Murphy Oil Corp 10-Q for FY2026 Q2
Murphy Oil Corp (MUR)
10-Q
2026-08-05
For: 2026-06-30
View Original
Added on
August 05, 2026
About this 10-Q
Murphy Oil Corp filed this 10-Q on August 5, 2026, covering the quarter ended June 30, 2026 (FY2026 Q2).
Headline figures
Quarter ended June 30, 2026, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $928.31M
- up 33.5% from $695.57M a year earlier
- Net income
- $232.18M
- up 942.1% from net income of $22.28M a year earlier
- Diluted EPS
- $1.59
- up 893.8% from $0.16 a year earlier
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) | |||||
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended June 30, 2026
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
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |||||||
| (Zip Code) | ||||||||
| (Address of principal executive offices) | ||||||||
| (Registrant’s telephone number, including area code) | ||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
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.
| ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | Emerging growth company | |||||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2026 was 143,381,125 .
MURPHY OIL CORPORATION
TABLE OF CONTENTS
| Page | ||||||||
1
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| (Thousands of dollars, except share amounts) | June 30, 2026 | December 31, 2025 | |||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
Accounts receivable, net | |||||||||||
| Inventories | |||||||||||
| Prepaid expenses | |||||||||||
| Total current assets | |||||||||||
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $ | |||||||||||
| Operating lease assets | |||||||||||
| Deferred charges and other assets | |||||||||||
| Total assets | $ | $ | |||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current maturities of long-term debt, finance lease | $ | $ | |||||||||
| Accounts payable | |||||||||||
| Income taxes payable | |||||||||||
| Other taxes payable | |||||||||||
| Operating lease liabilities | |||||||||||
| Other accrued liabilities | |||||||||||
| Current asset retirement obligations | |||||||||||
| Total current liabilities | |||||||||||
| Long-term debt, including finance lease obligation | |||||||||||
| Asset retirement obligations | |||||||||||
| Deferred credits and other liabilities | |||||||||||
| Non-current operating lease liabilities | |||||||||||
| Deferred income taxes | |||||||||||
| Total liabilities | $ | $ | |||||||||
| Equity | |||||||||||
Cumulative Preferred Stock, par $ | $ | $ | |||||||||
Common Stock, par $ | |||||||||||
| Capital in excess of par value | |||||||||||
| Retained earnings | |||||||||||
| Accumulated other comprehensive loss | ( | ( | |||||||||
| Treasury stock | ( | ( | |||||||||
| Murphy Shareholders' Equity | |||||||||||
| Noncontrolling interest | |||||||||||
| Total equity | |||||||||||
| Total liabilities and equity | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
2
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | $ | $ | $ | |||||||||||||||||||
| Total revenue from sales to customers | |||||||||||||||||||||||
| Gain on derivative instruments | |||||||||||||||||||||||
| Gain on sale of assets and other operating income | |||||||||||||||||||||||
| Total revenues and other income | |||||||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | |||||||||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||||||||
| Transportation, gathering and processing | |||||||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | |||||||||||||||||||||||
| Selling and general expenses | |||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||
| Accretion of asset retirement obligations | |||||||||||||||||||||||
| Other operating expense | |||||||||||||||||||||||
| Total costs and expenses | |||||||||||||||||||||||
| Operating income from continuing operations | |||||||||||||||||||||||
| Other income (loss) | |||||||||||||||||||||||
| Other income (loss) | ( | ( | |||||||||||||||||||||
| Interest expense, net | ( | ( | ( | ( | |||||||||||||||||||
| Total other loss | ( | ( | ( | ( | |||||||||||||||||||
| Income from continuing operations before income taxes | |||||||||||||||||||||||
| Income tax expense | |||||||||||||||||||||||
| Income from continuing operations | |||||||||||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | ( | ( | |||||||||||||||||||||
| Net income including noncontrolling interest | |||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | |||||||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO MURPHY | $ | $ | $ | $ | |||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | $ | $ | $ | |||||||||||||||||||
| Discontinued operations | ( | ||||||||||||||||||||||
| Net income | $ | $ | $ | $ | |||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | $ | $ | $ | |||||||||||||||||||
| Discontinued operations | ( | ||||||||||||||||||||||
| Net income | $ | $ | $ | $ | |||||||||||||||||||
| Cash dividends per common share | $ | $ | $ | $ | |||||||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | |||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
3
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net income including noncontrolling interest | $ | $ | $ | $ | |||||||||||||||||||
Other comprehensive income (loss), net of tax | |||||||||||||||||||||||
Net gain (loss) from foreign currency translation | ( | ( | |||||||||||||||||||||
| Retirement and postretirement benefit plans | |||||||||||||||||||||||
Other comprehensive income (loss) | ( | ( | |||||||||||||||||||||
| Comprehensive income including noncontrolling interest | |||||||||||||||||||||||
| Less: Comprehensive income attributable to noncontrolling interest | |||||||||||||||||||||||
| COMPREHENSIVE INCOME ATTRIBUTABLE TO MURPHY | $ | $ | $ | $ | |||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Operating Activities | |||||||||||
| Net income including noncontrolling interest | $ | $ | |||||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||
| Depreciation, depletion and amortization | |||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | ( | ||||||||||
| Deferred income tax expense | |||||||||||
| Accretion of asset retirement obligations | |||||||||||
| Long-term non-cash compensation | |||||||||||
| Amortization of undeveloped leases | |||||||||||
| (Income) loss from discontinued operations | ( | ||||||||||
| Unrealized gain on derivative instruments | ( | ||||||||||
| Other operating activities, net | ( | ( | |||||||||
| Net (increase) decrease in non-cash working capital | ( | ||||||||||
| Net cash provided by continuing operations activities | |||||||||||
| Investing Activities | |||||||||||
| Property additions and dry hole costs | ( | ( | |||||||||
| Acquisition of oil and natural gas properties | ( | ( | |||||||||
| Net cash required by investing activities | ( | ( | |||||||||
| Financing Activities | |||||||||||
| Retirement of debt | ( | ||||||||||
| Early redemption of debt cost | ( | ||||||||||
| Debt issuance | |||||||||||
Debt issuance cost | ( | ||||||||||
| Borrowings on revolving credit facility | |||||||||||
| Repayment of revolving credit facility | ( | ( | |||||||||
Issue costs of revolving credit facility | ( | ( | |||||||||
| Repurchase of common stock, including excise tax | ( | ( | |||||||||
| Cash dividends paid | ( | ( | |||||||||
| Distributions to noncontrolling interest | ( | ( | |||||||||
| Withholding tax on stock-based incentive awards | ( | ( | |||||||||
| Finance lease obligation payments | ( | ( | |||||||||
| Net cash provided (required) by financing activities | ( | ||||||||||
| Effect of exchange rate changes on cash and cash equivalents | ( | ||||||||||
Net increase (decrease) in cash and cash equivalents | ( | ||||||||||
| Cash and cash equivalents at beginning of period | |||||||||||
| Cash and cash equivalents at end of period | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Thousands of dollars except number of shares) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Common Stock | |||||||||||||||||||||||
Balance at beginning and end of period – par $ | $ | $ | $ | $ | |||||||||||||||||||
| Capital in Excess of Par Value | |||||||||||||||||||||||
| Balance at beginning of period | |||||||||||||||||||||||
| Restricted stock transactions and other | ( | ( | ( | ( | |||||||||||||||||||
| Share-based compensation | |||||||||||||||||||||||
| Balance at end of period | |||||||||||||||||||||||
| Retained Earnings | |||||||||||||||||||||||
| Balance at beginning of period | |||||||||||||||||||||||
| Net income attributable to Murphy | |||||||||||||||||||||||
| Cash dividends paid | ( | ( | ( | ( | |||||||||||||||||||
| Balance at end of period | |||||||||||||||||||||||
| Accumulated Other Comprehensive Loss | |||||||||||||||||||||||
| Balance at beginning of period | ( | ( | ( | ( | |||||||||||||||||||
| Foreign currency translation, net of income taxes | ( | ( | |||||||||||||||||||||
| Retirement and postretirement benefit plans, net of income taxes | |||||||||||||||||||||||
| Balance at end of period | ( | ( | ( | ( | |||||||||||||||||||
| Treasury Stock | |||||||||||||||||||||||
| Balance at beginning of period | ( | ( | ( | ( | |||||||||||||||||||
| Repurchase of common stock | ( | ||||||||||||||||||||||
| Awarded restricted stock, net of forfeitures | |||||||||||||||||||||||
Balance at end of period – | ( | ( | ( | ( | |||||||||||||||||||
| Murphy Shareholders’ Equity | |||||||||||||||||||||||
| Noncontrolling Interest | |||||||||||||||||||||||
| Balance at beginning of period | |||||||||||||||||||||||
| Net income attributable to noncontrolling interest | |||||||||||||||||||||||
| Distributions to noncontrolling interest owners | ( | ( | ( | ( | |||||||||||||||||||
| Balance at end of period | |||||||||||||||||||||||
| Total Equity | $ | $ | $ | $ | |||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.
Note A – Basis of Presentation
The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at June 30, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2026 and 2025, in conformity with U.S. generally accepted accounting principles (GAAP). In preparing the financial statements of the Company in conformity with GAAP, management has made a number of estimates and assumptions that affect the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
Consolidated financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2025 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three and six months ended June 30, 2026 are not necessarily indicative of future results.
Note B – New Accounting Principles and Recent Accounting Pronouncements
Accounting Principles Adopted
Income Tax Disclosures. In December 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The update requires financial statements to include consistent categories and greater disaggregation of information in the rate reconciliation, as well as income taxes paid disaggregated by jurisdiction. The Company adopted this standard in the fourth quarter of 2025. Interim period disclosures are largely unaffected by this update. The adoption did not affect the calculation of income tax expense.
Recent Accounting Pronouncements
Expense Disaggregation Disclosures. In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard becomes effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The standard requires specified information about certain costs and expenses presented on the face of the income statement to be further disaggregated in the notes to the financial statements. In addition, the standard requires certain expense and cost information that is not separately disaggregated to be qualitatively described. We are currently evaluating our expense categories and underlying cost components to identify the quantitative and qualitative disclosures that will be required upon adoption. We expect this ASU to only impact our disclosures with no impact on our results of operations, cash flows and financial condition.
The Company evaluates the applicability and impact of all ASUs. ASUs not specifically discussed above were assessed and determined to be not applicable, previously disclosed, or not material upon adoption.
Note C – Revenue from Contracts with Customers
Nature of Goods and Services
The Company explores for and produces oil and natural gas in select basins around the world. The Company’s revenue from sales of oil and natural gas production activities is primarily subdivided into two key geographic segments: the United States (U.S.) and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil, natural gas and natural gas liquids (NGLs).
For operated oil and natural gas production where a non-operated working interest owner does not take in kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest (NCI) in MP Gulf of Mexico, LLC (MP GOM) as prescribed by GAAP.
U.S. - In the U.S., the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of America. Revenue is generally recognized when oil and natural gas is transferred to the customer at the delivery point. Revenue recognized is largely index-based with price adjustments for floating market differentials.
Canada - In Canada, contracts include long-term floating commodity index-priced and natural gas physical forward sales fixed-price contracts. For the offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. The Company also purchases natural gas in Canada to meet certain sales commitments.
Disaggregation of Revenue
The Company reviews performance based on two key geographical segments and between onshore and offshore sources of revenue within these geographies.
The Company’s revenues and other income for the three and six months ended June 30, 2026 and 2025 were as follows.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Thousands of dollars) | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||
| Net crude oil and condensate revenue | ||||||||||||||||||||||||||
| United States - Onshore | $ | $ | $ | $ | ||||||||||||||||||||||
United States - Offshore 1 | ||||||||||||||||||||||||||
| Canada - Onshore | ||||||||||||||||||||||||||
| Canada - Offshore | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total crude oil and condensate revenue | ||||||||||||||||||||||||||
| Net natural gas liquids revenue | ||||||||||||||||||||||||||
| United States - Onshore | ||||||||||||||||||||||||||
United States - Offshore 1 | ||||||||||||||||||||||||||
| Canada - Onshore | ||||||||||||||||||||||||||
| Total natural gas liquids revenue | ||||||||||||||||||||||||||
| Net natural gas revenue | ||||||||||||||||||||||||||
| United States - Onshore | ||||||||||||||||||||||||||
United States - Offshore 1 | ||||||||||||||||||||||||||
| Canada - Onshore | ||||||||||||||||||||||||||
| Total natural gas revenue | ||||||||||||||||||||||||||
| Total revenue from sales to customers | ||||||||||||||||||||||||||
| Gain on derivative instruments | ||||||||||||||||||||||||||
| Gain on sale of assets and other operating income | ||||||||||||||||||||||||||
| Total revenues and other income | $ | $ | $ | $ | ||||||||||||||||||||||
1 Includes revenue attributable to the noncontrolling interest in MP GOM.
Contract Balances and Asset Recognition
As of June 30, 2026, and December 31, 2025, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $213.3 million and $165.3 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on a forward-looking expected loss model
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
in accordance with ASU 2016-13, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.
The Company has not entered into any revenue contracts that have financing components as of June 30, 2026.
The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.
Performance Obligations
The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.
For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.
The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the Company’s long-term strategy.
As of June 30, 2026, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period over 12 months starting at the inception of the contract:
| Location | Commodity | End Date | Description | Approximate Volumes | ||||||||||||||||||||||
| U.S. | Natural Gas and NGLs | Q1 2031 | Deliveries from dedicated acreage in Eagle Ford Shale | As produced | ||||||||||||||||||||||
| Canada | Natural Gas | Q4 2026 | Contracts to sell natural gas at USD index pricing | |||||||||||||||||||||||
| Canada | Natural Gas | Q4 2027 | Contracts to sell natural gas at USD index pricing | |||||||||||||||||||||||
| Canada | Natural Gas | Q4 2028 | Contracts to sell natural gas at USD index pricing | |||||||||||||||||||||||
| Canada | Natural Gas | Q4 2029 | Contracts to sell natural gas at USD index pricing | |||||||||||||||||||||||
| Canada | Natural Gas | Q4 2026 | Contracts to sell natural gas at CAD fixed pricing | |||||||||||||||||||||||
| Canada | Natural Gas | Q4 2027 | Contracts to sell natural gas at CAD fixed pricing | |||||||||||||||||||||||
| Canada | NGLs | Q4 2026 | Contracts to sell NGLs at CAD index pricing | As produced | ||||||||||||||||||||||
The fixed price contracts above are accounted for as normal sales and purchases for accounting purposes.
Note D – Property, Plant and Equipment
Exploratory Wells
Under FASB guidance, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
As of June 30, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $371.6 million. The following table reflects the net changes in capitalized exploratory well costs during the six months ended June 30, 2026 and 2025.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Beginning balance at January 1 | $ | $ | |||||||||
| Additions pending the determination of proved reserves | |||||||||||
| Capitalized exploratory well costs charged to expense | ( | ||||||||||
| Balance at June 30 | $ | $ | |||||||||
Capital additions of $190.4 million, for the six months ended June 30, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) well in Côte d’Ivoire; the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America; and the Hai Su Vang-3X (Golden Sea Lion) well, Block 15-1/05 in Vietnam.
In the second quarter of 2026, Murphy announced a discovery at the Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire, with the well encountering 100 feet of net pay across two reservoirs. In addition, Murphy concluded the Hai Su Vang (Golden Sea Lion) appraisal program for Hai Su Vang-2X (Block 15-2/17), Hai Su Vang-3X (Block 15-1/05) and Hai Su Vang-4X (Block 15-2/17) appraisal wells in Vietnam.
Subsequent to the second quarter of 2026, Murphy spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d’Ivoire and Lac Da Trang North-1X (White Camel) exploration well in Block 15-1/05 offshore Vietnam.
In the first quarter of 2026, Murphy announced the successful discoveries of the Banjo #1 and Cello #1 (Mississippi Canyon 385) exploration wells in the Gulf of America, which encountered 50 feet and 30 feet of net pay, respectively. In addition, the Company announced a successful appraisal well Hai Su Vang-2X (Golden Sea Lion), Block 15-2/17, in the Cuu Long Basin, located approximately 40 miles offshore of Vietnam.
Capital additions of $38.5 million, for the six months ended June 30, 2025, were mainly for the Hai Su Vang-1X (Golden Sea Lion), Block 15-2/17; and Lac Da Hong-1X (Pink Camel), Block 15-1/05 exploration wells in Vietnam and long-lead equipment for the Cello #1 and Banjo #1 (Mississippi Canyon 385) exploration wells in the Gulf of America.
Capitalized well costs charged to dry hole expense of $10.6 million, for the six months ended June 30, 2026, were primarily related to the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, which was plugged and abandoned as a dry hole after encountering non-commercial hydrocarbon shows. There were no capitalized well costs charged to dry hole expense for the six months ended June 30, 2025.
The preceding table excludes well costs of $70.0 million incurred and expensed directly to dry hole for the six months ended June 30, 2026. In 2026, these costs primarily related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, which encountered non-commercial hydrocarbons, the Caracal-1X (Block CI-102) exploration well in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion), Block 15-2/17 appraisal well in Vietnam.
The following table provides an aging of capitalized exploration costs based on the date the drilling operations were initiated for each individual project.
| June 30, | |||||||||||||||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Amount | No. of Projects | Amount | No. of Projects | |||||||||||||||||||||||||||||||
| Aging of capitalized well costs: | |||||||||||||||||||||||||||||||||||
| Zero to one year | $ | $ | |||||||||||||||||||||||||||||||||
| One to two years | |||||||||||||||||||||||||||||||||||
| Two to three years | |||||||||||||||||||||||||||||||||||
| Three years or more | |||||||||||||||||||||||||||||||||||
| $ | $ | ||||||||||||||||||||||||||||||||||
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
Of the $371.6 million of exploration well costs capitalized and classified as more than one year at June 30, 2026, $150.3 million was in Côte d’Ivoire, $114.0 million was in Vietnam, $100.1 million was in the Gulf of America, $4.5 million was in Canada, and $2.7 million was in Brunei. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.
Property Additions
During the first quarter of 2025, Murphy purchased a floating production storage and offloading vessel (FPSO) from BW Offshore (UK) Limited for a gross purchase price of $125.0 million. The Pioneer FPSO remained on location, supporting operations at the Cascade field (Walker Ridge 206 and 250) and Chinook field (Walker Ridge 469 and 425) in the Gulf of America. BW Offshore (UK) Limited continues to provide operations and maintenance services under a five-year contract that began in 2025.
Impairments
There were no
Note E – Financing Arrangements and Debt
Revolving Credit Facility
In the first quarter of 2026, the Company entered into an amended credit agreement governing a $2.0 billion senior unsecured guaranteed revolving credit facility (Amended RCF), with a maturity date of January 2, 2031. All terms of the Amended RCF are substantially similar to the previous senior unsecured guaranteed revolving credit facility (RCF) credit agreement, with an exception for the following: The “Adjusted Term Secured Overnight Financing Rate (SOFR)” of interest is equal to (a) the Term SOFR Rate for such Interest Period, plus (b) zero . The “Adjusted Daily Simple SOFR Rate” of interest is equal to (a) the Daily Simple SOFR, plus (b) zero . The “Applicable Rate” of interest means, for any day, the applicable rate per annum based upon the ratings of Moody’s Investors Service, Inc. and Standard and Poor’s Rating Services, respectively. The Company incurred $12.3 million in transaction costs and recorded the amount to “Deferred charges and other assets” in the Consolidated Balance Sheets, which is being amortized to interest expense over the term of the Amended RCF.
At June 30, 2026, the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At June 30, 2026, the interest rate in effect on borrowings under the Amended RCF was 5.90 %. At June 30, 2026, the Company was in compliance with all covenants related to the Amended RCF.
The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) that permits the offer and sale of debt and/or equity securities through October 15, 2027.
Debt Offering
In the first quarter of 2026, the Company closed a public offering of $500.0 million aggregate principal amount of its senior notes that bear interest at a rate of 6.50 % per annum and mature on February 15, 2034. The Company has incurred transaction costs of $8.3 million on the issuance of these new notes. The Company will pay interest semi-annually on August 15 and February 15 of each year, beginning August 15, 2026. The proceeds of the $500.0 million notes were used to fund the repurchase and repayment of debt and related fees, as well as for general corporate purposes.
Debt Extinguishment
In the first quarter of 2026, the Company redeemed the remaining $78.9 million principal amount outstanding of its 5.875 % senior notes due 2027 (2027 Notes) and the remaining $148.6 million principal amount outstanding of its 6.375 % senior notes due 2028 (2028 Notes), for an aggregate $227.5 million. The total cost of the debt extinguishment of $3.5 million consisted of cash costs of $2.5 million and non-cash costs of $1.0 million.
11
Note F – Other Financial Information
Supplemental Information to Statement of Cash Flows
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Net (increase) decrease in operating working capital, excluding cash and cash equivalents: | |||||||||||
| (Increase) decrease in accounts receivable | $ | ( | $ | ( | |||||||
| (Increase) decrease in inventories | ( | ( | |||||||||
| (Increase) decrease in prepaid expenses | ( | ( | |||||||||
| Increase (decrease) in accounts payable and accrued liabilities | |||||||||||
| Increase (decrease) in income taxes payable | |||||||||||
| Net (increase) decrease in non-cash working capital | $ | ( | $ | ||||||||
| Supplementary disclosures: | |||||||||||
Interest paid, net of amounts capitalized of $ | $ | $ | |||||||||
| Non-cash investing activities: | |||||||||||
| Asset retirement costs capitalized | $ | $ | |||||||||
| (Increase) decrease in capital expenditure accrual | ( | ||||||||||
Note G – Asset Retirement Obligations
The asset retirement obligations liabilities (ARO) recognized by the Company are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.
A reconciliation of the beginning and ending aggregate carrying amount of the ARO for the six months ended June 30, 2026 and 2025 are shown in the following table.
| (Thousands of dollars) | June 30, 2026 | June 30, 2025 | |||||||||
| Balance at beginning of year | $ | $ | |||||||||
| Accretion | |||||||||||
| Liabilities incurred | |||||||||||
| Revisions of previous estimates | |||||||||||
| Liabilities settled | ( | ( | |||||||||
| Changes due to translation of foreign currencies | ( | ||||||||||
| Balance at end of period | |||||||||||
Current portion of liability | ( | ( | |||||||||
| Non-current portion of liability | $ | $ | |||||||||
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
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note H – Employee and Retiree Benefit Plans (Continued)
the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors other postretirement benefits such as health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.
The table that follows provides the components of net periodic benefit expense for the three and six months ended June 30, 2026 and 2025.
| Three Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||
| Interest cost | |||||||||||||||||||||||
| Expected return on plan assets | ( | ( | |||||||||||||||||||||
| Estimated defined contribution provision | |||||||||||||||||||||||
| Amortization of prior service cost (credit) | ( | ( | |||||||||||||||||||||
| Recognized actuarial (gain) loss | ( | ( | |||||||||||||||||||||
| Total net periodic benefit cost (credit) | $ | $ | $ | $ | ( | ||||||||||||||||||
| Six Months Ended June 30, | |||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| (Thousands of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||
| Interest cost | |||||||||||||||||||||||
| Expected return on plan assets | ( | ( | |||||||||||||||||||||
| Estimated defined contribution provision | |||||||||||||||||||||||
| Amortization of prior service cost (credit) | ( | ( | |||||||||||||||||||||
| Recognized actuarial (gain) loss | ( | ( | |||||||||||||||||||||
| Total net periodic benefit cost (credit) | $ | $ | $ | $ | ( | ||||||||||||||||||
The components of net periodic benefit expense, other than the service cost, are recorded in “Other income (loss)” in the Consolidated Statements of Operations.
During the six months ended June 30, 2026, the Company made contributions of $15.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2026 for the Company’s defined benefit pension and postretirement plans is anticipated to be $15.1 million.
Note I – Incentive Plans
The Company recognizes expenses for all share-based and cash-based incentive compensation in the Consolidated Statements of Operations using a fair value-based measurement method over the applicable vesting periods.
The Annual Incentive Plan (AIP) authorizes the Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the AIP are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.
The 2025 Long-Term Incentive Plan (the 2025 Long-Term Plan) authorizes the Committee to grant shares of the Company’s common stock and stock-based awards to employees. These awards may be in the form of stock
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
options (nonqualified or incentive), stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance units, performance shares, dividend equivalents, and other stock-based incentives. The 2025 Long-Term Plan expires in 2035, and a total of 3.885 million shares of common stock are authorized for issuance over its term.
Shares issued pursuant to awards granted under the 2025 Long-Term Plan may be shares that are authorized but unissued or shares that were reacquired by the Company, including shares repurchased on the open market. Shares underlying awards that have been canceled, expired, are forfeited, or otherwise not issued under an award shall not count as shares issued under the Plan.
During the six months ended June 30, 2026, the Committee granted the following awards from the 2025 Long-Term Plan:
| Type of Award | Number of Awards Granted | Grant Date | Grant Date Fair Value | Valuation Methodology | ||||||||||||||||||||||
Performance-based RSUs 1 | February 3, 2026 | $ | Monte Carlo | |||||||||||||||||||||||
Time-based RSUs (Stock-Settled) 2 | February 3, 2026 | $ | Average Stock Price | |||||||||||||||||||||||
Time-based RSUs (Cash-Settled) 2 | February 3, 2026 | $ | Average Stock Price | |||||||||||||||||||||||
1 Performance-based RSUs are tied to the achievement of Total Shareholder Return (TSR) performance goals, measured over a three-year performance period based on (i) the Company’s TSR relative to a peer group and (ii) the Company’s absolute TSR performance, and are scheduled to vest at the end of the period subject to achievement of these conditions.
2 Time-based RSUs generally vest on the third anniversary of the date of grant.
In May 2026, the Company’s shareholders approved the 2026 Stock Plan for Non-Employee Directors (the 2026 NED Plan) to replace the 2021 Stock Plan for Non-Employee Directors (the 2021 NED Plan). All awards granted on or after May 13, 2026, will be made under the 2026 NED Plan. The 2026 NED Plan will expire in 2036 and authorizes the issuance of up to 900,000 shares of common stock over its term. Additional information on the 2026 NED Plan can be found in Exhibit A to the definitive proxy statement filed on March 27, 2026.
Similar to the 2021 NED Plan, the 2026 NED Plan permits the issuance of restricted stock, RSUs and stock options or a combination thereof to the Company’s Non-Employee Directors. The Company currently has outstanding incentive awards issued to directors under the 2026, 2021 and 2018 Stock Plans for Non-Employee Directors.
During the six months ended June 30, 2026, the Committee granted the following awards to Non-Employee Directors under the 2021 NED Plan (before May 13, 2026) and the 2026 NED Plan (after May 13, 2026):
| Type of Award | Number of Awards Granted | Grant Date | Grant Date Fair Value | Valuation Methodology | ||||||||||||||||||||||
Time-Based RSUs 1 | February 4, 2026 | $ | Closing Stock Price | |||||||||||||||||||||||
Time-Based RSUs 2 | March 31, 2026 | $ | Closing Stock Price | |||||||||||||||||||||||
Time-Based RSUs 2 | June 30, 2026 | $ | Closing Stock Price | |||||||||||||||||||||||
1 Non-Employee Directors’ time-based RSUs generally vest on the first anniversary of the date of grant. Non-Employee Directors may elect to defer settlement of their vested time-based RSUs until (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.
2 Non-Employee Directors may elect to receive all or a portion of their annual cash retainers in the form of deferred RSUs. Director fees that are deferred into RSUs are calculated and expensed each quarter by taking fees earned in respect of the applicable quarter and dividing by the closing price of our common stock on the last trading day of the quarter. Each deferred RSU represents the right to receive one share of common stock following (1) termination of service from the Board or (2) a future date selected by the director at the time of their deferral election.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.
| Six Months Ended June 30, | |||||||||||
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Compensation charged against income before tax benefit | $ | $ | |||||||||
| Related income tax benefit recognized in income | |||||||||||
Note J – Net Income Per Common Share
Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per common share for the three and six months ended June 30, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(Weighted-average shares, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Basic method | |||||||||||||||||||||||
Dilutive restricted stock units | |||||||||||||||||||||||
| Diluted method | |||||||||||||||||||||||
NET INCOME PER COMMON SHARE – BASIC | $ | $ | $ | $ | |||||||||||||||||||
NET INCOME PER COMMON SHARE – DILUTED | $ | $ | $ | $ | |||||||||||||||||||
Note K – Income Taxes
The Company’s effective income tax rate is calculated as the amount of income tax expense divided by income from continuing operations before income taxes. For the three and six months ended June 30, 2026 and 2025, the Company’s effective income tax rates were as follows:
| 2026 | 2025 | ||||||||||
| Three months ended June 30, | |||||||||||
| Six months ended June 30, | |||||||||||
The effective tax rate for the three months ended June 30, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; and the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate. The impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.
The effective tax rate for the three months ended June 30, 2025 was below the U.S. statutory tax rate of 21% primarily due to no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.
The effective tax rate for the six months ended June 30, 2026 was above the U.S. statutory tax rate of 21% primarily due to several factors including: certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available; U.S. state tax expense; stock-based compensation; and the effects of income generated in foreign tax jurisdictions, certain of which have income tax
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note K – Income Taxes (Continued)
rates higher than the U.S. federal rate. The impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM.
The effective tax rate for the six months ended June 30, 2025 was above the U.S. statutory tax rate of 21% due to several factors including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates higher than the U.S. federal rate; U.S. state tax expense; stock-based compensation; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are currently available. These impacts were partially offset by no tax applied to the pretax income of the noncontrolling interest in MP GOM, and a Canada tax credit received.
For the six months ended June 30, 2026, the Company paid $5.9 million in net cash income tax payments, compared to $0.4 million in net cash income tax payments for the six months ended June 30, 2025.
The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. Additionally, the Company could be required to pay amounts into an escrow account as any matters are identified and appealed with the relevant taxing authorities. As of June 30, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2021. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019.
Note L – Financial Instruments and Risk Management
Murphy, at times, uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.
Foreign Currency Exchange Risks
The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no
Commodity Price Risks
The Company is subject to commodity price risk related to products it produces and sells. During the three and six months ended June 30, 2026, the Company did no t have any crude oil or natural gas derivative contracts.
During the second quarter of 2025, the Company held open natural gas swap contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.
| NYMEX Henry Hub | Area | Commodity | Volumes MMCF/d | Price/MCF | Start Date | End Date | ||||||||||||||
| Fixed price derivative swap | United States | Natural Gas | $ | 7/1/2025 | 9/30/2025 | |||||||||||||||
| Fixed price derivative swap | United States | Natural Gas | $ | 10/1/2025 | 12/31/2025 | |||||||||||||||
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
For the three and six months ended June 30, 2026 and 2025, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table:
| (Thousands of dollars) | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||
| Type of Derivative Contract | Statement of Operations Location | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||
| Commodity swaps | Gain on derivative instruments | $ | $ | $ | $ | |||||||||||||||||||||||||||
Fair Values – Recurring
The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.
The fair value measurements for these assets and liabilities at June 30, 2026 and December 31, 2025, are shown in the following table.
| June 30, 2026 | December 31, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Nonqualified employee savings plan | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
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
The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at June 30, 2026 and December 31, 2025. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. Substantially all of the Company’s long-term debt is actively traded in open markets, and accordingly, is classified as Level 1 in the fair value hierarchy. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was minimal.
| June 30, 2026 | December 31, 2025 | ||||||||||||||||||||||||||||||||||
| (Thousands of dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||||||||||||||
Financial liabilities: | |||||||||||||||||||||||||||||||||||
Current and long-term debt | $ | $ | $ | $ | |||||||||||||||||||||||||||||||
Fair Values – Nonrecurring
There were no
17
Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and June 30, 2026, and the changes during the six months ended June 30, 2026, are presented net of taxes in the following table.
| (Thousands of dollars) | Foreign Currency Translation Gains (Losses) | Retirement and Postretirement Benefit Plan Adjustments | Total | ||||||||||||||||||||
| Balance at December 31, 2025 | $ | ( | $ | ( | $ | ( | |||||||||||||||||
| Components of other comprehensive income (loss): | |||||||||||||||||||||||
| Before reclassifications to income | ( | ( | |||||||||||||||||||||
| Reclassifications to income ¹ | |||||||||||||||||||||||
| Net other comprehensive income (loss) | ( | ( | |||||||||||||||||||||
| Balance at June 30, 2026 | $ | ( | $ | ( | $ | ( | |||||||||||||||||
1 Reclassifications before taxes of $3.3 million are included in the computation of net periodic benefit expense for the six months ended June 30, 2026. See Note H for additional information. Related income taxes of $0.5 million are included in "Income tax expense” on the Consolidated Statements of Operations for the six months ended June 30, 2026.
Note N – Environmental and Other Contingencies
The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; trade policies, tariffs and other trade restrictions; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws, regulations and government action intended for the promotion of safety and the protection and/or remediation of the environment including in connection with the purported causes or potential impacts of climate change; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Given the factors involved in various government actions, including political considerations, it is difficult to predict their likelihood, the form they may take, or the effect they may have on the Company.
ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment and protection of health and safety. The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including methane and other greenhouse gas (GHG) emissions; wildlife, habitat and water protection; water access, use and disposal; the placement, operation and decommissioning of production equipment; the health and safety of our employees, contractors and communities where our operations are located, including indigenous communities; and the causes and impacts of climate change. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning of facilities once production has ceased.
Violation of federal or state environmental, health and safety laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not adequately insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. In addition, Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that the Company reasonably believes will exceed a specified threshold. Pursuant to SEC amendments to this
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)
item, the Company will be using a threshold of $1.0 million for such proceedings and the Company is not aware of environmental legal proceedings likely to exceed this $1.0 million threshold.
In recent years, there has been an increase in regulatory oversight of the oil and gas industry at the state and federal level, with a focus on climate change and GHG emissions (including methane emissions). For example, in March 2024, the U.S. Environmental Protection Agency (EPA) published its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. However, the EPA has since published a final rule extending several compliance deadlines associated with the new methane rules. In November 2024, the EPA published its final rule implementing a charge on large emitters of waste methane from the oil and gas sector. This rule, however, was disapproved by a joint Congressional resolution in March 2025, and the One Big Beautiful Bill Act (OBBBA) passed in July 2025 extended the imposition of the waste emission charge until 2034. In addition, an international climate agreement (the Paris Agreement) was agreed to at the 2015 United Nations Framework Convention on Climate Change in Paris, France. In January 2025, the United States submitted formal notification to the United Nations that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal came into effect on January 27, 2026. In September 2025, the EPA announced a proposal to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On January 7, 2026, the Trump Administration issued an executive order directing United States executive agencies to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution. While presidential administrations may modify, revise or repeal rules related to climate change and GHG emissions, the general trend has been towards stricter regulation over time. Further, many states have adopted or are considering regulations related to GHG emissions.
The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)
on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note O – Common Stock Issued and Outstanding
Activity in the number of shares of common stock issued and outstanding for the six months ended June 30, 2026 and 2025 is shown below.
(Number of shares outstanding) | June 30, 2026 | June 30, 2025 | |||||||||||||||
| Beginning of period | |||||||||||||||||
Restricted stock awards 1 | |||||||||||||||||
Treasury shares purchased | ( | ||||||||||||||||
| End of period | |||||||||||||||||
1 Shares issued upon award of restricted stock are less withholding for statutory income taxes owed upon issuance of shares.
On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100.0 million of its common stock. This repurchase program has no time limit and may be suspended or discontinued completely at any time without prior notice as determined by the Company at its discretion and dependent upon a variety of factors.
During the six months ended June 30, 2026, the Company did no t repurchase any shares of its common stock. During the six months ended June 30, 2025, the Company repurchased 3.6 million shares of its common stock under the share repurchase program for $100.0 million ($100.9 million including excise taxes and fees). As of June 30, 2026, the Company had $550.1 million of its common stock remaining available to repurchase under the program.
Note P – Business Segments
Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia and U.S. refining and marketing operations as discontinued operations for all periods presented. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the Chief Operating Decision Maker (CODM).
“Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income attributed to the Canada segment.
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
| Exploration and Production | |||||||||||||||||||||||||||||||||||||||||||||||
(Millions of dollars) | United States 1 | Canada | Other | Total E&P | Corporate and Discontinued Operations | Consolidated Total | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2026 | |||||||||||||||||||||||||||||||||||||||||||||||
Revenue from production | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Gain on sale of assets and other operating income | |||||||||||||||||||||||||||||||||||||||||||||||
Total revenues and other income | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses and taxes other than income | |||||||||||||||||||||||||||||||||||||||||||||||
Repair and maintenance | |||||||||||||||||||||||||||||||||||||||||||||||
| Workovers | |||||||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||||||||||||||||||||||||||||||||
| Transportation, gathering and processing | |||||||||||||||||||||||||||||||||||||||||||||||
| Selling and general expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Exploration Expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Geological and geophysical | |||||||||||||||||||||||||||||||||||||||||||||||
Dry holes and previously suspended exploration costs | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Other exploratory costs, including undeveloped lease amortization and delay lease rentals | |||||||||||||||||||||||||||||||||||||||||||||||
| Total exploration expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | |||||||||||||||||||||||||||||||||||||||||||||||
Other operating expenses | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Interest Income | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||
Interest expense, net of capitalization | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
| Current income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense (benefit) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Total income tax expense (benefit) | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Other segment costs (income) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Segment income (loss) - including NCI 1 | $ | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Additions to property, plant, equipment | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Total assets at quarter-end | |||||||||||||||||||||||||||||||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
| Exploration and Production | |||||||||||||||||||||||||||||||||||||||||||||||
(Millions of dollars) | United States 1 | Canada | Other | Total E&P | Corporate and Discontinued Operations | Consolidated Total | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
Revenue from production | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Gain on sale of assets and other operating income | |||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues and other income | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses and taxes other than income | |||||||||||||||||||||||||||||||||||||||||||||||
Repair and maintenance | |||||||||||||||||||||||||||||||||||||||||||||||
| Workovers | |||||||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||||||||||||||||||||||||||||||||
| Transportation, gathering and processing | |||||||||||||||||||||||||||||||||||||||||||||||
| Selling and general expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Exploration Expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Geological and geophysical | |||||||||||||||||||||||||||||||||||||||||||||||
Dry holes and previously suspended exploration costs | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
Other exploratory costs, including undeveloped lease amortization and delay lease rentals | |||||||||||||||||||||||||||||||||||||||||||||||
| Total exploration expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | |||||||||||||||||||||||||||||||||||||||||||||||
Other operating expenses | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Interest income | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalization | |||||||||||||||||||||||||||||||||||||||||||||||
Income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
Current income tax expense (benefit) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense (benefit) | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
Total income tax expense (benefit) | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Other segment costs | |||||||||||||||||||||||||||||||||||||||||||||||
Segment income (loss) - including NCI 1 | $ | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Additions to property, plant, equipment | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Total assets at quarter-end | |||||||||||||||||||||||||||||||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
| Exploration and Production | |||||||||||||||||||||||||||||||||||||||||||||||
(Millions of dollars) | United States 1 | Canada | Other | Total E&P | Corporate and Discontinued Operations | Consolidated Total | |||||||||||||||||||||||||||||||||||||||||
| Six Months Ended June 30, 2026 | |||||||||||||||||||||||||||||||||||||||||||||||
Revenue from production | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Gain on sale of assets and other operating income | |||||||||||||||||||||||||||||||||||||||||||||||
Total revenues and other income | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses and taxes other than income | |||||||||||||||||||||||||||||||||||||||||||||||
Repair and maintenance | |||||||||||||||||||||||||||||||||||||||||||||||
| Workovers | |||||||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||||||||||||||||||||||||||||||||
| Transportation, gathering and processing | |||||||||||||||||||||||||||||||||||||||||||||||
| Selling and general expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Exploration Expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Geological and geophysical | |||||||||||||||||||||||||||||||||||||||||||||||
Dry holes and previously suspended exploration costs | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Other exploratory costs, including undeveloped lease amortization and delay lease rentals | |||||||||||||||||||||||||||||||||||||||||||||||
| Total exploration expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | |||||||||||||||||||||||||||||||||||||||||||||||
Other operating expenses | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Interest Income | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||
Interest expense, net of capitalization | |||||||||||||||||||||||||||||||||||||||||||||||
Income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
Current income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense (benefit) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Total income tax expense (benefit) | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Other segment costs (income) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Segment income (loss) - including NCI 1 | $ | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Additions to property, plant, equipment | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Total assets at quarter-end | |||||||||||||||||||||||||||||||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
| Exploration and Production | |||||||||||||||||||||||||||||||||||||||||||||||
(Millions of dollars) | United States 1 | Canada | Other | Total E&P | Corporate and Discontinued Operations | Consolidated Total | |||||||||||||||||||||||||||||||||||||||||
| Six Months Ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||||||||
Revenue from production | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Gain on sale of assets and other operating income | |||||||||||||||||||||||||||||||||||||||||||||||
Total revenues and other income | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Lease operating expenses and taxes other than income | |||||||||||||||||||||||||||||||||||||||||||||||
Repair and maintenance | |||||||||||||||||||||||||||||||||||||||||||||||
| Workovers | |||||||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||||||||||||||||||||||||||||||||
| Transportation, gathering and processing | |||||||||||||||||||||||||||||||||||||||||||||||
| Selling and general expenses | |||||||||||||||||||||||||||||||||||||||||||||||
Exploration Expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Geological and geophysical | |||||||||||||||||||||||||||||||||||||||||||||||
Dry holes and previously suspended exploration costs | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
Other exploratory costs, including undeveloped lease amortization and delay lease rentals | |||||||||||||||||||||||||||||||||||||||||||||||
| Total exploration expenses | |||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | |||||||||||||||||||||||||||||||||||||||||||||||
| Other operating expenses | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Interest Income | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||
Interest expense, net of capitalization | |||||||||||||||||||||||||||||||||||||||||||||||
Income tax expense | |||||||||||||||||||||||||||||||||||||||||||||||
| Current income tax expense (benefit) | ( | ||||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense (benefit) | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
Total income tax expense (benefit) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
Other segment costs | |||||||||||||||||||||||||||||||||||||||||||||||
Segment income (loss) - including NCI 1 | $ | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||||||||||||||||
| Additions to property, plant, equipment | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
Total assets at quarter-end | |||||||||||||||||||||||||||||||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
24
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the period ended June 30, 2026 included under “Item 1. Financial Statements” of this Form 10-Q and the audited consolidated financial statements and related notes and MD&A included in Item 8 and 7, respectively, of our Annual Report on Form 10-K for the year ended December 31, 2025. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” at the end of this section.
Overview
Murphy is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The Company boasts over a century of strong execution and innovative, full-cycle development capabilities, with a focus on value creation to enhance shareholder returns. The Company’s current operations include inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire.
The analysis and discussion in this section includes amounts attributable to the noncontrolling interest in MP GOM, unless otherwise noted.
Significant Company financial and operational highlights during the second quarter of 2026 were as follows:
•Production was 175,013 barrels of oil equivalent (BOE) per day (including NCI), a decrease from 196,315 BOE per day in the second quarter of 2025;
•Drilled an oil discovery at Bubale-1X (Block CI-709) exploration well in Côte d’Ivoire;
•Concluded the Hai Su Vang (Golden Sea Lion) appraisal program with the completion of Hai Su Vang-4X (Block 15-2/17) appraisal well, which was expensed as a dry hole;
•Completed drilling operations and initiated completion activities at the Chinook #8 (Walker Ridge 425) development well in the Gulf of America;
•Finalized pipeline installation and launched the FSO (Floating Storage and Offloading vessel) at the Lac Da Vang development project in Vietnam; and
•Brought online six Eagle Ford Shale wells and four Kaybob Duvernay wells.
Subsequent to the second quarter:
•Spud Bubale West-1X appraisal well in Block CI-103 offshore Côte d'Ivoire;
•Spud the Lac Da Trang (White Camel) North-1X exploration well in Block 15-1/05 in Vietnam; and
•Completed installation of topsides and mobilized FSO to final location for Lac Da Vang development project.
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2026 was $264.0 million compared to net income of $33.8 million for the same period in 2025. The increase in 2026 was primarily driven by higher revenues from production ($243.3 million), lower lease operating expenses ($71.8 million), higher other income ($43.6 million), and lower transportation, gathering and processing expenses ($8.8 million). These favorable items were partially offset by higher income tax expense ($76.0 million), higher exploration expense ($28.9 million), and higher other operating expenses ($12.9 million).
Higher revenues were primarily driven by higher realized crude oil prices in the United States, partially offset by lower oil sales volumes in the Gulf of America. Canada oil revenues also increased, driven by higher oil prices and increased production and sales at Terra Nova and Hibernia, as well as new wells at Kaybob; these items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Khaleesi, Marmalard and Samurai and
25
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
lower production handling agreement costs at King’s Quay from lower volumes; these items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale. Higher other income was primarily due to foreign exchange gains driven by favorable currency movements in Canada. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, as well as certain exploration expenses that did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher exploration expenses were largely due to exploration activities in the Gulf of America and costs related to second-quarter appraisal programs in Vietnam and Côte d’Ivoire. Higher other operating expenses were related to the increase in a joint venture settlement provision.
For the three months ended June 30, 2026 total hydrocarbon production was 175,013 barrels of oil equivalent per day, a decrease of 11% compared to the second quarter of 2025. The decrease was principally due to lower offshore production in the Gulf of America, primarily attributable to planned and unplanned downtime at multiple fields, partially offset by higher production in Canada Offshore. Higher Canada Offshore production was driven by increased production at Terra Nova and Hibernia, while higher Canada Onshore production was driven by new wells at Kaybob. Higher Eagle Ford Shale production was primarily the result of new wells online in the current year.
Net income from continuing operations, including noncontrolling interest, for the six months ended June 30, 2026 was $333.2 million, an increase of $209.3 million compared to the same period of 2025. Higher net income from continuing operations was primarily driven by higher revenues from production ($302.9 million), lower lease operating expenses ($133.4 million), higher other income ($51.0 million), and lower transportation, gathering and processing expenses ($10.6 million). These favorable items were partially offset by higher exploration expenses ($97.2 million), higher income tax expense ($93.2 million), higher DD&A ($63.0 million), and higher other operating expenses ($11.7 million).
Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the United States contributing the majority of the increase from higher prices in the Gulf of America and both higher prices and volumes in the Eagle Ford Shale from new wells at Karnes and Catarina. Canada oil revenues increased from higher prices along with higher production at Kaybob from new wells; these items were partially offset by lower Canada natural gas revenues, primarily due to reduced production and sales volumes at Tupper. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America, including the non-repeat of 2025 workover activity at Samurai, Marmalard and Khaleesi, lower production handling agreement costs at King’s Quay from lower volumes, and lower FPSO rental fees at Cascade & Chinook following the vessel purchase in early 2025. Higher other income was primarily due to favorable foreign exchange movements. Higher exploration expenses were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, both of which encountered non-commercial hydrocarbons, and the Hai Su Vang-4X (Golden Sea Lion) Block 15-2/17 appraisal well in Vietnam, which did not encounter hydrocarbons and was also expensed as a dry hole. Exploration activities in the Gulf of America also contributed to the higher exploration costs. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses, and certain exploration expenses did not reduce income tax expense as they were incurred in foreign jurisdictions where no income tax benefits are currently available. Higher DD&A was primarily driven by higher sales volumes in the Eagle Ford Shale, combined with higher rates in the Eagle Ford Shale and the Gulf of America, and higher sales volumes at Kaybob from new wells; these items were partially offset by lower sales volumes in the Gulf of America and at Tupper. Higher other operating expenses were related to the increase in a joint venture settlement provision.
For the six months ended June 30, 2026, total hydrocarbon production was 177,519 barrels of oil equivalent per day, a decrease of 1% compared to the same period in 2025. The decrease was principally due to lower production in the Gulf of America, primarily from planned and unplanned downtime at multiple fields, and lower natural gas production at Tupper. These decreases were largely offset by higher production in the Eagle Ford Shale from new wells, higher Canada Offshore production from Terra Nova and Hibernia, and higher Canada Onshore production from new wells at Kaybob.
Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.
At June 30, 2026, the West Texas Intermediate (WTI) crude oil futures price was $68.96 per barrel, whereas the crude oil futures price at the end of July 2026 was $80.31, reflecting a 16% increase in price. As of August 3, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $76.97 per barrel. Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.
Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below:
| Income (Loss) | |||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
| United States | $ | 274.2 | $ | 86.5 | $ | 430.9 | $ | 194.4 | |||||||||||||||
| Canada | 51.9 | 10.5 | 83.5 | 52.0 | |||||||||||||||||||
| Other | (30.2) | (7.3) | (112.8) | (18.5) | |||||||||||||||||||
Total exploration and production | 295.9 | 89.7 | 401.6 | 227.9 | |||||||||||||||||||
| Corporate and other | (32.0) | (55.9) | (68.4) | (104.1) | |||||||||||||||||||
| Income from continuing operations | 263.9 | 33.8 | 333.2 | 123.8 | |||||||||||||||||||
Discontinued operations, net of tax 1 | (0.4) | 1.3 | (1.0) | 0.7 | |||||||||||||||||||
| Net income including noncontrolling interest | 263.5 | 35.1 | 332.2 | 124.5 | |||||||||||||||||||
Less: Net income attributable to noncontrolling interest | 31.3 | 12.8 | 47.0 | 29.2 | |||||||||||||||||||
Net income attributable to Murphy | $ | 232.2 | $ | 22.3 | $ | 285.2 | $ | 95.3 | |||||||||||||||
1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Exploration and Production Continuing Operations
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted.
The following is a summarized statement of operations for E&P continuing operations:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Revenues and other income | |||||||||||||||||||||||
Revenue from production | $ | 926.3 | $ | 683.0 | $ | 1,658.7 | $ | 1,355.8 | |||||||||||||||
Other income | 1.3 | 1.7 | 2.5 | 4.1 | |||||||||||||||||||
Total revenues and other income | 927.6 | 684.7 | 1,661.2 | 1,359.9 | |||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 143.7 | 215.5 | 287.2 | 420.6 | |||||||||||||||||||
| Severance and ad valorem taxes | 15.0 | 10.8 | 28.7 | 19.5 | |||||||||||||||||||
| Transportation, gathering and processing | 45.3 | 54.0 | 92.3 | 102.9 | |||||||||||||||||||
| Depreciation, depletion and amortization | 259.7 | 257.6 | 511.7 | 449.4 | |||||||||||||||||||
| Accretion of asset retirement obligations | 14.8 | 14.4 | 29.2 | 28.5 | |||||||||||||||||||
Exploration expenses, including undeveloped lease amortization | 39.3 | 10.4 | 122.1 | 24.9 | |||||||||||||||||||
| Selling and general expenses | 17.3 | 13.1 | 32.3 | 23.0 | |||||||||||||||||||
| Other | 17.6 | 1.6 | 23.8 | 6.3 | |||||||||||||||||||
| Results of operations before taxes | 374.9 | 107.3 | 533.9 | 284.8 | |||||||||||||||||||
Income tax provisions | 79.0 | 17.6 | 132.3 | 56.9 | |||||||||||||||||||
Results of operations (excluding Corporate segment) 1 | $ | 295.9 | $ | 89.7 | $ | 401.6 | $ | 227.9 | |||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
28
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Pricing
The following table contains the weighted average sales prices for the three and six months ended June 30, 2026 and 2025:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Weighted average sales prices) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Crude oil and condensate – dollars per barrel | |||||||||||||||||||||||
United States - Onshore | $ | 99.55 | $ | 64.00 | $ | 86.18 | $ | 66.84 | |||||||||||||||
United States - Offshore 1 | 99.36 | 64.48 | 84.99 | 68.23 | |||||||||||||||||||
Canada - Onshore 2 | 84.08 | 59.94 | 77.28 | 61.73 | |||||||||||||||||||
Canada - Offshore 2 | 103.88 | 64.76 | 93.00 | 70.39 | |||||||||||||||||||
Other 2 | — | 70.86 | 71.04 | 70.86 | |||||||||||||||||||
| Natural gas liquids – dollars per barrel | |||||||||||||||||||||||
| United States - Onshore | 23.08 | 19.56 | 20.55 | 21.07 | |||||||||||||||||||
United States - Offshore 1 | 21.66 | 19.35 | 18.97 | 22.75 | |||||||||||||||||||
Canada - Onshore 2 | 34.46 | 33.84 | 31.25 | 35.00 | |||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | |||||||||||||||||||||||
| United States - Onshore | 2.41 | 2.75 | 3.07 | 3.03 | |||||||||||||||||||
United States - Offshore 1 | 3.38 | 3.47 | 4.55 | 3.89 | |||||||||||||||||||
Canada - Onshore 2 | 1.48 | 1.65 | 1.97 | 1.96 | |||||||||||||||||||
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
The following table contains benchmark prices relevant to the Company for the three and six months ended June 30, 2026 and 2025:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Average price for the period) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Oil and NGLs | |||||||||||||||||||||||
| WTI ($/BBL) | $ | 92.79 | $ | 63.74 | $ | 82.36 | $ | 67.58 | |||||||||||||||
| Natural gas | |||||||||||||||||||||||
| Henry Hub ($/MMBTU) | 2.94 | 3.16 | 3.90 | 3.72 | |||||||||||||||||||
| AECO (C$/MCF) | 1.63 | 1.69 | 1.82 | 1.93 | |||||||||||||||||||
29
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Production Volumes
The following table contains hydrocarbons produced during the three and six months ended June 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 32.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
United States - Onshore | 26,853 | 28,519 | 27,670 | 22,779 | ||||||||||||||||||||||
United States - Offshore 1 | 50,920 | 58,840 | 51,377 | 57,222 | ||||||||||||||||||||||
Canada - Onshore | 4,854 | 2,307 | 3,899 | 2,445 | ||||||||||||||||||||||
Canada - Offshore | 7,880 | 5,638 | 8,440 | 7,237 | ||||||||||||||||||||||
| Other | 239 | 296 | 232 | 275 | ||||||||||||||||||||||
Total net crude oil and condensate | 90,746 | 95,600 | 91,618 | 89,958 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
United States - Onshore | 6,769 | 5,557 | 6,315 | 4,818 | ||||||||||||||||||||||
United States - Offshore 1 | 3,976 | 4,720 | 4,136 | 4,265 | ||||||||||||||||||||||
Canada - Onshore | 570 | 494 | 549 | 516 | ||||||||||||||||||||||
Total net natural gas liquids | 11,315 | 10,771 | 11,000 | 9,599 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
United States - Onshore | 32,861 | 32,389 | 32,971 | 29,306 | ||||||||||||||||||||||
United States - Offshore 1 | 49,178 | 52,964 | 50,160 | 52,062 | ||||||||||||||||||||||
Canada - Onshore | 355,672 | 454,310 | 366,277 | 400,898 | ||||||||||||||||||||||
Total net natural gas | 437,711 | 539,663 | 449,408 | 482,266 | ||||||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 175,013 | 196,315 | 177,519 | 179,935 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,481) | (6,070) | (5,382) | (5,925) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (195) | (244) | (210) | (207) | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (2,052) | (1,942) | (1,955) | (1,590) | ||||||||||||||||||||||
Total noncontrolling interest 2,3 | (6,018) | (6,638) | (5,918) | (6,397) | ||||||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 168,995 | 189,677 | 171,601 | 173,538 | ||||||||||||||||||||||
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
30
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Sales Volumes
The following table contains hydrocarbons sold during the three and six months ended June 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 32.
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
United States - Onshore | 26,853 | 28,520 | 27,670 | 22,779 | ||||||||||||||||||||||
United States - Offshore 1 | 50,359 | 58,469 | 51,277 | 56,313 | ||||||||||||||||||||||
Canada - Onshore | 4,854 | 2,307 | 3,899 | 2,444 | ||||||||||||||||||||||
Canada - Offshore | 10,201 | 7,762 | 8,897 | 9,436 | ||||||||||||||||||||||
| Other | — | 457 | 226 | 230 | ||||||||||||||||||||||
Total net crude oil and condensate | 92,267 | 97,515 | 91,969 | 91,202 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
United States - Onshore | 6,769 | 5,557 | 6,315 | 4,819 | ||||||||||||||||||||||
United States - Offshore 1 | 3,976 | 4,720 | 4,136 | 4,264 | ||||||||||||||||||||||
Canada - Onshore | 570 | 494 | 549 | 516 | ||||||||||||||||||||||
Total net natural gas liquids | 11,315 | 10,771 | 11,000 | 9,599 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
United States - Onshore | 32,861 | 32,388 | 32,971 | 29,306 | ||||||||||||||||||||||
United States - Offshore 1 | 49,178 | 52,964 | 50,160 | 52,062 | ||||||||||||||||||||||
Canada - Onshore | 355,672 | 454,310 | 366,277 | 400,898 | ||||||||||||||||||||||
Total net natural gas | 437,711 | 539,662 | 449,408 | 482,266 | ||||||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 176,534 | 198,230 | 177,870 | 181,179 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,396) | (6,014) | (5,365) | (5,792) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (195) | (243) | (210) | (207) | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (2,052) | (1,942) | (1,955) | (1,590) | ||||||||||||||||||||||
Total noncontrolling interest 2,3 | (5,933) | (6,581) | (5,901) | (6,264) | ||||||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 170,601 | 191,649 | 171,969 | 174,915 | ||||||||||||||||||||||
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
31
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted.
Revenues from Production
The Company’s production revenues by country and product were as follows:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Revenues from production | |||||||||||||||||||||||
United States - Oil | $ | 698.6 | $ | 509.2 | $ | 1,220.4 | $ | 971.0 | |||||||||||||||
United States - Natural gas liquids | 22.1 | 18.1 | 37.7 | 35.9 | |||||||||||||||||||
United States - Natural gas | 22.3 | 24.8 | 59.6 | 52.7 | |||||||||||||||||||
Canada - Oil | 133.5 | 58.3 | 204.3 | 147.5 | |||||||||||||||||||
Canada - Natural gas liquids | 1.8 | 1.5 | 3.1 | 3.3 | |||||||||||||||||||
Canada - Natural gas | 48.0 | 68.1 | 130.7 | 142.4 | |||||||||||||||||||
Other - Oil | — | 2.9 | 2.9 | 2.9 | |||||||||||||||||||
Total revenue from production | $ | 926.3 | $ | 683.0 | $ | 1,658.7 | $ | 1,355.8 | |||||||||||||||
Revenue from production for the three months ended June 30, 2026 increased $243.3 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized crude oil prices in the U.S., partially offset by lower oil sales volumes in the Gulf of America due to decreased production at the Mormont, Kodiak, and Samurai fields related to planned and unplanned downtime. Canada oil revenues increased, driven by higher oil prices and increased sales at Terra Nova and Hibernia, as well as new wells at Kaybob. These items were partially offset by lower Canada natural gas revenues, primarily due to lower realized natural gas prices and reduced sales volumes at Tupper.
Revenues from production for the six months ended June 30, 2026 increased $302.9 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized crude oil prices across all regions, with the U.S. contributing the majority of the increase from higher prices in the Gulf of America and both higher prices and volumes in the Eagle Ford Shale from new wells at Karnes and Catarina. Canada oil revenues also increased, primarily driven by higher prices, as well as higher production at Kaybob from new wells. These items were partially offset by lower Canada natural gas revenues, primarily due to lower production at Tupper due to the natural decline of new wells. U.S. natural gas revenues increased from higher realized prices, while U.S. NGL revenues increased primarily from higher volumes in the Eagle Ford Shale.
32
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Lease Operating and Transportation, Gathering and Processing Expenses
The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of dollars) | (Dollars per equivalent barrel) | (Millions of dollars) | (Dollars per equivalent barrel) | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||||||||||
| Lease operating expenses | ||||||||||||||||||||||||||||||||||||||||||||||||||
United States - Onshore | $ | 34.2 | $ | 29.5 | $ | 9.60 | $ | 8.20 | $ | 66.6 | $ | 59.2 | $ | 9.31 | $ | 10.08 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 59.3 | 137.0 | 10.43 | 20.91 | 124.7 | 264.9 | 10.80 | 21.13 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 32.5 | 35.6 | 5.52 | 4.98 | 65.4 | 65.8 | 5.53 | 5.21 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 17.5 | 12.6 | 18.84 | 17.86 | 29.4 | 29.5 | 18.24 | 17.29 | ||||||||||||||||||||||||||||||||||||||||||
| Other | 0.2 | 0.8 | — | 19.95 | 1.1 | 1.2 | 25.74 | 29.02 | ||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | $ | 143.7 | $ | 215.5 | $ | 8.95 | $ | 11.95 | $ | 287.2 | $ | 420.6 | $ | 8.92 | $ | 12.83 | ||||||||||||||||||||||||||||||||||
Transportation, gathering and processing | ||||||||||||||||||||||||||||||||||||||||||||||||||
United States - Onshore | $ | 3.7 | $ | 2.1 | $ | 1.03 | $ | 0.62 | $ | 6.4 | $ | 4.5 | $ | 0.90 | $ | 0.77 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 20.8 | 28.1 | 3.66 | 4.28 | 43.3 | 54.5 | 3.75 | 4.35 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 18.9 | 22.0 | 3.21 | 3.08 | 39.4 | 40.3 | 3.32 | 3.19 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 1.9 | 1.8 | 2.01 | 2.53 | 3.2 | 3.6 | 2.01 | 2.10 | ||||||||||||||||||||||||||||||||||||||||||
Total transportation, gathering and processing | $ | 45.3 | $ | 54.0 | $ | 2.82 | $ | 3.00 | $ | 92.3 | $ | 102.9 | $ | 2.87 | $ | 3.14 | ||||||||||||||||||||||||||||||||||
For the three months ended June 30, 2026 lease operating expenses decreased by $71.8 million and transportation, gathering and processing expenses decreased by $8.7 million compared to the same period in 2025. Lower expenses were primarily driven by decreased costs in the Gulf of America, where workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Khaleesi, Marmalard, and Samurai, a one-time access fee received at Lucius, and lower production handling agreement costs at King's Quay from lower volumes. These items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale.
Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes in the Gulf of America.
For the six months ended June 30, 2026 lease operating expenses decreased by $133.4 million, and transportation, gathering and processing expenses decreased by $10.6 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by decreased costs in the Gulf of America. Workover expenses decreased significantly due to the non-repeat of 2025 workover activity at Samurai, Marmalard, and Khaleesi. In addition, lower production handling agreement costs at King's Quay from lower volumes and lower FPSO rental fees at Cascade & Chinook, following the vessel purchase in early 2025, contributed to the decrease in operating expenses. Canada Offshore expenses decreased due to lower production-related costs at Terra Nova. These items were partially offset by higher U.S. Onshore costs from increased operated well counts in the Eagle Ford Shale.
Lower transportation, gathering and processing expenses were primarily driven by renegotiated vessel contract rates at Cascade & Chinook and lower volumes across multiple Gulf of America fields including Mormont, St. Malo, and Khaleesi. Canada Onshore transportation costs decreased due to lower volumes and ongoing mitigation efforts at Tupper.
33
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Depreciation, Depletion and Amortization Expenses
The Company’s DD&A by geographic area were as follows:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of dollars) | (Dollars per equivalent barrel) | (Millions of dollars) | (Dollars per equivalent barrel) | |||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||||||||||||||||||
DD&A | ||||||||||||||||||||||||||||||||||||||||||||||||||
United States - Onshore | $ | 113.9 | $ | 107.4 | $ | 32.01 | $ | 29.88 | $ | 227.2 | $ | 174.4 | $ | 31.79 | $ | 29.68 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 106.6 | 110.9 | 18.74 | 16.93 | 210.2 | 203.2 | 18.21 | 16.21 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 29.2 | 30.0 | 4.96 | 4.20 | 55.6 | 54.1 | 4.69 | 4.29 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 9.9 | 8.1 | 10.65 | 11.47 | 17.5 | 16.4 | 10.89 | 9.59 | ||||||||||||||||||||||||||||||||||||||||||
| Other | 0.1 | 1.2 | — | 28.38 | 1.2 | 1.3 | 27.84 | 31.02 | ||||||||||||||||||||||||||||||||||||||||||
Total DD&A | $ | 259.7 | $ | 257.6 | $ | 16.16 | $ | 14.28 | $ | 511.7 | $ | 449.4 | $ | 15.89 | $ | 13.70 | ||||||||||||||||||||||||||||||||||
DD&A for the three months ended June 30, 2026 increased by $2.1 million compared to the same period in 2025. Higher DD&A was primarily driven by higher rates in the Eagle Ford Shale and the Gulf of America, as well as higher sales volumes at Canada Offshore from increased cargo deliveries at Terra Nova and Hibernia and higher volumes at Kaybob from new wells. These items were partially offset by lower volumes in the Gulf of America related to planned and unplanned downtime at multiple fields and lower sales volumes at Tupper.
DD&A for the six months ended June 30, 2026 increased by $62.3 million compared to the same period in 2025. Higher DD&A was primarily driven by significantly higher sales volumes in the Eagle Ford Shale from new Alice May wells at Karnes and new wells at Catarina, combined with higher rates in the Eagle Ford Shale and the Gulf of America. Additionally, higher sales volumes at Kaybob from new wells contributed to the increase. These items were partially offset by lower sales volumes in the Gulf of America and at Tupper.
Exploration Expenses
The Company’s exploration expenses were as follows:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | $ | 13.5 | $ | (0.9) | $ | 80.6 | $ | (0.7) | |||||||||||||||
| Geological and geophysical | 11.2 | 0.8 | 12.8 | 4.4 | |||||||||||||||||||
| Other exploration | 12.2 | 8.2 | 24.0 | 17.3 | |||||||||||||||||||
| Undeveloped lease amortization | 2.4 | 2.3 | 4.7 | 3.9 | |||||||||||||||||||
Total exploration expenses, including undeveloped lease amortization | $ | 39.3 | $ | 10.4 | $ | 122.1 | $ | 24.9 | |||||||||||||||
Exploration expenses for the three months ended June 30, 2026 increased by $28.9 million compared to the same period in 2025. Higher exploration expenses in the current quarter were largely due to exploration activities in Côte d’Ivoire, Vietnam, and the Gulf of America. Dry holes and previously suspended exploration costs primarily related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam.
Exploration expenses for the six months ended June 30, 2026 increased by $97.2 million compared to the same period in 2025. Higher exploration expenses in the current period were largely driven by higher dry hole costs related to the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells in Côte d’Ivoire, and the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) in Vietnam, all of which encountered non-commercial hydrocarbons. Exploration activities in the Gulf of America also contributed to the higher exploration costs.
34
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Other
Other expenses increased by $16.0 million and $17.5 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in a joint venture dispute settlement provision.
Income Taxes
Income taxes for the three and six months ended June 30, 2026 increased by $61.4 million and $75.4 million, respectively, compared to the same periods in 2025. Higher income tax expense was primarily due to higher revenues and lower lease operating expenses during the period. In addition, higher exploration expenses, mainly due to dry hole expenses recognized related to Côte d’Ivoire, did not reduce income tax expense as they were in foreign jurisdictions where no income tax benefits are currently available.
Corporate
Corporate activities include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps to hedge commodity price) and corporate overhead not allocated to E&P. Realized and unrealized gains and losses on derivative instruments result from changes in market natural gas prices relating to future periods whereby the swap contracts provided the Company with a fixed price.
The Corporate segment reported a loss of $32.0 million for the three months ended June 30, 2026 a favorable variance of $23.9 million compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($44.0 million), driven by favorable currency movements in Canada. These gains were partially offset by no repeat of gains on derivative instruments in 2026 ($10.3 million) and lower income tax benefit ($14.5 million) due to higher current period net income.
The Corporate segment reported a loss of $68.4 million for the six months ended June 30, 2026 a favorable variance of $35.7 million, compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($52.9 million). These favorable items were partially offset by higher income tax expense ($17.8 million), and higher interest expense ($5.2 million) related to costs associated with the redemption of the 2027 Notes and 2028 Notes.
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF. The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months and the foreseeable future.
35
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Cash Flows
The following table presents the Company’s cash flows for the periods presented:
| Six Months Ended June 30, | |||||||||||
(Millions of dollars) | 2026 | 2025 | |||||||||
Net cash provided (required) by: | |||||||||||
| Net cash provided by continuing operations activities | $ | 977.1 | $ | 658.7 | |||||||
Net cash required by investing activities | (889.7) | (679.4) | |||||||||
| Net cash provided (required) by financing activities | 19.0 | (22.4) | |||||||||
| Effect of exchange rate changes on cash and cash equivalents | 0.3 | (0.9) | |||||||||
| Net increase (decrease) in cash and cash equivalents | $ | 106.7 | $ | (43.9) | |||||||
Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities for the six months ended June 30, 2026 increased by $318.4 million compared to the same period in 2025. The increase in cash flows from operations activities was primarily due to higher realized commodity prices, which resulted in a $302.9 million increase in revenue from production, and lower lease operating expenses ($133.4 million). These favorable impacts were partially offset by a $65.1 million decrease in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations, as well as a $48.4 million unfavorable change in net non-cash working capital, which was also affected by higher commodity prices.
Cash Required by Investing Activities
Net cash required by investing activities for the six months ended June 30, 2026 was $210.2 million higher compared to the same period in 2025. The increase was primarily due to higher property additions and dry hole costs ($188.1 million) and higher acquisition capital ($22.1 million).
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
| Six Months Ended June 30, | |||||||||||
| (Millions of dollars) | 2026 | 2025 | |||||||||
| Property additions and dry hole costs | $ | 866.2 | $ | 678.0 | |||||||
| Acquisition of oil and natural gas properties | 23.5 | 1.4 | |||||||||
| Geophysical and other exploration expenses | 34.3 | 19.3 | |||||||||
| Capital expenditure accrual changes and other | 54.2 | (20.3) | |||||||||
| Total capital expenditures | $ | 978.2 | $ | 678.4 | |||||||
Total accrual basis capital expenditures are shown below.
| Six Months Ended June 30, | |||||||||||
| (Millions of dollars) | 2026 | 2025 | |||||||||
| Capital Expenditures | |||||||||||
| Exploration and production | $ | 961.9 | $ | 671.4 | |||||||
| Corporate | 16.3 | 7.0 | |||||||||
| Total capital expenditures | $ | 978.2 | $ | 678.4 | |||||||
Higher capital expenditures in the six months ended June 30, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory and development drilling in the Gulf of America, and higher development spending in Vietnam, which included progressing the LDV-A platform construction and pipe-laying campaign. These increases were partially offset by lower field
36
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
development costs in the Gulf of America due to the prior year purchase of the Pioneer FPSO in the Gulf of America.
Capital expenditures in 2026 primarily relate to development drilling and field development activities in the Gulf of America ($278.7 million), the Eagle Ford Shale ($187.4 million), the Tupper Montney and the Kaybob Duvernay ($112.8 million), and in Vietnam ($55.0 million).
Exploration costs in 2026 were $314.3 million, primarily comprised of activities in Côte d'Ivoire related to exploration drilling for Bubale-1X (Block CI-709), Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells, and the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05). Exploration costs were also driven by activities in the Gulf of America including lease acquisitions and exploration drilling at the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) exploration wells.
Cash Provided (Required) by Financing Activities
Net cash provided by financing activities for the six months ended June 30, 2026 increased by $41.4 million compared to the same period in 2025.
In 2026, the cash provided by financing activities was principally from a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 million. The bond issuance was partially offset by the aggregate redemption of the 2027 Notes ($78.9 million) and 2028 Notes ($148.6 million), net repayments on the Amended RCF ($100.0 million), year-to-date cash dividends to shareholders of $0.70 per share ($100.3 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.1 million), and distributions to the noncontrolling interest in MP GOM ($21.2 million).
In 2025, net cash required by financing activities was principally for the repurchase of common shares ($102.6 million), year-to-date cash dividends to shareholders of $0.65 per share ($93.4 million), and distributions to the noncontrolling interest in MP GOM ($18.2 million), and was partially offset by net borrowings on the senior unsecured RCF ($200.0 million).
Liquidity
At June 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $483.9 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured Amended RCF with a major banking consortium.
The Company’s $2.0 billion senior unsecured Amended RCF expires in January 2031. As of June 30, 2026 the Company had no outstanding borrowings under the Amended RCF and $0.4 million of outstanding letters of credit, which reduce the borrowing capacity of the Amended RCF. At June 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 5.90%. At June 30, 2026, the Company was in compliance with all covenants related to the Amended RCF.
Cash and invested cash are maintained in several operating locations outside the U.S. As of June 30, 2026 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $160.2 million, the majority of which was held in Canada ($89.4 million), Côte d'Ivoire ($34.6 million), Vietnam ($12.7 million), Mexico ($7.9 million), Brunei ($6.1 million), and the U.K. ($4.6 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
37
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Working Capital
| (Millions of dollars) | June 30, 2026 | December 31, 2025 | |||||||||
Working capital | |||||||||||
| Total current assets | $ | 1,026.8 | $ | 816.7 | |||||||
| Total current liabilities | 1,202.3 | 1,062.7 | |||||||||
Net working capital liability | $ | (175.5) | $ | (246.0) | |||||||
As of June 30, 2026 net working capital increased by $70.5 million compared to December 31, 2025. The increase was primarily attributable to a higher cash balance at the end of the period ($106.7 million) and higher accounts receivable ($96.4 million), partially offset by higher accounts payable ($99.1 million), higher current asset retirement obligations ($17.3 million), and higher income taxes payable ($14.1 million).
Higher accounts receivable and accounts payable were primarily due to higher oil and NGL prices and drilling activities in the Gulf of America, respectively. Higher current asset retirement obligations were due to reclassification of certain obligations from long-term to current for anticipated well abandonment activities expected within the next 12 months. Higher income taxes were due to higher pretax net income.
Capital Employed
A summary of capital employed at June 30, 2026 and December 31, 2025 follows.
| June 30, 2026 | December 31, 2025 | ||||||||||||||||||||||
| (Millions of dollars) | Amount | % | Amount | % | |||||||||||||||||||
| Capital employed | |||||||||||||||||||||||
| Long-term debt | $ | 1,547.9 | 22.7 | % | $ | 1,382.6 | 21.3 | % | |||||||||||||||
| Murphy shareholders' equity | 5,259.0 | 77.3 | % | 5,118.4 | 78.7 | % | |||||||||||||||||
| Total capital employed | $ | 6,806.9 | 100.0 | % | $ | 6,501.0 | 100.0 | % | |||||||||||||||
At June 30, 2026, long-term debt of $1,547.9 million increased by $165.3 million compared to December 31, 2025 primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.7 years and a weighted average coupon of 6.3%.
Murphy shareholders’ equity increased by $140.6 million in 2026, primarily due to net income ($285.2 million) and ($15.5 million) stock award amortization, partially offset by dividends ($100.3 million) and foreign currency translation ($54.6 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.
Critical Accounting Estimates
As of June 30, 2026 there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2025.
Accounting Changes and Recent Accounting Pronouncements
See Note B to the Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.
38
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics
The Company uses other operational performance and income metrics to review operational performance.
Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 232.2 | $ | 22.3 | $ | 285.2 | $ | 95.3 | |||||||||||||||
| Discontinued operations (income) loss | 0.4 | (1.3) | 1.0 | (0.7) | |||||||||||||||||||
| Net income from continuing operations attributable to Murphy | 232.6 | 21.0 | 286.2 | 94.6 | |||||||||||||||||||
Adjustments: | |||||||||||||||||||||||
| Foreign exchange (gain) loss | (9.2) | 34.3 | (18.6) | 34.3 | |||||||||||||||||||
| Unrealized gain on derivative instruments | — | (10.3) | — | (1.4) | |||||||||||||||||||
| Total adjustments, before taxes | (9.2) | 24.0 | (18.6) | 32.9 | |||||||||||||||||||
Income tax (benefit) expense related to adjustments | 2.4 | (6.5) | 4.8 | (8.3) | |||||||||||||||||||
| Total adjustments, after taxes | (6.8) | 17.5 | (13.8) | 24.6 | |||||||||||||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 225.8 | $ | 38.5 | $ | 272.4 | $ | 119.2 | |||||||||||||||
Net income from continuing operations per average diluted share (GAAP) | $ | $ | $ | $ | |||||||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 1.55 | $ | 0.27 | $ | 1.87 | $ | 0.83 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
39
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
The following table reconciles net income (loss) attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Net income attributable to Murphy (GAAP) 1 | $ | 232.2 | $ | 22.3 | $ | 285.2 | $ | 95.3 | |||||||||||||||
| Income tax expense | 77.0 | 1.1 | 127.0 | 33.8 | |||||||||||||||||||
| Interest expense, net | 24.9 | 25.1 | 53.9 | 48.6 | |||||||||||||||||||
Depreciation, depletion and amortization expense 1 | 254.0 | 250.8 | 500.8 | 438.2 | |||||||||||||||||||
EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 588.1 | $ | 299.3 | $ | 966.9 | $ | 615.9 | |||||||||||||||
Exploration expenses 1 | 39.3 | 10.3 | 122.1 | 24.8 | |||||||||||||||||||
EBITDAX attributable to Murphy (Non-GAAP) 1 | $ | 627.4 | $ | 309.6 | $ | 1,089.0 | $ | 640.7 | |||||||||||||||
EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 588.1 | $ | 299.3 | $ | 966.9 | $ | 615.9 | |||||||||||||||
| Foreign exchange (gain) loss | (9.2) | 34.3 | (18.6) | 34.3 | |||||||||||||||||||
Accretion of asset retirement obligations 1 | 13.4 | 12.9 | 26.3 | 25.4 | |||||||||||||||||||
| Unrealized gain on derivative instruments | — | (10.3) | — | (1.4) | |||||||||||||||||||
| Discontinued operations (income) loss | 0.4 | (1.3) | 1.0 | (0.7) | |||||||||||||||||||
Adjusted EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 592.7 | $ | 334.9 | $ | 975.6 | $ | 673.5 | |||||||||||||||
Exploration expenses 1 | 39.3 | 10.3 | 122.1 | 24.8 | |||||||||||||||||||
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1 | $ | 632.0 | $ | 345.2 | $ | 1,097.7 | $ | 698.3 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
40
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.
The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net cash provided by continuing operations activities (GAAP) | $ | 655.9 | $ | 358.1 | $ | 977.1 | $ | 658.7 | |||||||||||||||
| Exclude: increase (decrease) in non-cash working capital | (67.5) | (30.7) | 40.5 | (7.9) | |||||||||||||||||||
Operating cash flow excluding working capital adjustments (Non-GAAP) | 588.4 | 327.4 | 1,017.6 | 650.8 | |||||||||||||||||||
Less: property additions and dry hole costs 1 | (478.4) | (309.6) | (866.2) | (678.0) | |||||||||||||||||||
| Free cash flow (Non-GAAP) | $ | 110.0 | $ | 17.8 | $ | 151.4 | $ | (27.2) | |||||||||||||||
| Adjustments: | |||||||||||||||||||||||
| Cash dividends paid | (50.1) | (46.4) | (100.3) | (93.4) | |||||||||||||||||||
| Distributions to noncontrolling interest | (21.2) | (11.2) | (21.2) | (18.2) | |||||||||||||||||||
| Debt costs | (0.1) | — | (22.5) | — | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | — | — | (7.8) | (7.7) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | (0.8) | — | (23.5) | (1.4) | |||||||||||||||||||
| Adjusted free cash flow (Non-GAAP) | $ | 37.8 | $ | (39.8) | $ | (23.9) | $ | (147.9) | |||||||||||||||
1 Property additions for the six months ended June 30, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, including amounts attributable to a noncontrolling interest in MP GOM.
41
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook
The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the “Results of Operations” section discussing revenues, on page 32, higher average crude oil and lower natural gas pricing during the second quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.
As of close on August 3, 2026 forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.
| 2026 | 2027 | |||||||||||||
| WTI ($/BBL) | 76.97 | 69.99 | ||||||||||||
| NYMEX ($/MMBTU) | 3.09 | 3.38 | ||||||||||||
| AECO (US$ Equivalent/MCF) | 1.35 | 1.69 | ||||||||||||
The regional conflict involving Iran continues to contribute to heightened geopolitical risk and significant volatility in global energy and shipping markets, primarily due to disruptions affecting transit through the Strait of Hormuz, which is a critical passage for oil, LNG, and other refined products. Although these developments have led to higher commodity prices, these developments have also led to increased transportation and insurance costs, and broader uncertainty across global supply chains, which may indirectly affect the Company through fluctuations in oil and gas prices, changes in demand, and higher operating or input costs. During the period, the Company has not experienced direct physical disruption to its operations, and the Company’s financial and operating results have been favorably impacted by price volatility. Looking forward, a prolonged or escalating conflict could further disrupt global energy flows, exacerbate price volatility, constrain access to markets or services, and adversely affect macroeconomic conditions, which could materially impact the Company’s future operating results, cash flows, and financial position.
Current uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of goods and services used in E&P operations or contribute to inflation in the countries in which we operate. In July 2026, the Trump Administration imposed a 10% or 12.5% tariff on 60 trading partners pursuant to Section 301 of the Trade Act of 1974. Although we are continuing to monitor the economic effects of tariff announcements and developments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.
We cannot predict what impact economic factors (including, but not limited to, inflation, trade policies, tariffs, other trade restrictions, and possible economic recession) may have on future commodity pricing and future costs for goods and services in the E&P operations. Similarly, we cannot predict the impact that political instability or armed conflict in oil and natural gas producing regions, such as in Russia and Ukraine, the Middle East, and Venezuela, may have on pricing, global supply and demand for oil and gas. It is also uncertain how production quota decisions by OPEC and OPEC+, along with changes in membership, may influence pricing and the global supply–demand balance. Lower prices or higher costs, should they occur, will result in lower profits and operating cash flows and could result in material future impairment charges.
For the third quarter of 2026, production is expected to average between 171.0 and 179.0 thousand barrels of oil equivalents per day, excluding noncontrolling interest.
The Company now expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million, compared with its prior guidance of $1,200 million to $1,300 million provided in the first quarter. This increase is driven primarily by additional capital related to the Bubale-1X (Block CI-709) discovery and the Bubale West-1X (Block CI-103) appraisal well, incremental Eagle Ford Shale activity, and higher-than-anticipated costs associated with Chinook #8 (Walker Ridge 425) drilling. Noncontrolling interest capital expenditures are expected to be $65 million.
In the Gulf of America, Murphy will continue developing the Cello #1 (Mississippi Canyon 385) and Banjo #1 (Mississippi Canyon 385) wells, which were determined to be successful in the first quarter of 2026. The Company currently expects these wells to begin production in the fourth quarter of 2027. In addition, the Company has initiated completion activities at the Chinook #8 (Walker Ridge 425) well, and expects the well to come online in the fourth quarter of 2026.
42
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook (Continued)
In Côte d’Ivoire, the Company drilled a successful exploration well at Bubale-1X (Block CI-709), and in July 2026 spud its first appraisal well, the Bubale West-1X (Block CI-103). The appraisal program is expected to include up to five wells over the next 18 to 24 months.
The Hai Su Vang (Golden Sea Lion) appraisal program in Vietnam has been completed following the completion of the Hai Su Vang-2X (Block 15-2/17) and Hai Su Vang-3X (Block 15-1/05) appraisal wells, which encountered hydrocarbons, and the Hai Su Vang-4X (Block 15-2/17) appraisal well, which did not and was expensed as a dry hole. The Company is evaluating development alternatives and progressing post-appraisal studies, with a final investment decision currently anticipated in the fourth quarter of 2027. In addition, in July the Company spud the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well. Finally, Murphy will continue field development activities in Vietnam at Lac Da Vang (Golden Camel), Block 15-1/05, with first oil anticipated in the fourth quarter of 2026.
In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally. During the second quarter, Murphy progressed key agreements for offshore exploration blocks in Cameroon and submitted an application for offshore blocks in Mauritania, initiating discussions with the government. The Company anticipates finalizing the contracts in both countries in the second half of 2026.
Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, as well as changing commodity price environments, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2026 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company plans to utilize any surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation plan designed to allow for additional shareholder returns and debt reduction. Details of the plan can be found in the “Capital Allocation” section of the Company’s Form 8-K filed on May 7, 2025. Based on current market conditions and our planned exploration and appraisal program, the Company is currently more likely to use available adjusted free cash flow for share repurchases than bond repayment.
On August 8, 2024, the Company’s Board of Directors authorized a share repurchase program whereby the Company can repurchase up to $1,100 million of the Company’s common stock, of which $550 million remains available to repurchase as of June 30, 2026.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the senior unsecured Amended RCF (see Note E).
As of August 3, 2026 the Company has entered into forward fixed price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
| Volumes (MMCF/d) | Price/MCF | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type 1 | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 88 | C$2.81 | 7/1/2026 | 9/30/2026 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 59 | C$3.00 | 10/1/2026 | 12/31/2026 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 9.5 | C$3.14 | 1/1/2027 | 12/31/2027 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Forward-Looking Statements
This Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and intent to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other environmental, social and governance matters, make capital expenditures, pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply and demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns (including the current conflict in Iran); increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or markets of health pandemics and related government responses; natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; cyber attacks and other cybersecurity risks; any failure to obtain necessary regulatory approvals; the impact of current and future laws, rulings and governmental regulations; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Item 1A. Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission (SEC) and on page 46 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Each forward-looking statement contained in this report speaks only as of the date of this report. Except as required by applicable law, Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
44
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, foreign currency exchange rates, and interest rates. As described in Note L, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
Commodity Price Risk
There were no commodity-based derivative contracts in place as of June 30, 2026.
Foreign Exchange Risk
There were no derivative foreign exchange contracts in place at June 30, 2026.
Interest Rate Risk
The Company’s senior unsecured Amended RCF provides for variable interest rate borrowings. As of June 30, 2026 we had no outstanding borrowings under the Amended RCF, and therefore, no related exposure to interest rate risk.
ITEM 4. CONTROLS AND PROCEDURES
Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
During the quarter ended June 30, 2026 there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
45
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.
46
ITEM 5. OTHER INFORMATION
During the three months ended June 30, 2026 no director or officer of the Company adopted terminated
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 | ||||||||||
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) | |||||||||||
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) | |||||||||||
Murphy Oil Corporation 2026 Stock Plan for Non-Employee Directors (incorporated by reference to Exhibit A to definitive proxy statement of Registrant filed on March 27, 2026) | |||||||||||
| 101. INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | ||||||||||
| 101. SCH | Inline XBRL Taxonomy Extension Schema Document | ||||||||||
| 101. CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||||||||
| 101. DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||||||||
| 101. LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document | ||||||||||
| 101. PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | ||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||||||||
47
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) | ||||||||
August 5, 2026
(Date)
48
EXHIBIT 10.37
MURPHY OIL CORPORATION
2026 STOCK PLAN FOR NON-EMPLOYEE DIRECTORS
RESTRICTED STOCK UNIT GRANT AGREEMENT
Restricted Stock Unit Award Number: ___________________ | Name of Grantee: ______________________________________ | Number of Restricted Stock Units Subject to this Grant: _______________________ | ||||||
This Restricted Stock Unit Award (this “Award”) is granted on and dated [•] (the “Grant Date”), by Murphy Oil Corporation, a Delaware corporation (the “Company”), pursuant to and for the purposes of the Company’s 2026 Stock Plan for Non-Employee Directors (the “Plan”), subject to the provisions set forth herein and in the Plan. Any terms used herein and not otherwise defined shall have the meaning set forth in the Plan.
1. The Company hereby grants to the individual named above (the “Grantee”) an Award of Restricted Stock Units each equal in value to one share of Common Stock (collectively, the “Units”). This Award constitutes a right to receive shares in the future and does not represent any current interest in the shares subject to the Award.
2. Subject to paragraph 3 below and in accordance with the Plan, this Award will fully vest on the first anniversary of the Grant Date (the “Vesting Date”), subject to the Grantee’s continuous service as a member of the Board through the Vesting Date (provided that, in the event the Grantee’s service as a member of the Board terminates prior to the Vesting Date, the Award shall be subject to the provisions of Article X of the Plan). Upon vesting, the Common Shares and any accrued dividend equivalents will be issued, without restrictions, within thirty (30) days following the Vesting Date or, in the case of Deferred Units, the settlement date selected at the time a valid deferral election was made in accordance with the Plan. This Award shall not be settled whenever the delivery of Common Shares under it would be a violation of any applicable law, rule or regulation.
3. This Award will fully vest, and Common Shares will be issued, without restrictions, upon the occurrence of a Change in Control (as such term is defined in the Plan); provided, however, that no issuance of Common Shares will be made until [•] unless the Change in Control also qualifies as a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of its assets, as determined under Section 409A of the Internal Revenue Code.
4. This Award and the number of Restricted Stock Units granted hereunder shall be subject to adjustment in accordance with the provisions of Article XI of the Plan.
5. In accordance with the Plan, settlement of the Award may be deferred to the extent the Company received from the Grantee an executed valid deferral election form, in compliance with such rules and procedures as the Committee deems advisable, no later than December 31 of the calendar year prior to the year in which the Award was granted.
6. This Award is not assignable except as provided in the case of death and is not subject in whole or in part to attachment, execution or levy of any kind.
7. The Grantee shall not be eligible to receive any dividends or other distributions paid with respect to the Common Shares underlying the Units during the Restricted Period. An amount equivalent to these dividends and/or other distributions shall be paid to the Grantee upon and subject to the vesting and issuance of Common Shares and payment of this Award. Any such payment (unadjusted for interest) shall be made in whole shares of the Common Stock of the Company (rounding up to the nearest whole share).
Attest: MURPHY OIL CORPORATION
___________________________________ By _________________________________
EXHIBIT 10.38
MURPHY OIL CORPORATION
2026 STOCK PLAN FOR NON-EMPLOYEE DIRECTORS
ELECTIVE RESTRICTED STOCK UNIT GRANT AGREEMENT
Restricted Stock Unit Award Number: ___________________ | Name of Grantee: ___________________________________ | Number of Restricted Stock Units Subject to this Grant: _______________________ | ||||||
This Restricted Stock Unit Award (this “Award”) is granted on and dated [•] (the “Grant Date”), by Murphy Oil Corporation, a Delaware corporation (the “Company”), pursuant to and for the purposes of the Company’s 2026 Stock Plan for Non-Employee Directors (the “Plan”), subject to the provisions set forth herein and in the Plan. Any terms used herein and not otherwise defined shall have the meaning set forth in the Plan.
1. The Company hereby grants to the individual named above (the “Grantee”) an Award of Restricted Stock Units each equal in value to one share of Common Stock (collectively, the “Units”). This Award constitutes a right to receive shares in the future and does not represent any current interest in the shares subject to the Award.
2. This Award is fully vested as of the Grant Date and the Common Shares and any accrued dividend equivalents will be issued, without restrictions, within thirty (30) days following the Grant Date or, in the case of Deferred Units, the settlement date selected at the time a valid deferral election was made in accordance with the Plan. This Award shall not be settled whenever the delivery of Common Shares under it would be a violation of any applicable law, rule or regulation.
3. This Award and the number of Restricted Stock Units granted hereunder shall be subject to adjustment in accordance with the provisions of Article XI of the Plan.
4. This Award is not assignable except as provided in the case of death and is not subject in whole or in part to attachment, execution or levy of any kind.
5. The Grantee shall not be eligible to receive any dividends or other distributions paid with respect to the Common Shares underlying the Units during the Restricted Period. An amount equivalent to these dividends and/or other distributions shall be paid to the Grantee upon and subject to the vesting and issuance of Common Shares and payment of this Award. Any such payment (unadjusted for interest) shall be made in whole shares of the Common Stock of the Company (rounding up to the nearest whole share).
Attest: MURPHY OIL CORPORATION
___________________________________ By _________________________________
EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Eric M. Hambly, certify that:
1.I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions)
a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.
| Date: August 5, 2026 | ||
| /s/ Eric M. Hambly | ||
Eric M. Hambly | ||
| Principal Executive Officer | ||
Ex. 31.1
EXHIBIT 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Thomas J. Mireles, certify that:
1.I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.
| Date: August 5, 2026 | ||
| /s/ Thomas J. Mireles | ||
| Thomas J. Mireles | ||
| Principal Financial Officer | ||
Ex. 31.2
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the quarterly report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period ended June 30, 2026 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Eric M. Hambly and Thomas J. Mireles, Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:
(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| Date: August 5, 2026 | ||
| /s/ Eric M. Hambly | ||
Eric M. Hambly | ||
| Principal Executive Officer | ||
| /s/ Thomas J. Mireles | ||
| Thomas J. Mireles | ||
| Principal Financial Officer | ||
Ex. 32.1