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Murphy Oil
MUR
#3056
Rank
$5.34 B
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๐Ÿ‡บ๐Ÿ‡ธ United States
Country
$37.31
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3.09%
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  1. Murphy Oil
  2. Quarterly Reports (10-Q)
  3. Financial Year FY2026 Q1

Murphy Oil - 10-Q quarterly report FY2026 Q1


Text size:
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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, 2026
OR
☐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
murphyoilcorplogo.jpg
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware71-0361522
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification Number)
9805 Katy Fwy, Suite G-20077024
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 classTrading SymbolName of each exchange on which registered
Common Stock, $1.00 Par ValueMURNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes  ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  ☒ Yes    ☐ No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☒Accelerated filer☐Non-accelerated filer☐Smaller reporting company☐Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at April 30, 2026 was 143,349,576.


MURPHY OIL CORPORATION
TABLE OF CONTENTS
Page
2
Item 1.  Financial Statements
2
Consolidated Balance Sheets
2
Consolidated Statements of Operations
3
Consolidated Statements of Comprehensive Income
4
Consolidated Statements of Cash Flows
5
Consolidated Statements of Stockholders’ Equity
6
Notes to Consolidated Financial Statements
7
Note A – Basis of Presentation
7
Note B – New Accounting Principles and Recent Accounting Pronouncements
7
Note C – Revenue from Contracts with Customers
7
Note D – Property, Plant and Equipment
10
Note E – Financing Arrangements and Debt
11
Note F – Other Financial Information
12
Note G – Asset Retirement Obligations
12
Note H – Employee and Retiree Benefit Plans
12
Note I – Incentive Plans
13
Note J – Net Income Per Common Share
15
Note K – Income Taxes
15
Note L – Financial Instruments and Risk Management
15
Note M – Accumulated Other Comprehensive Loss
17
Note N – Environmental and Other Contingencies
17
Note O – Common Stock Issued and Outstanding
19
Note P – Business Segments
20
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of
              Operations
23
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
41
Item 4.  Controls and Procedures
41
42
Item 1.  Legal Proceedings
42
Item 1A.  Risk Factors
42
Item 5. Other Information
43
Item 6.  Exhibits
43
44
1
Table of Contents
PART I – FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

(Thousands of dollars, except share amounts)March 31,
2026		December 31,
2025
ASSETS
Current assets
Cash and cash equivalents$378,753 $377,196 
Accounts receivable, net
467,229 346,759 
Inventories58,428 57,284 
Prepaid expenses32,541 35,473 
Total current assets936,951 816,712 
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $15,277,325 in 2026 and $15,068,149 in 2025
8,265,324 8,136,346 
Operating lease assets738,315 805,464 
Deferred charges and other assets95,044 74,104 
Total assets$10,035,634 $9,832,626 
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt, finance lease$2,547 $2,514 
Accounts payable645,829 572,183 
Income taxes payable19,690 18,209 
Other taxes payable30,418 28,295 
Operating lease liabilities270,214 278,834 
Other accrued liabilities111,858 120,755 
Current asset retirement obligations53,630 41,959 
Total current liabilities1,134,186 1,062,749 
Long-term debt, including finance lease obligation1,548,147 1,382,566 
Asset retirement obligations972,503 970,908 
Deferred credits and other liabilities256,209 263,596 
Non-current operating lease liabilities479,161 537,773 
Deferred income taxes412,548 378,337 
Total liabilities$4,802,754 $4,595,929 
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
$— $— 
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,100,628 shares at March 31, 2026 and 195,100,628 shares at December 31, 2025
195,101 195,101 
Capital in excess of par value837,327 859,633 
Retained earnings6,694,131 6,691,318 
Accumulated other comprehensive loss(576,572)(554,227)
Treasury stock(2,051,091)(2,073,445)
Murphy Shareholders' Equity5,098,896 5,118,380 
Noncontrolling interest133,984 118,317 
Total equity5,232,880 5,236,697 
Total liabilities and equity$10,035,634 $9,832,626 

The accompanying notes are an integral part of these consolidated financial statements.
2
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended
March 31,
(Thousands of dollars, except per share amounts)20262025
Revenues and other income
Revenue from production$732,354 $672,730 
Total revenue from sales to customers732,354 672,730 
Gain (loss) on derivative instruments— (9,459)
Gain on sale of assets and other operating income1,198 2,440 
Total revenues and other income733,552 665,711 
Costs and expenses
Lease operating expenses143,464 205,079 
Severance and ad valorem taxes13,746 8,650 
Transportation, gathering and processing47,061 48,851 
Exploration expenses, including undeveloped lease amortization82,815 14,488 
Selling and general expenses34,870 30,915 
Depreciation, depletion and amortization254,376 194,160 
Accretion of asset retirement obligations14,514 14,045 
Other operating expense4,441 5,629 
Total costs and expenses595,287 521,817 
Operating income from continuing operations138,265 143,894 
Other income (loss)
Other income9,852 2,402 
Interest expense, net(28,977)(23,523)
Total other loss
(19,125)(21,121)
Income from continuing operations before income taxes119,140 122,773 
Income tax expense49,945 32,722 
Income from continuing operations69,195 90,051 
Loss from discontinued operations, net of income taxes(542)(633)
Net income including noncontrolling interest68,653 89,418 
Less: Net income attributable to noncontrolling interest15,667 16,382 
NET INCOME ATTRIBUTABLE TO MURPHY$52,986 $73,036 
NET INCOME PER COMMON SHARE – BASIC
Continuing operations$0.37 $0.51 
Discontinued operations— — 
Net income$0.37 $0.51 
NET INCOME PER COMMON SHARE – DILUTED
Continuing operations$0.37 $0.50 
Discontinued operations— — 
Net income$0.37 $0.50 
Cash dividends per common share$0.350 $0.325 
Average common shares outstanding (thousands)
Basic143,082 144,284 
Diluted144,381 145,072 
The accompanying notes are an integral part of these consolidated financial statements.
3
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
Three Months Ended
March 31,
(Thousands of dollars)20262025
Net income including noncontrolling interest$68,653 $89,418 
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation
(23,746)(1,667)
Retirement and postretirement benefit plans1,401 864 
Other comprehensive income (loss)
(22,345)(803)
Comprehensive income including noncontrolling interest46,308 88,615 
Less: Comprehensive income (loss) attributable to noncontrolling interest15,667 16,382 
COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY$30,641 $72,233 

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)20262025
Operating Activities
Net income including noncontrolling interest$68,653 $89,418 
Adjustments to reconcile net income to net cash provided by continuing operations activities
Depreciation, depletion and amortization254,376 194,160 
Unsuccessful exploration well costs and previously suspended exploration costs 67,043 190 
Deferred income tax expense36,864 16,343 
Accretion of asset retirement obligations14,514 14,045 
Long-term non-cash compensation15,433 9,905 
Amortization of undeveloped leases2,270 1,654 
Loss from discontinued operations542 633 
Unrealized loss on derivative instruments— 8,916 
Other operating activities, net(30,539)(11,799)
Net increase in non-cash working capital(107,972)(22,784)
Net cash provided by continuing operations activities321,184 300,681 
Investing Activities
Property additions and dry hole costs(387,838)(368,421)
Acquisition of oil and natural gas properties (22,681)(1,364)
Net cash required by investing activities(410,519)(369,785)
Financing Activities
Retirement of debt(227,489)— 
Early redemption of debt cost(2,369)— 
Debt issuance500,000 — 
Debt issuance cost
(7,819)— 
Borrowings on revolving credit facility 175,000 250,000 
Repayment of revolving credit facility (275,000)(50,000)
Issue costs of revolving credit facility
(12,213)— 
Repurchase of common stock, including excise tax(777)(100,072)
Cash dividends paid(50,173)(47,026)
Distributions to noncontrolling interest— (6,955)
Withholding tax on stock-based incentive awards(7,849)(7,673)
Finance lease obligation payments(419)(116)
Net cash provided by financing activities
90,892 38,158 
Effect of exchange rate changes on cash and cash equivalents— 291 
Net increase (decrease) in cash and cash equivalents
1,557 (30,655)
Cash and cash equivalents at beginning of period377,196 423,569 
Cash and cash equivalents at end of period$378,753 $392,914 

The accompanying notes are an integral part of these consolidated financial statements.
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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)20262025
Common Stock
Balance at beginning and end of period – par $1.00, authorized 450,000,000 shares at March 31, 2026 and March 31, 2025, issued 195,100,628 shares at March 31, 2026 and March 31, 2025
$195,101 $195,101 
Capital in Excess of Par Value
Balance at beginning of period859,633 848,950 
Restricted stock transactions and other(30,185)(27,338)
Share-based compensation7,879 9,333 
Balance at end of period837,327 830,945 
Retained Earnings
Balance at beginning of period6,691,318 6,773,289 
Net income attributable to Murphy52,986 73,036 
Cash dividends paid(50,173)(47,026)
Balance at end of period6,694,131 6,799,299 
Accumulated Other Comprehensive Loss
Balance at beginning of period(554,227)(628,072)
Foreign currency translation, net of income taxes(23,746)(1,667)
Retirement and postretirement benefit plans, net of income taxes1,401 864 
Balance at end of period(576,572)(628,875)
Treasury Stock
Balance at beginning of period(2,073,445)(1,995,018)
Repurchase of common stock— (100,876)
Awarded restricted stock, net of forfeitures22,354 19,683 
Balance at end of period – 51,751,915 shares of common stock at March 31, 2026 and 52,384,566 shares of common stock at March 31, 2025, at cost
(2,051,091)(2,076,211)
Murphy Shareholders’ Equity5,098,896 5,120,259 
Noncontrolling Interest
Balance at beginning of period118,317 147,593 
Net income attributable to noncontrolling interest15,667 16,382 
Distributions to noncontrolling interest owners— (6,955)
Balance at end of period133,984 157,020 
Total Equity$5,232,880 $5,277,279 

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, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2026 and 2025, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2025 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month period ended March 31, 2026 are not necessarily indicative of future results.

Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Income Tax Disclosures. In December 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. The Company adopted this standard in the fourth quarter of 2025. Interim period disclosures are largely unaffected by this update. The adoption did not affect the calculation of income tax expense.
Recent Accounting Pronouncements
Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impacts on our results of operations, cash flows and financial condition.
The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.

Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces oil and natural gas in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the United States (U.S.) and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil, natural gas and natural gas liquids (NGLs).
For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.
U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index-priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
The Company’s revenues and other income for the three-month periods ended March 31, 2026 and 2025 were as follows.
Three Months Ended
March 31,
(Thousands of dollars)20262025
Net crude oil and condensate revenue
United States - Onshore$188,348 $109,458 
United States - Offshore 1
333,441 352,362 
Canada - Onshore17,391 14,730 
Canada - Offshore53,336 74,469 
Other2,909 — 
Total crude oil and condensate revenue595,425 551,019 
Net natural gas liquids revenue
United States - Onshore9,275 8,487 
United States - Offshore 1
6,363 9,249 
Canada - Onshore1,318 1,747 
Total natural gas liquids revenue16,956 19,483 
Net natural gas revenue
United States - Onshore11,128 7,967 
United States - Offshore 1
26,150 19,941 
Canada - Onshore82,695 74,320 
Total natural gas revenue119,973 102,228 
Total revenue from sales to customers732,354 672,730 
Gain (loss) on derivative instruments— (9,459)
Gain on sale of assets and other operating income1,198 2,440 
Total revenues and other income$733,552 $665,711 
1 Includes revenue attributable to the noncontrolling interest in MP GOM.

Contract Balances and Asset Recognition
As of March 31, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $222.1 million and $165.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any revenue contracts that have financing components as of March 31, 2026.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.
As of March 31, 2026, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:
LocationCommodityEnd DateDescriptionApproximate Volumes
U.S.Natural Gas and NGLsQ1 2031Deliveries from dedicated acreage in Eagle Ford ShaleAs produced
CanadaNatural GasQ4 2026Contracts to sell natural gas at USD index pricing
49 MMCF/D
CanadaNatural GasQ4 2027Contracts to sell natural gas at USD index pricing
30 MMCF/D
CanadaNatural GasQ4 2028Contracts to sell natural gas at USD index pricing
10 MMCF/D
CanadaNatural Gas
Q4 2029
Contracts to sell natural gas at USD index pricing
25 MMCF/D
CanadaNatural GasQ4 2026Contracts to sell natural gas at CAD fixed pricing
50 MMCF/D
CanadaNatural GasQ4 2027Contracts to sell natural gas at CAD fixed pricing
9 MMCF/D
CanadaNGLs
Q4 2026
Contracts to sell NGLs at CAD index pricingAs produced
The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of March 31, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $266.8 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2026 and 2025.
(Thousands of dollars)20262025
Beginning balance at January 1$191,821 $72,055 
  Additions pending the determination of proved reserves84,599 24,790 
  Capitalized exploratory well costs charged to expense(9,610)— 
Balance at March 31$266,810 $96,845 
Capital additions of $84.6 million, for the three months ended March 31, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire; the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in Vietnam; and the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America. In the first quarter of 2026, Murphy announced the successful discoveries of the Banjo #1 and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, which encountered 50 feet and 30 feet of net pay, respectively. In addition, the Company also announced a successful appraisal well Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, in the Cuu Long Basin, located approximately 40 miles offshore of Vietnam.
Capital additions of $24.8 million, for the three months ended March 31, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam and long-lead equipment for the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America.
In the first quarter of 2026, the Company also announced the results of two exploration wells in Côte d’Ivoire; the Civette-1X (Block CI-502) exploration well, which encountered non-commercial hydrocarbons, and the Caracal-1X (Block CI-102) exploration well, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. Capitalized well costs charged to dry hole expense of $9.6 million, for the three months ended March 31, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire. There were no capitalized well costs charged to dry hole expense for the three months ended March 31, 2025.
The preceding table excludes well costs of $57.5 million incurred and expensed directly to dry hole for the three months ended March 31, 2026. In 2026, these costs primarily related to the Caracal-1X (Block CI-102) and Civette-1X (Block CI-502) exploration wells in Côte d’Ivoire.
The following table provides an aging of capitalized exploration well costs based on the date the drilling operations were initiated for each individual project.
March 31,
20262025
(Thousands of dollars)Amount
No. of Projects
Amount
No. of Projects
Aging of capitalized well costs:
Zero to one year$58,556 1 $9,421 2 
One to two years71,906 2 65,160 3 
Two to three years113,934 3 — — 
Three years or more22,414 3 22,264 3 
$266,810 9 $96,845 8 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
Of the $208.3 million of exploration well costs capitalized and classified as more than one year at March 31, 2026, $107.0 million was in Vietnam, $94.0 million was in the Gulf of America, $4.6 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Property Additions
During the first quarter of 2025, Murphy purchased a floating production storage and offloading vessel (FPSO) from BW Offshore (UK) Limited for a gross purchase price of $125.0 million. The Pioneer FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a five-year contract that began in 2025.
Impairments
There were no impairments in the three months ended March 31, 2026 and 2025.

Note E – Financing Arrangements and Debt
Revolving Credit Facility
In the first quarter of 2026, the Company entered into an amended credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. All terms of the Amended RCF are substantially similar to the previous senior unsecured guaranteed revolving credit facility (RCF) credit agreement, with an exception for the following: The “Adjusted Term SOFR Rate” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero. The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero. The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF.
At March 31, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%. At March 31, 2026, the Company was in compliance with all covenants related to the Amended RCF.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2027.
Debt Offering
In the first quarter of 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.50% per annum and mature on February 15, 2034. The Company has incurred transaction costs of $8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes.
Debt Extinguishment
In the first quarter of 2026, the Company redeemed the remaining $78.9 million principal amount outstanding of its 5.875% senior notes due 2027 (2027 Notes) and the remaining $148.6 million principal amount outstanding of its 6.375% senior notes due 2028 (2028 Notes), for an aggregate $227.5 million. The total cost of the debt extinguishment of $3.5 million consisted of cash costs of $2.5 million and non-cash costs of $1.0 million.

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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)20262025
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable $(120,525)$(10,089)
(Increase) decrease in inventories(479)(15,851)
(Increase) decrease in prepaid expenses2,799 10,502 
Increase (decrease) in accounts payable and accrued liabilities 8,752 (13,560)
Increase (decrease) in income taxes payable1,481 6,214 
Net (increase) decrease in non-cash working capital$(107,972)$(22,784)
Supplementary disclosures:
Interest paid, net of amounts capitalized of $3.9 million in 2026 and $1.1 million in 2025
$4,897 $6,347 
Non-cash investing activities:
Asset retirement costs capitalized$8,843 $8,996 
(Increase) decrease in capital expenditure accrual(54,000)(42,442)

Note G – Asset Retirement Obligations
The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.
A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the three-month periods ended March 31, 2026 and 2025 are shown in the following table.
(Thousands of dollars)March 31, 2026March 31, 2025
Balance at beginning of year$1,012,867 $1,008,884 
Accretion14,514 14,045 
Liabilities incurred10,064 4,996 
Revisions of previous estimates— 3,999 
Liabilities settled(8,941)(157)
Changes due to translation of foreign currencies(2,371)394 
Balance at end of period1,026,133 1,032,161 
Current portion of liability
(53,630)(77,452)
Non-current portion of liability$972,503 $954,709 
The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

Note H – Employee and Retiree Benefit Plans
The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note H – Employee and Retiree Benefit Plans (Continued)
the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2026 and 2025.
Three Months Ended March 31,
Pension BenefitsOther Postretirement Benefits
(Thousands of dollars)2026202520262025
Service cost$1,865 $1,683 $102 $84 
Interest cost7,752 8,398 750 708 
Expected return on plan assets(8,792)(8,871)— — 
Estimated defined contribution provision70 60 — — 
Amortization of prior service cost (credit)432 491 (133)(133)
Recognized actuarial (gain) loss 1,644 1,891 (387)(1,056)
Total net periodic benefit cost (credit)$2,971 $3,652 $332 $(397)
The components of net periodic benefit expense, other than the service cost, are recorded in “Other income” in the Consolidated Statements of Operations.
During the three-month period ended March 31, 2026, the Company made contributions of $7.0 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2026 for the Company’s defined benefit pension and postretirement plans is anticipated to be $22.5 million.

Note I – Incentive Plans
The Company recognizes expenses for all share-based and cash-based incentive compensation in the Consolidated Statements of Operations using a fair value-based measurement method over the applicable vesting periods.
The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
The 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) authorizes the Committee to grant shares of the Company’s common stock and stock-based awards to employees. These awards may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents, and other stock-based incentives. The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term.
Shares issued pursuant to awards granted under the 2025 Long-Term Plan may be shares that are authorized but unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Shares underlying awards that have been canceled, expired, are forfeited, or otherwise not issued under an award shall not count as shares issued under the Plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
During the three months ended March 31, 2026, the Committee granted the following awards from the 2025 Long-Term Plan:
Type of AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation Methodology
Performance-based RSUs 1
412,560February 3, 2026$32.67 Monte Carlo
Time-based RSUs (Stock-Settled) 2
811,620February 3, 2026$30.05 Average Stock Price
Time-based RSUs (Cash-Settled) 2
661,960February 3, 2026$30.05 Average Stock Price
1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) performance goals, measured over a three-year performance period based on (i) the Company’s TSR relative to a peer group and (ii) the Company’s absolute TSR performance, and are scheduled to vest at the end of the period subject to achievement of these conditions.
2 Time-based RSUs generally vest on the third anniversary of the date of grant.
The Company also maintains a Stock Plan for Non-Employee Directors (NEDs) that permits the issuance of RSUs, stock options, or a combination thereof to the Company’s Non-Employee Directors.
The Company currently has outstanding incentive awards issued to Directors under the 2021 Stock Plan for NEDs (the 2021 NED Plan) and the 2018 Stock Plan for NEDs. All awards granted on or after May 12, 2021 were made under the 2021 NED Plan.
During the three months ended March 31, 2026, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan:
Type of AwardNumber of Awards GrantedGrant DateGrant Date Fair ValueValuation Methodology
Time-Based RSUs 1
56,844February 4, 2026$31.67 Closing Stock Price
Time-Based RSUs 2
2,150March 31, 2026$41.25 Closing Stock Price
1 Non-Employee Directors’ time-based RSUs are scheduled to vest on the first anniversary of the date of grant. Non-Employee Directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election. These unvested time-based RSUs are included in the table above, will vest in one year, and become deferred RSUs.
2 Effective January 1, 2024, Non-Employee Directors can elect to receive their annual retainers in the form of deferred RSUs. Director fees that are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.
Three Months Ended
March 31,
(Thousands of dollars)20262025
Compensation charged against income before tax benefit$13,900 $8,864 
Related income tax benefit recognized in income2,279 1,175 
Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the current tax law.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note J – Net Income Per Common Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three-month periods ended March 31, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.
Three Months Ended
March 31,
(Weighted-average shares, except per share amounts)
20262025
Basic method143,081,801 144,283,946 
Dilutive restricted stock units
1,298,790 788,142 
Diluted method144,380,590 145,072,088 
NET INCOME PER COMMON SHARE – BASIC
$0.37 $0.51 
NET INCOME PER COMMON SHARE – DILUTED
$0.37 $0.50 

Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense divided by income from continuing operations before income taxes. For the three-month periods ended March 31, 2026 and 2025, the Company’s effective income tax rates were as follows:
20262025
Three months ended March 31,41.9%26.7%
The effective tax rate for the three-month period ended March 31, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate. The impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.
The effective tax rate for the three-month period ended March 31, 2025 was above the U.S. statutory tax rate of 21% primarily due to several factors including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. Federal rate; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.
For the three-month period ended March 31, 2026, the Company received $0.1 million in net cash income tax refunds, compared to $1.6 million in net cash income tax refunds for the three-month period ended March 31, 2025.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of March 31, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2021. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.

Note L – Financial Instruments and Risk Management
Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. 
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange derivative instruments outstanding at March 31, 2026 and 2025.
Commodity Price Risks
The Company is subject to commodity price risk related to products it produces and sells. During the first quarter of 2025, the Company entered into natural gas swap contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.
During the three months ended March 31, 2026, the Company did not have any crude oil or natural gas derivative contracts. At March 31, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows:
NYMEX Henry Hub
AreaCommodityVolumes MMCF/dPrice/MCFStart DateEnd Date
Fixed price derivative swapUnited StatesNatural Gas40$3.58 4/1/20256/30/2025
Fixed price derivative swapUnited StatesNatural Gas60$3.65 7/1/20259/30/2025
Fixed price derivative swapUnited StatesNatural Gas60$3.74 10/1/202512/31/2025
For the three-month periods ended March 31, 2026 and 2025, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:
(Thousands of dollars)Three Months Ended
March 31,
Type of Derivative ContractStatement of Operations Location20262025
Commodity swapsGain (loss) on derivative instruments$— $(9,459)
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The fair value measurements for these assets and liabilities at March 31, 2026 and December 31, 2025, are shown in the following table.
March 31, 2026December 31, 2025
(Thousands of dollars)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Liabilities:
Nonqualified employee savings plan$21,947 $— $— $21,947 $22,205 $— $— $22,205 
$21,947 $— $— $21,947 $22,205 $— $— $22,205 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in “Selling and general expenses” in the Consolidated Statements of Operations.
The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at March 31, 2026 and December 31, 2025.
The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at March 31, 2026 and December 31, 2025. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, were minimal.
March 31, 2026December 31, 2025
(Thousands of dollars)Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Financial liabilities:
Current and long-term debt
$1,550,694 $1,468,657 $1,385,080 $1,326,101 
Fair Values – Nonrecurring
There were no impairment charges incurred in the three months ended March 31, 2026 and 2025.

Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and March 31, 2026, and the changes during the three-month period ended March 31, 2026, are presented net of taxes in the following table.
(Thousands of dollars)Foreign
Currency
Translation
Gains (Losses)
Retirement and
Postretirement
Benefit Plan
Adjustments
Total
Balance at December 31, 2025$(442,331)$(111,896)$(554,227)
Components of other comprehensive income (loss):
Before reclassifications to income(23,746)— (23,746)
Reclassifications to income ¹— 1,401 1,401 
Net other comprehensive income (loss)(23,746)1,401 (22,345)
Balance at March 31, 2026$(466,077)$(110,495)$(576,572)
1  Reclassifications before taxes of $1.7 million are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2026. See Note H for additional information. Related income taxes of $0.3 million are included in "Income tax expense” on the Consolidated Statements of Operations for the three-month period ended March 31, 2026.

Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; trade policies, tariffs and other trade restrictions; royalty and revenue sharing increases; import and export controls;
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Note N – Environmental and Other Contingencies (Continued)

price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.
ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other greenhouse gas (GHG) emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased.
Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $1.0 million threshold.
In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the One Big Beautiful Bill Act (OBBBA) passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)

regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions.
The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Note O – Common Stock Issued and Outstanding
Activity in the number of shares of common stock issued and outstanding for the three-month periods ended March 31, 2026 and 2025 is shown below.
(Number of shares outstanding)
March 31, 2026March 31, 2025
Beginning of period142,785,152 145,845,124 
Restricted stock awards 1
563,561 484,388 
Treasury shares purchased
— (3,613,450)
End of period143,348,713 142,716,062 
1 Shares issued upon award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.
On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors.
During the three months ended March 31, 2026, the Company did not repurchase any shares of its common stock. During the three months ended March 31, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.9 million including excise taxes and fees). As of March 31, 2026, the Company had $550.1 million of its common stock remaining available to repurchase under the program.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments
Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia and U.S. refining and marketing operations as discontinued operations for all periods presented. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the Chief Operating Decision Maker (CODM).
“Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income attributed to the Canada segment.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
Exploration and Production
(Millions of dollars)
United
States 1
CanadaOtherTotal
E&P
Corporate and Discontinued Operations
Consolidated
Total
Three Months Ended March 31, 2026
Revenue from production
$574.7 $154.8 $2.9 $732.4 $— $732.4 
Gain on sale of assets and other operating income
0.8 0.4 — 1.2 — 1.2 
Total revenues and other income
575.5 155.2 2.9 733.6 — 733.6 
Lease operating expenses
Lease operating expenses and taxes other than income
80.8 41.8 0.8 123.4 — 123.4 
Repair and maintenance
12.3 0.7 — 13.0 — 13.0 
Workovers4.7 2.4 — 7.1 — 7.1 
Total lease operating expenses
97.8 44.9 0.8 143.5 — 143.5 
Severance and ad valorem taxes12.9 0.8 — 13.7 — 13.7 
Transportation, gathering and processing25.2 21.9 — 47.1 — 47.1 
Selling and general expenses5.5 7.5 2.1 15.1 19.8 34.9 
Exploration Expenses
Geological and geophysical0.8 — 0.8 1.6 — 1.6 
Dry holes and previously suspended exploration costs
— — 67.1 67.1 — 67.1 
Other exploratory costs, including undeveloped lease amortization and delay lease rentals
4.9 — 9.2 14.1 — 14.1 
Total exploration expenses5.7 — 77.1 82.8 — 82.8 
Depreciation, depletion and amortization216.9 34.0 1.1 252.0 2.4 254.4 
Accretion of asset retirement obligations11.6 2.6 0.2 14.4 0.1 14.5 
Other operating expenses
4.0 0.1 0.3 4.4 — 4.4 
Interest Income(0.2)— — (0.2)(2.3)(2.5)
Interest expense, net of capitalization
0.1 0.1 — 0.2 28.8 29.0 
Income tax expense
Current income tax expense
1.0 9.6 0.3 10.9 2.2 13.1 
Deferred income tax expense (benefit)
37.3 1.6 3.4 42.3 (5.5)36.8 
Total income tax expense (benefit)
38.3 11.2 3.7 53.2 (3.3)49.9 
Other segment costs (income)
1.1 0.4 0.3 1.8 (8.6)(6.8)
Segment income (loss) - including NCI 1
$156.6 $31.7 $(82.7)$105.6 $(36.9)$68.7 
Additions to property, plant, equipment$254.8 $62.1 $71.3 $388.2 $9.3 $397.5 
Total assets at quarter-end
6,916.5 1,980.3 660.7 9,557.5 478.110,035.6 
1 Includes results attributable to the 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
CanadaOtherTotal
E&P
Corporate and Discontinued Operations
Consolidated
Total
Three Months Ended March 31, 2025
Revenue from production
$507.4 $165.3 $— $672.7 $— $672.7 
Gain on sale of assets and other operating income (loss)
2.1 0.4 — 2.5 (9.5)(7.0)
Total revenues and other income
509.5 165.7 — 675.2 (9.5)665.7 
Lease operating expenses
Lease operating expenses and taxes other than income
100.3 45.2 0.4 145.9 — 145.9 
Repair and maintenance
10.2 1.6 — 11.8 — 11.8 
Workovers47.1 0.3 — 47.4 — 47.4 
Total lease operating expenses
157.6 47.1 0.4 205.1 — 205.1 
Severance and ad valorem taxes8.4 0.3 — 8.7 — 8.7 
Transportation, gathering and processing28.7 20.2 — 48.9 — 48.9 
Selling and general expenses2.0 6.0 1.9 9.9 21.0 30.9 
Exploration Expenses
Geological and geophysical3.2 — 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 expenses6.1 0.1 8.3 14.5 — 14.5 
Depreciation, depletion and amortization159.4 32.4 0.1 191.9 2.3 194.2 
Accretion of asset retirement obligations11.3 2.5 0.2 14.0 — 14.0 
Other operating expenses2.6 0.9 0.1 3.6 2.0 5.6 
Interest Income(0.4)— — (0.4)(3.3)(3.7)
Interest expense, net of capitalization
— — — — 23.5 23.5 
Income tax expense
Current income tax expense
0.5 13.7 — 14.2 2.1 16.3 
Deferred income tax expense (benefit)
24.5 0.6 — 25.1 (8.7)16.4 
Total income tax expense (benefit)
25.0 14.3 — 39.3 (6.6)32.7 
Other segment costs
0.9 0.4 0.2 1.5 0.4 1.9 
Segment income (loss) - including NCI 1
$107.9 $41.5 $(11.2)$138.2 $(48.8)$89.4 
Additions to property, plant, equipment$317.1 $55.4 $35.3 $407.8 $4.2 $412.0 
Total assets at quarter-end
7,046.3 1,963.4 345.7 9,355.4 464.9 9,820.3 
1 Includes results attributable to the noncontrolling interest in MP GOM.

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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, 2026 included under “Item 1. Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2025. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.
Overview
Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The Company boasts over a century of strong execution and innovative, full-cycle development capabilities, with a focus on value creation to enhance shareholder returns. The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire.
The analysis and discussion in this section includes amounts attributable to the noncontrolling interest in MP GOM, unless otherwise noted.
Significant Company financial and operational highlights during the first quarter of 2026 were as follows:
•Increased production to 180,053 barrels of oil equivalent (BOE) per day (including NCI), up from 163,374 BOE per day in the first quarter of 2025;
•Drilled oil discoveries at Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, and announced dry holes at Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) in Côte d’Ivoire;
•Issued $500.0 million of 6.50% senior notes due 2034 (2034 Notes) and used proceeds to redeem an aggregate $227.5 million of senior notes due in 2027 and 2028;
•Upsized senior unsecured revolving credit facility from $1.35 billion to $2.0 billion and extended maturity from 2029 to 2031;
•Increased the quarterly cash dividend to $0.35 per share, which on an annualized basis would be $1.40 per share.
Subsequent to the first quarter, the Company’s offer for four exploration blocks in offshore Cameroon was accepted, with finalization of the terms pending further discussions with the Republic of Cameroon.
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended March 31, 2026, was $69.2 million compared to net income of $90.1 million for the same period in 2025. The results for 2026 were impacted by higher exploration expense ($68.3 million), higher depreciation, depletion and amortization expenses (DD&A) ($60.2 million), and higher income tax expense ($17.2 million) and were partially offset by higher revenues from production ($59.6 million), lower lease operating expenses ($61.6 million), and lower losses from derivative instruments ($9.5 million).
Higher exploration expenses in the current quarter were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons. Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S. and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S. and offshore Canada. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, certain exploration expenses did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available. Higher volumes in the Eagle Ford Shale and onshore Canada were the primary contributors to higher revenues for the period and were partially offset by lower volumes in other segments. Higher realized prices onshore U.S. and both onshore and offshore Canada also contributed to the increase but were partially offset by lower realized prices offshore U.S. Lower lease operating expenses are due to lower
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
workover costs in the current quarter. Lower losses from derivative instruments were due to having no open derivative contracts during the first quarter of 2026.
For the three months ended March 31, 2026, total hydrocarbon production was 180,053 barrels of oil equivalent per day, an increase of 10% compared to the first quarter of 2025. The increase was principally due to higher production in the Eagle Ford Shale and Tupper Montney, partially offset by lower offshore production in the Gulf of America. Higher production in the Eagle Ford Shale and Canada Onshore was primarily the result of new wells online in the current year at Karnes and Catarina in the U.S., and at Tupper Montney in Canada. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.
Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.
At March 31, 2026, the West Texas Intermediate (WTI) crude oil futures price were $82.75 per barrel, whereas the crude oil futures price at the end of April 2026 was $90.56, reflecting a 9% increase in price. As of May 4, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $93.58 per barrel. Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.

Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below:
Income (Loss)
Three Months Ended
March 31,
(Millions of dollars)20262025
Exploration and production
United States$156.6 $107.9 
Canada31.7 41.5 
Other (82.7)(11.2)
Total exploration and production
105.6 138.2 
Corporate and other(36.4)(48.2)
Income from continuing operations69.2 90.0 
Discontinued operations, net of tax 1
(0.5)(0.6)
Net income including noncontrolling interest68.7 89.4 
Less: Net income attributable to noncontrolling interest
15.7 16.4 
Net income attributable to Murphy
$53.0 $73.0 
1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
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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)20262025
Revenues and other income
Revenue from production
$732.4 $672.7 
Other income
1.2 2.5 
Total revenues and other income
733.6 675.2 
Costs and expenses
Lease operating expenses143.5 205.1 
Severance and ad valorem taxes13.7 8.7 
Transportation, gathering and processing47.1 48.9 
Depreciation, depletion and amortization252.0 191.8 
Accretion of asset retirement obligations14.4 14.0 
Exploration expenses, including undeveloped lease amortization
82.8 14.5 
Selling and general expenses15.1 9.9 
Other 6.2 4.8 
Results of operations before taxes158.8 177.5 
Income tax provisions
53.2 39.3 
Results of operations (excluding Corporate segment) 1
$105.6 $138.2 
1 Includes results attributable to a noncontrolling interest in MP GOM.
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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, 2026 and 2025:
Three Months Ended
March 31,
(Weighted average sales prices)20262025
Crude oil and condensate – dollars per barrel
United States - Onshore
$73.44 $71.65 
United States - Offshore 1
70.97 72.32 
Canada - Onshore 2
65.89 63.34 
Canada - Offshore 2
78.19 74.36 
Other 2
71.04 — 
Natural gas liquids – dollars per barrel
United States - Onshore17.60 23.16 
United States - Offshore 1
16.45 27.02 
Canada - Onshore 2
27.73 36.08 
Natural gas – dollars per thousand cubic feet
United States - Onshore3.74 3.38 
United States - Offshore 1
5.68 4.33 
Canada - Onshore 2
2.44 2.38 
1  Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
The following table contains benchmark prices relevant to the Company for the three-month periods ended March 31, 2026 and 2025:
Three Months Ended
March 31,
(Average price for the period)20262025
Oil and NGLs
WTI ($/BBL)$71.93 $71.42 
Natural gas
NYMEX ($/MMBTU)4.87 4.27 
AECO (C$/MCF)2.01 2.17 
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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, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.
Three Months Ended
March 31,
(Barrels per day unless otherwise noted)20262025
Net crude oil and condensate
United States - Onshore
28,497 16,974 
United States - Offshore 1
51,839 55,587 
Canada - Onshore
2,932 2,584 
Canada - Offshore
9,006 8,855 
Other224 255 
Total net crude oil and condensate
92,498 84,255 
Net natural gas liquids
United States - Onshore
5,856 4,072 
United States - Offshore 1
4,298 3,804 
Canada - Onshore
528 538 
Total net natural gas liquids
10,682 8,414 
Net natural gas – thousands of cubic feet per day
United States - Onshore
33,082 26,190 
United States - Offshore 1
51,153 51,150 
Canada - Onshore
377,001 346,892 
Total net natural gas
461,236 424,232 
Total net hydrocarbons - including NCI 2,3
180,053 163,374 
Noncontrolling interest
Net crude oil and condensate – barrels per day(5,281)(5,779)
Net natural gas liquids – barrels per day(226)(170)
   Net natural gas – thousands of cubic feet per day (1,857)(1,234)
Total noncontrolling interest 2,3
(5,817)(6,154)
Total net hydrocarbons - excluding NCI 2,3
174,236 157,220 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.

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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, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 29.
Three Months Ended
March 31,
(Barrels per day unless otherwise noted)20262025
Net crude oil and condensate
United States - Onshore
28,497 16,974 
United States - Offshore 1
52,205 54,133 
Canada - Onshore
2,932 2,584 
Canada - Offshore
7,579 11,128 
Other455 — 
Total net crude oil and condensate
91,668 84,819 
Net natural gas liquids
United States - Onshore
5,856 4,072 
United States - Offshore 1
4,298 3,804 
Canada - Onshore
528 538 
Total net natural gas liquids
10,682 8,414 
Net natural gas – thousands of cubic feet per day
United States - Onshore
33,082 26,190 
United States - Offshore 1
51,153 51,150 
Canada - Onshore
377,001 346,892 
Total net natural gas
461,236 424,232 
Total net hydrocarbons - including NCI 2,3
179,223 163,938 
Noncontrolling interest
Net crude oil and condensate – barrels per day(5,333)(5,567)
Net natural gas liquids – barrels per day(226)(170)
Net natural gas – thousands of cubic feet per day(1,857)(1,234)
Total noncontrolling interest 2,3
(5,869)(5,942)
Total net hydrocarbons - excluding NCI 2,3
173,354 157,996 
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.



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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)20262025
Revenues from production
United States - Oil
$521.8 $461.8 
United States - Natural gas liquids
15.6 17.8 
United States - Natural gas
37.3 27.9 
Canada - Oil
70.8 89.2 
Canada - Natural gas liquids
1.3 1.7 
Canada - Natural gas
82.7 74.3 
Other - Oil
2.9 — 
Total revenue from production
$732.4 $672.7 
Revenues from production for the three months ended March 31, 2026, increased $59.6 million compared to the same period in 2025. New wells in the Karnes and Catarina fields in the Eagle Ford Shale were the primary contributor to higher revenues for the period, contributing both higher volumes and realized prices. Canada also realized higher prices, but overall revenues were lower due to fewer cargoes offshore Canada compared to 2025. In the Gulf of America, both production and realized prices were lower compared to the first quarter of 2025. Lower offshore U.S. production was primarily attributable to planned turnarounds at several fields and was partially offset by wells back online from workover downtime in 2025.

Lease Operating and Transportation, Gathering and Processing Expenses
The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:
Three Months Ended March 31,
(Millions of dollars)
(Dollars per equivalent barrel)
2026202520262025
Lease operating expenses
United States - Onshore
$32.4 $29.8 $9.02 $13.02 
United States - Offshore
65.4 127.8 11.17 21.37 
Canada - Onshore
33.0 30.2 5.53 5.51 
Canada - Offshore
11.9 16.9 17.42 16.89 
Other0.8 0.4 19.55 — 
Total lease operating expenses
$143.5 $205.1 $8.89 $13.90 
Transportation, gathering and processing
United States - Onshore
$2.7 $2.4 $0.76 $1.00 
United States - Offshore
22.5 26.4 3.84 4.42 
Canada - Onshore
20.5 18.3 3.43 3.34 
Canada - Offshore
1.4 1.8 2.02 1.80 
Total transportation, gathering and processing
$47.1 $48.9 $2.92 $3.31 

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
For the three months ended March 31, 2026, lease operating expenses decreased by $61.6 million, and transportation, gathering and processing expenses decreased by $1.8 million compared to the same period in 2025. Lower lease operating expenses are due to lower workover costs in the Gulf of America in the current quarter, particularly at the Samurai field. Further decreases in the Gulf of America are attributable to lower vessel rental costs as a result of the purchase of the Pioneer FPSO in 2025. Offshore Canada realized lower operating costs in the current quarter due to fewer cargoes in 2026 compared to 2025.

Depreciation, Depletion and Amortization Expenses
The Company’s DD&A by geographic area were as follows:
Three Months Ended March 31,
(Millions of dollars)
(Dollars per equivalent barrel)
2026202520262025
DD&A
United States - Onshore
$113.3 $67.1 $31.58 $29.35 
United States - Offshore
103.6 92.2 17.69 15.42 
Canada - Onshore
26.3 24.1 4.42 4.40 
Canada - Offshore
7.7 8.3 11.22 8.26 
Other1.1 0.1 26.95 — 
Total DD&A
$252.0 $191.8 $15.62 $13.00 
DD&A for the three months ended March 31, 2026 increased by $60.2 million. Higher DD&A in the current quarter is primarily due to higher sales volumes onshore U.S. and onshore Canada, as well as higher rates in the Gulf of America, and was partially offset by lower sales volumes offshore U.S. and offshore Canada.

Exploration Expenses
The Company’s exploration expenses were as follows:
Three Months Ended
March 31,
(Millions of dollars)20262025
Exploration expenses
Dry holes and previously suspended exploration costs$67.1 $0.2 
Geological and geophysical1.6 3.6 
Other exploration11.8 9.1 
Undeveloped lease amortization2.3 1.6 
Total exploration expenses, including undeveloped lease amortization
$82.8 $14.5 
Exploration expenses for the three months ended March 31, 2026 increased by $68.3 million compared to the same period in 2025. Higher exploration expenses in the current quarter were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons.

Income Taxes
Income taxes for the three months ended March 31, 2026 increased by $13.9 million compared to the same period in 2025. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, higher exploration expenses, mainly due to dry hole expenses recognized related to Côte d’Ivoire, did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)

Corporate
Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge commodity price) and corporate overhead not allocated to E&P. Realized and unrealized gains and losses on derivative instruments result from changes in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.
The Corporate segment reported a loss of $36.4 million for the three months ended March 31, 2026, a favorable variance of $11.8 million, compared to the same period in 2025. The favorable variance was primarily due to no losses on derivative instruments ($9.5 million) in the current quarter and higher foreign exchange gains ($8.8 million). These changes were partially offset by higher interest expense ($5.3 million) due to costs related to the redemption of the 2027 Notes and 2028 Notes.

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

Cash Flows
The following table presents the Company’s cash flows for the periods presented:
Three Months Ended
March 31,
(Millions of dollars)
20262025
Net cash provided (required) by:
Net cash provided by continuing operations activities$321.2 $300.7 
Net cash required by investing activities
(410.5)(369.8)
Net cash provided by financing activities
90.9 38.2 
Effect of exchange rate changes on cash and cash equivalents— 0.3 
Net increase (decrease) in cash and cash equivalents$1.6 $(30.7)
Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities for the three months ended March 31, 2026 was $20.5 million higher compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized prices and volumes resulting in higher revenue from production ($59.6 million) and lower lease operating expenses ($61.6 million), partially offset by the timing of net non-cash working capital ($85.2 million) and changes in other operating activities, net ($18.7 million), primarily due to fluctuations in foreign exchange rates ($8.9 million) and higher expenditures for asset retirements ($8.8 million).
Cash Required by Investing Activities
Net cash required by investing activities for the three months ended March 31, 2026 was $40.7 million higher compared to the same period in 2025. The increase was primarily due to higher acquisition capital ($21.3 million) and higher property additions and dry hole costs ($19.4 million).
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Three Months Ended
March 31,
(Millions of dollars)20262025
Property additions and dry hole costs$387.8 $368.4 
Acquisition of oil and natural gas properties 22.7 1.4 
Geophysical and other exploration expenses13.4 11.6 
Capital expenditure accrual changes and other54.0 43.4 
Total capital expenditures$477.9 $424.8 
Total accrual basis capital expenditures are shown below.
Three Months Ended
March 31,
(Millions of dollars)20262025
Capital Expenditures
Exploration and production$468.8 $420.6 
Corporate9.1 4.2 
Total capital expenditures$477.9 $424.8 
Higher capital expenditures in the three months ended March 31, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory and development drilling in the Gulf of America, and higher development drilling in Vietnam, which included progressing the LDV-A platform jacket installation and pipe-laying campaign. These increases were partially offset by lower field development costs in the Gulf of America due to the prior year spend on the Pioneer FPSO purchase in the Gulf of America.
Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($105.8 million), Eagle Ford Shale ($98.9 million), Tupper Montney and Kaybob Duvernay ($54.8 million), and in Vietnam ($24.0 million). Exploration costs in 2026 were $178.1 million, primarily comprised of activities in Côte d'Ivoire related to exploration drilling for Bubale-1X (Block CI-709), Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells. Exploration costs were also driven by activities in the Gulf of America including lease acquisitions and exploration drilling at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells, and activities in Vietnam for the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 exploration well.
Cash Provided by Financing Activities
Net cash provided by financing activities for the three months ended March 31, 2026 increased by $52.7 million compared to the same period in 2025.
In 2026, the cash provided by financing activities was principally from a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million. The bond issuance was partially offset by the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), cash dividends to shareholders of $0.350 per share ($50.2 million), and $20.0 million in debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance.
In 2025, net cash provided by financing activities was from net borrowings on the senior unsecured RCF ($200.0 million), partially offset by the repurchase of common shares ($100.1 million), cash dividends to shareholders ($47.0 million), withholding tax on stock-based incentive awards ($7.7 million), and distributions to the noncontrolling interest in MP GOM ($7.0 million).

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Liquidity
At March 31, 2026, the Company had approximately $2.4 billion of liquidity consisting of $378.8 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured Amended RCF with a major banking consortium.
The Company’s $2.0 billion senior unsecured Amended RCF expires in January 2031. As of March 31, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At March 31, 2026, the interest rate in effect on borrowings under the Amended RCF would have been 5.91%. At March 31, 2026, the Company was in compliance with all covenants related to the Amended RCF.
Cash and invested cash are maintained in several operating locations outside the U.S. As of March 31, 2026, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $94.6 million, the majority of which was held in Canada ($35.2 million), Côte d'Ivoire ($24.8 million), Vietnam ($10.5 million), Mexico ($7.9 million), Brunei ($6.9 million), and the U.K. ($6.3 million) . In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Working Capital
(Millions of dollars)March 31, 2026December 31, 2025
Working capital
Total current assets$937.0 $816.7 
Total current liabilities1,134.2 1,062.7 
Net working capital liability
$(197.2)$(246.0)
As of March 31, 2026, net working capital increased by $48.8 million compared to December 31, 2025. The increase was primarily attributable to higher accounts receivable ($120.5 million) and lower current operating lease obligations ($8.6 million), partially offset by higher accounts payable ($73.6 million).
Higher accounts receivable and accounts payable were due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively. Lower lease obligations were due to lower day rates related to an offshore drilling rig, ongoing lease amortization and the absence of lease rental payments related to the Pioneer FPSO in the Gulf of America.
Capital Employed
A summary of capital employed at March 31, 2026 and December 31, 2025 follows.
March 31, 2026December 31, 2025
(Millions of dollars)Amount%Amount%
Capital employed
Long-term debt$1,548.1 23.3 %$1,382.6 21.3 %
Murphy shareholders' equity5,098.9 76.7 %5,118.4 78.7 %
Total capital employed$6,647.0 100.0 %$6,501.0 100.0 %
At March 31, 2026, long-term debt of $1,548.1 million increased by $165.5 million compared to December 31, 2025, primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.9 years and a weighted average coupon of 6.2%.
Murphy shareholders’ equity decreased by $19.5 million in 2026, primarily due to dividends ($50.2 million), foreign currency translation ($23.7 million), partially offset by net income ($53.0 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Critical Accounting Estimates
As of March 31, 2026, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2025.

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

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics
The Company uses other operational performance and income metrics to review operational performance.
Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
Three Months Ended
March 31,
(Millions of dollars, except per share amounts)
20262025
Net income attributable to Murphy (GAAP) 1
$53.0 $73.0 
Discontinued operations loss0.5 0.6 
Net income from continuing operations attributable to Murphy
53.5 73.6 
Adjustments:
Foreign exchange gain(9.4)— 
Unrealized loss on derivative instruments— 8.9 
Total adjustments, before taxes(9.4)8.9 
Income tax (benefit) expense related to adjustments
2.4 (1.8)
Total adjustments, after taxes(7.0)7.1 
Adjusted net income from continuing operations attributable to Murphy
(Non-GAAP)
$46.5 $80.7 
Net income from continuing operations per average diluted share (GAAP)
$0.37 $0.50 
Adjusted net income from continuing operations per average diluted share (Non-GAAP)$0.32 $0.56 
1  Excludes amounts attributable to a noncontrolling interest in MP GOM.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
The following table reconciles net income (loss) attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.  
Three Months Ended
March 31,
(Millions of dollars)20262025
Net income attributable to Murphy (GAAP) 1
$53.0 $73.0 
Income tax expense49.9 32.7 
Interest expense, net29.0 23.5 
Depreciation, depletion and amortization expense 1
246.9 187.4 
EBITDA attributable to Murphy (Non-GAAP) 1
$378.8 $316.6 
Exploration expenses 1
82.8 14.5 
EBITDAX attributable to Murphy (Non-GAAP) 1
$461.6 $331.1 
EBITDA attributable to Murphy (Non-GAAP) 1
$378.8 $316.6 
Foreign exchange gain
(9.4)— 
Accretion of asset retirement obligations 1
13.0 12.5 
Unrealized loss on derivative instruments— 8.9 
Discontinued operations loss0.5 0.6 
Adjusted EBITDA attributable to Murphy (Non-GAAP) 1
$382.9 $338.6 
Exploration expenses 1
82.8 14.5
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1
$465.7 $353.1 
1  Excludes amounts attributable to a noncontrolling interest in MP GOM.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.   
The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.

Three Months Ended
March 31,
(Millions of dollars)20262025
Net cash provided by continuing operations activities (GAAP)$321.2 $300.7 
Exclude: increase in non-cash working capital
108.0 22.8 
Operating cash flow excluding working capital adjustments (Non-GAAP)
429.2 323.5 
Less: property additions and dry hole costs 1
(387.8)(368.4)
Free cash flow (Non-GAAP)$41.4 $(44.9)
Less: cash dividends paid(50.2)(47.0)
Less: distributions to noncontrolling interest— (7.0)
Less: debt costs(22.4)— 
Less: withholding tax on stock-based incentive awards(7.8)(7.7)
Less: acquisition of oil and natural gas properties(22.7)(1.4)
Adjusted free cash flow (Non-GAAP)$(61.7)$(108.0)
1 Property additions for the three months ended March 31, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, including amounts attributable to a noncontrolling interest in MP GOM.

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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 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.
As of close on May 4, 2026, forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.
20262027
WTI ($/BBL)93.5876.88
NYMEX ($/MMBTU)3.393.64
AECO (US$ Equivalent/MCF)1.371.79
The regional conflict involving Iran has contributed to heightened geopolitical risk and significant volatility in global energy and shipping markets, primarily due to disruptions affecting transit through the Strait of Hormuz, which is a critical passage for oil, LNG, and other refined products. Although these developments have led to higher commodity prices, these developments have also led to increased transportation and insurance costs, and broader uncertainty across global supply chains, which may indirectly affect the Company through fluctuations in oil and gas prices, changes in demand, and higher operating or input costs. During the period, the Company has not experienced direct physical disruption to its operations, and the Company’s financial and operating results have been favorably impacted by price volatility. Looking forward, a prolonged or escalating conflict could further disrupt global energy flows, exacerbate price volatility, constrain access to markets or services, and adversely affect macroeconomic conditions, which could materially impact the Company’s future operating results, cash flows, and financial position.
Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate. Although we are continuing to monitor the economic effects of tariff announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.
On July 4, 2025, the current U.S. Administration signed into law the OBBBA legislation, which includes a broad range of tax reform provisions affecting corporations. The Company evaluated the effects of the OBBBA in accordance with ASC 740, Income Taxes, and determined that the legislation did not have a material impact on its consolidated financial statements for the period ended March 31, 2026. The Company will continue to monitor any subsequent regulatory guidance related to the OBBBA.
We cannot predict what impact economic factors (including, but not limited to, inflation, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations. Similarly, we cannot predict the impact that political instability or armed conflict in oil and natural gas producing regions, such as in Russia and Ukraine, the Middle East, and Venezuela, may have on pricing, global supply and demand for oil and gas. It is also uncertain how production quota decisions by OPEC and OPEC+, along with changes in membership, may influence pricing and the global supply–demand balance. Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.
For the second quarter of 2026, production is expected to average between 161.0 and 169.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.
The Company’s capital expenditures for 2026 are expected to be between $1,200 million and $1,300 million, excluding noncontrolling interest. This range excludes noncontrolling interest of $53.0 million.
In the Gulf of America, Murphy will continue developing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter. In addition, the Company commenced drilling at the Chinook #8 (Walker Ridge 425) development well.
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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook (Continued)
The Company commenced drilling on its third Côte d’Ivoire exploration well, Bubale-1X (Block CI-709), during the first quarter, with results expected in the second quarter.
The appraisal program at the Hai Su Vang (Golden Sea Lion) prospect in Vietnam is continuing on schedule following the successful completion of the Hai Su Vang-2X (Block 15-2/17) appraisal well in the first quarter. Also in the first quarter, the Company began drilling the Hai Su Vang-3X (Block 15-1/05) appraisal well. Hai Su Vang-3X is then expected to be followed by the Hai Su Vang-4X (Block 15-2/17) appraisal well.
Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with scheduled first oil anticipated in the fourth quarter of 2026.
Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, as well as changing commodity price environments, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2026 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company plans to utilize any surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation plan designed to allow for additional shareholder returns and debt reduction. Details of the plan can be found in the “Capital Allocation” section of the Company’s Form 8-K filed on May 7, 2025. Based on current market conditions and our planned exploration and appraisal program, the Company is currently more likely to use available adjusted Free Cash Flow for share repurchases than bond repayment.
On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of March 31, 2026.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the senior unsecured Amended RCF (see Note E).
As of May 4, 2026, the Company has entered into forward fixed price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
Volumes
(MMCF/d)		Price/MCFRemaining Period
AreaCommodity
Type 1
Start DateEnd Date
CanadaNatural GasFixed price forward sales78C$2.944/1/20266/30/2026
CanadaNatural GasFixed price forward sales78C$2.947/1/20269/30/2026
CanadaNatural GasFixed price forward sales59C$3.0010/1/202612/31/2026
CanadaNatural GasFixed price forward sales9.5C$3.141/1/202712/31/2027
1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Forward-Looking Statements
This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and intent to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other environmental, social and governance matters, make capital expenditures, pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply and demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns (including the current conflict in Iran); increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or markets of health pandemics and related government responses; natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; cyber attacks and other cybersecurity risks; any failure to obtain necessary regulatory approvals; the impact of current and future laws, rulings and governmental regulations; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Item 1A. Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (SEC) and on page 42 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Each forward-looking statement contained in this report speaks only as of the date of this report. Except as required by applicable law, Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, foreign currency exchange rates, and interest rates. As described in Note L, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
Commodity Price Risk
There were no commodity-based derivative contracts in place as of March 31, 2026.
Foreign Exchange Risk
There were no derivative foreign exchange contracts in place at March 31, 2026.
Interest Rate Risk
The Company’s senior unsecured Amended RCF provides for variable interest rate borrowings. As of March 31, 2026, we had no outstanding borrowings under the Amended RCF, and therefore, no related exposure to interest rate risk.

ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended March 31, 2026, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS
The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in “Item 1A. Risk Factors” in the Company’s 2025 Form 10-K filed on February 25, 2026. The Company has not identified any additional risk factors not previously disclosed in its 2025 Form 10-K report.

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ITEM 5. OTHER INFORMATION
During the three months ended March 31, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 6. EXHIBITS
The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed as indicated by double asterisks (**), or that are incorporated by reference. Exhibits other than those listed have been omitted since they are either not required or not applicable.
Exhibit
No.
Description
3.1
Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005 (incorporated by reference to Exhibit 3.1 to Form 10-K of Registrant filed on February 28, 2011)
3.2
By-Laws of Murphy Oil Corporation, as amended effective August 5, 2020 (incorporated by reference to Exhibit 3.2 to Form 10-Q of Registrant filed on August 6, 2020)
4.1
Eighth Supplemental Indenture, dated as of January 23, 2026, between Murphy Oil Corporation and Regions Bank, as trustee (including the Form of 6.500% Notes due 2034) (incorporated by reference to Exhibit 4.2 to Form 8-K of Registrant filed on January 23, 2026)
10.1
Second Amendment to the Credit Agreement dated as of January 2, 2026 among Murphy Oil Corporation, Murphy Exploration & Production Company – International and Murphy Oil Company Ltd. as borrowers, Murphy Exploration & Production Company and Murphy Exploration & Production Company – USA, as guarantors, JP Morgan Chase Bank, N.A. as administrative agent, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K of Registrant filed on January 6, 2026)
*31.1
*31.2
**32.1
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. SCHInline XBRL Taxonomy Extension Schema Document
101. CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101. DEFInline XBRL Taxonomy Extension Definition Linkbase Document
101. LABInline XBRL Taxonomy Extension Labels Linkbase Document
101. PREInline 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 6, 2026
(Date)
44

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