57.23
NYMEX ($/MMBTU)	4.08	4.38
AECO (US$ Equivalent/MCF)	1.94	2.44

In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations. Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.

For the second quarter of 2025, production is expected to average between 177.0 and 185.0 thousand barrels of oil equivalents per day (MBOEPD), excluding noncontrolling interest.

The Company’s capital expenditure spend for 2025 is expected to be between $1,135 million and $1,285 million, excluding noncontrolling interest. This includes net acquisition capital of $104 million for the BW Pioneer FPSO in the Gulf of America. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2025 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

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.

On August 8, 2024, the Company’s Board of Directors has 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 as of March 31, 2025.

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

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

Outlook (Continued)

As of May 5, 2025, the Company has entered into forward fixed price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

Volumes

(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type 1

Start Date

End Date

Canada

Natural Gas

Fixed price forward sales

C$2.75

4/1/2025

12/31/2025

Canada

Natural Gas

Fixed price forward sales

C$3.03

1/1/2026

12/31/2026

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

Volumes

(MMCF/d)

Price/MCF

Remaining Period

Area

Commodity

Type

Start Date

End Date

United States

Natural Gas

Fixed price derivative swap

$3.58

4/1/2025

6/30/2025

United States

Natural Gas

Fixed price derivative swap

$3.65

7/1/2025

9/30/2025

United States

Natural Gas

Fixed price derivative swap

$3.74

10/1/2025

12/31/2025

Forward-Looking Statements

This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Item 1A. Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (“SEC”) and on page 40 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

There were commodity transactions in place as of March 31, 2025, covering certain future U.S. natural gas sales volumes in 2025. A 10% increase in the respective benchmark price of these commodities would have increased the net payable associated with these derivative contracts by approximately $6.4 million, while a 10% decrease would have decreased the recorded net payable by a similar amount.

Foreign Exchange Risk

There were no derivative foreign exchange contracts in place at March 31, 2025.

Interest Rate Risk

The Company’s RCF provides for variable interest rate borrowings. As of March 31, 2025, we had $200.0 million of outstanding borrowings under the RCF. Assuming no change in the amount of borrowings outstanding under the RCF, a 10% increase in the average interest rate would have increased our interest expense by approximately $0.1 million. Actual results may vary due to changes in the amount of variable rate debt outstanding.

ITEM 4. CONTROLS AND PROCEDURES

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

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

During the quarter ended March 31, 2025, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchase of Equity Securities:

The following table summarizes repurchases of our common stock occurring in the first quarter of 2025.


Period	Total Number of Shares Purchased	Average Price Paid Per Share1		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs 2,3 (in thousands)
January 1 through January 31, 2025	—	$	—	—	$	650,000
February 1 through February 28, 2025	3,613,450	$	27.67	3,613,450	$	550,000
March 1 through March 31, 2025	—	$	—	—	$	550,000

1 Amounts exclude 1% excise tax and fees on share repurchases.

2 On August 8, 2024, the Company announced an increase in its share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock. Pursuant to the share repurchase program, the Company may repurchase shares through open market purchases, privately negotiated transactions and other means in accordance with federal securities laws. 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.

3 Maximum approximate dollar values reported represent amounts at end of the month. Since the inception of the share repurchase program through to the end of the first quarter of 2025, the Company has repurchased 15,033,394 shares of its common stock in open-market transactions for $550 million, excluding taxes and fees.

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ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 6. EXHIBITS

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


Exhibit No.						Description

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

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SIGNATURE

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


			MURPHY OIL CORPORATION
			(Registrant)

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

May 7, 2025

(Date)

Murphy Oil - 10-Q quarterly report FY2025 Q1

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