Murphy Oil Q3 2026 earnings rebound to $171M profit
A $500.0 million senior-note issue funded debt repurchases and repayments, related fees and general corporate purposes.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Form Type
10-Q
Rhea-AI Filing Summary
Murphy Oil Corporation (MUR) reported third-quarter 2026 production revenue of $849.2 million, compared with $721.0 million a year earlier. Income from continuing operations, including noncontrolling interest, was $195.8 million versus a $7.8 million loss; net income attributable to Murphy was $171.1 million versus a $3.0 million loss.
For the first nine months, production revenue was $2,507.9 million versus $2,076.8 million, and net income attributable to Murphy was $456.3 million versus $92.3 million. Net cash provided by continuing operations was $1,517.6 million, compared with $998.2 million. Property additions and dry-hole costs were $1,333.0 million.
Production averaged 192,283 barrels of oil equivalent per day in the quarter, down 7% year over year. Murphy reported an oil discovery offshore Vietnam, successful appraisal of Bubale offshore Côte d’Ivoire, and first oil at Lac Da Vang. In October, it entered a deepwater drillship agreement for an initial 10 wells, with estimated aggregate consideration of approximately $225 million to $325 million on a gross basis; commencement is anticipated in the first quarter of 2027.
3 points · 0 major0 major · 1 point
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointThird-quarter production revenue rose to $849.2 million from $721.0 million.
- Moderate pointNine-month net income attributable to Murphy was $456.3 million, versus $92.3 million.
- Moderate pointNine-month net cash from continuing operations was $1,517.6 million, versus $998.2 million.
Negative
- Moderate pointThird-quarter production fell 7% to 192,283 barrels of oil equivalent per day.
Filing Explained
At September 30, 2026, Murphy had $1,623,123 thousand in long-term debt and $500,301 thousand in cash, after issuing the 2034 notes and redeeming older notes.
Murphy’s Form 10-Q reports unaudited results for the quarter and nine months ended
In the first quarter of 2026, Murphy issued
Key Figures
Revenue from production: $849.2 million
Net income attributable to Murphy: $171.1 million
Net cash provided by continuing operations: $1,517.6 million
+3 more
6 metrics
Revenue from production
$849.2 million
Three months ended September 30, 2026; $721.0 million in 2025.
Net income attributable to Murphy
$171.1 million
Three months ended September 30, 2026; a $3.0 million loss in 2025.
Net cash provided by continuing operations
$1,517.6 million
Nine months ended September 30, 2026; $998.2 million in 2025.
Hydrocarbon production
192,283 barrels of oil equivalent per day
Third quarter of 2026; down 7% compared with the third quarter of 2025.
Property additions and dry-hole costs
$1,333.0 million
Nine months ended September 30, 2026.
Senior notes issued
$500.0 million
6.50% annual interest rate; maturity February 15, 2034.
Key Terms
barrels of oil equivalent (BOE), net oil pay, asset retirement obligations, floating storage and offloading vessel, +1 more
5 terms
barrels of oil equivalent (BOE) technical
"192,283 barrels of oil equivalent (BOE) per day"
A barrel of oil equivalent (boe) is a single unit that combines different types of energy production—mainly crude oil and natural gas—by converting them into the same energy value so they can be compared and totaled. Think of it as turning apples and oranges into pieces of fruit so you can count them together; investors use boe to compare production, reserves and revenue potential across companies and projects on a like-for-like basis.
net oil pay technical
"approximately 88 feet of net oil pay"
Net oil pay measures the portion of a subsurface rock layer that actually contains producible oil after excluding thin, non-porous or water-bearing zones and applying technical cutoffs. For investors, it’s a key input to estimated recoverable volumes and future production—think of it as the usable part of a loaf: not the whole loaf matters, only the slices you can actually serve, which drive revenue and asset value.
asset retirement obligations financial
"estimated costs to dismantle and abandon its producing oil and natural gas properties"
Asset retirement obligations are a company’s recorded promise to pay for dismantling, cleaning up, or restoring property when a long-lived asset is retired — for example decommissioning a plant or removing equipment. Companies estimate the future cleanup cost today and book it as a liability (and add the cost to the asset), so it affects the balance sheet, reported profits over time, and future cash needs; investors watch it like a planned bill that can reduce cash available for returns.
floating storage and offloading vessel technical
"finance lease for a floating storage and offloading vessel"
Adjusted Term Secured Overnight Financing Rate (SOFR) financial
"The “Adjusted Term Secured Overnight Financing Rate (SOFR)” of interest"
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
How much revenue did MUR report in the third quarter of 2026?
Murphy’s revenue from production was $849.2 million for the three months ended September 30, 2026, compared with $721.0 million for the same period in 2025. Total revenues and other income were $855.0 million and $733.0 million, respectively.
What was MUR’s net income in the third quarter of 2026?
Net income attributable to Murphy was $171.1 million for the third quarter of 2026, compared with a $3.0 million loss in the same period of 2025. Income from continuing operations, including noncontrolling interest, was $195.8 million, compared with a $7.8 million loss.
What are the terms of MUR’s deepwater drillship agreement?
In October 2026, Murphy entered an agreement for a deepwater drillship with an initial term covering 10 wells and estimated aggregate consideration of approximately $225 million to $325 million on a gross basis. It includes options for up to five additional wells at rates to be agreed before exercise and is anticipated to commence in the first quarter of 2027.
What were the terms of MUR’s 2026 senior notes?
Murphy closed a public offering of $500.0 million aggregate principal amount of senior notes bearing interest at 6.50% per annum and maturing February 15, 2034. Interest is payable semi-annually on August 15 and February 15, beginning August 15, 2026. Proceeds were used for debt repurchases and repayments, related fees and general corporate purposes.
AI-generated analysis. How Rhea-AI works. Not financial advice.
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 September 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 October 31, 2026 was 143,381,125 .
MURPHY OIL CORPORATION
TABLE OF CONTENTS
| Page | |||||
Part I – Financial Information | 2 | ||||
Item 1. Financial Statements | 2 | ||||
Consolidated Balance Sheets | 2 | ||||
Consolidated Statements of Operations | 3 | ||||
Consolidated Statements of Comprehensive Income (Loss) | 4 | ||||
Consolidated Statements of Cash Flows | 5 | ||||
Consolidated Statements of Stockholders’ Equity | 6 | ||||
Notes to Consolidated Financial Statements | 7 | ||||
Note A – Basis of Presentation | 7 | ||||
Note B – New Accounting Principles and Recent Accounting Pronouncements | 7 | ||||
Note C – Revenue from Contracts with Customers | 8 | ||||
Note D – Property, Plant and Equipment | 10 | ||||
Note E – Financing Arrangements and Debt | 12 | ||||
Note F – Other Financial Information | 13 | ||||
Note G – Asset Retirement Obligations | 14 | ||||
Note H – Employee and Retiree Benefit Plans | 14 | ||||
Note I – Incentive Plans | 15 | ||||
Note J – Net Income Per Common Share | 17 | ||||
Note K – Income Taxes | 17 | ||||
Note L – Financial Instruments and Risk Management | 18 | ||||
Note M – Accumulated Other Comprehensive Loss | 20 | ||||
Note N – Environmental and Other Contingencies | 21 | ||||
Note O – Common Stock Issued and Outstanding | 22 | ||||
Note P – Business Segments | 23 | ||||
Note Q – Leases | 28 | ||||
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 29 | ||||
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 49 | ||||
Item 4. Controls and Procedures | 49 | ||||
Part II – Other Information | 50 | ||||
Item 1. Legal Proceedings | 50 | ||||
Item 1A. Risk Factors | 50 | ||||
Item 5. Other Information | 51 | ||||
Item 6. Exhibits | 51 | ||||
Signature | 52 | ||||
1
Table of Contents
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| (Thousands of dollars, except share amounts) | September 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
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | $ | $ | $ | |||||||||||||||||||
| 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 | |||||||||||||||||||||||
| Impairment of assets | |||||||||||||||||||||||
| 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 (loss) from continuing operations before income taxes | ( | ||||||||||||||||||||||
| Income tax expense | |||||||||||||||||||||||
| Income (loss) from continuing operations | ( | ||||||||||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | ( | ( | ( | ||||||||||||||||||||
| Net income (loss) including noncontrolling interest | ( | ||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | ( | ||||||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | $ | ( | $ | $ | ||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | $ | ( | $ | $ | ||||||||||||||||||
| Discontinued operations | ( | ||||||||||||||||||||||
| Net income (loss) | $ | $ | ( | $ | $ | ||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | $ | ( | $ | $ | ||||||||||||||||||
| Discontinued operations | ( | ||||||||||||||||||||||
| Net income (loss) | $ | $ | ( | $ | $ | ||||||||||||||||||
| Cash dividends per common share | $ | $ | $ | $ | |||||||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | |||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net income (loss) 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 (loss) including noncontrolling interest | ( | ||||||||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | ( | ||||||||||||||||||||||
| COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | $ | ( | $ | $ | ||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| Nine Months Ended September 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 | |||||||||||
| Deferred income tax expense | |||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | |||||||||||
| Accretion of asset retirement obligations | |||||||||||
| Long-term non-cash compensation | |||||||||||
| Amortization of undeveloped leases | |||||||||||
| (Income) loss from discontinued operations | ( | ||||||||||
| Unrealized gain on derivative instruments | ( | ||||||||||
| Impairment of assets | |||||||||||
| Net increase in non-cash working capital | ( | ( | |||||||||
| Other operating activities, net | ( | ( | |||||||||
| 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 required by financing activities | ( | ( | |||||||||
| Effect of exchange rate changes on cash and cash equivalents | ( | ||||||||||
| Net increase 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
Table of Contents
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(UNAUDITED)
| Three Months Ended September 30, | Nine Months Ended September 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
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (the Company or Murphy) on pages 2 through 6 of this Form 10-Q report.
Note A – Basis of Presentation
The unaudited financial statements presented herein, in the opinion of Murphy’s management, include all adjustments necessary to present fairly the Company’s financial position as at September 30, 2026 and December 31, 2025, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2026 and 2025, in conformity with the United States 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 nine months ended September 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.
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Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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.
8
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
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 nine months ended September 30, 2026 and 2025 were as follows.
| Three Months Ended September 30, | Nine Months Ended September 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 September 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 $245.9 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 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 September 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,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note C – Revenue from Contracts with Customers (Continued)
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 September 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 September 30, 2026, the Company had total capitalized drilling costs pending the determination of proved reserves of $494.1 million. The following table reflects the net changes in capitalized exploratory well costs during the nine months ended September 30, 2026 and 2025.
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Beginning balance at January 1 | $ | $ | |||||||||
| Additions pending the determination of proved reserves | |||||||||||
| Reclassifications to proved properties based on the determination of proved reserves | ( | ||||||||||
| Capitalized exploratory well costs charged to expense | ( | ||||||||||
| Balance at September 30 | $ | $ | |||||||||
Capital additions of $317.6 million, for the nine months ended September 30, 2026, were mainly for exploration wells including the Bubale-1X (Block CI-709) and Bubale West-1X (Block CI-103) wells in Côte d’Ivoire; the Hai Su Vang-3X (Golden Sea Lion), Block 15-1/05 and Lac Da Trang (White Camel) North-1X, Block 15-1/05 wells in Vietnam; and the Banjo #1 (Mississippi Canyon 385) and Cello #1 (Mississippi Canyon 385) wells in the Gulf of America.
In the third quarter of 2026, Murphy successfully appraised the Bubale discovery offshore Côte d’Ivoire with the Bubale West-1X well, which encountered approximately 88 feet of net oil pay in the Turonian reservoir and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
additional hydrocarbons in the deeper Albian reservoir. The Company also announced an oil discovery at the Lac Da Trang (White Camel) North-1X exploration well offshore Vietnam, encountering approximately 131 feet of net oil pay. Murphy also achieved first oil from the Lac Da Vang (Golden Camel) development offshore 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.
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 $43.1 million, for the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2025.
The preceding table excludes well costs of $76.1 million incurred and expensed directly to dry hole for the nine months ended September 30, 2026. In 2026, these costs primarily related to the Civette-1X (Block CI-502) exploration well in Côte d’Ivoire, 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. There were no capitalized well costs charged to dry hole expense for the nine months ended September 30, 2025.
The following table provides an aging of capitalized exploration costs based on the date the drilling operations were initiated for each individual project.
| September 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 | |||||||||||||||||||||||
| $ | $ | ||||||||||||||||||||||
Of the $483.6 million of exploration well costs capitalized and classified as more than one year at September 30, 2026, $261.4 million was in Côte d’Ivoire, $114.0 million was in Vietnam, $105.5 million was in the Gulf of America, 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 third quarter of 2025, the Company purchased additional working interest in the Eagle Ford Shale, in acreages primarily operated by Murphy, for $23.0 million.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note D – Property, Plant and Equipment (Continued)
Impairments
There were no 115.0 92.0
Note E – Financing Arrangements and Debt
Long-term debt for the respective periods presented consisted of the following.
| September 30, | December 31, | ||||||||||
| (Thousands of dollars) | 2026 | 2025 | |||||||||
| Notes payable | |||||||||||
| $ | $ | ||||||||||
| Total notes payable | |||||||||||
| Unamortized debt issuance cost and discount on notes payable | ( | ( | |||||||||
| Total notes payable, net of unamortized discount | |||||||||||
| Finance lease obligations, due through October 2039 ² | |||||||||||
| Total debt including current maturities | |||||||||||
| Senior unsecured revolving credit facility | |||||||||||
| Current maturities | ( | ( | |||||||||
| Total long-term debt | $ | $ | |||||||||
1 Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.
2 Includes finance lease liabilities of $83.9 million at September 30, 2026 for a floating storage and offloading vessel (FSO) in Vietnam. See Note Q - Leases for additional information.
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 September 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 September 30, 2026, the interest rate in effect on borrowings under the Amended RCF was 6.16 %. At September 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note E – Financing Arrangements and Debt (Continued)
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.
Note F – Other Financial Information
Supplemental Information to Statement of Cash Flows
| Nine Months Ended September 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 | ( | ( | |||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 nine months ended September 30, 2026 and 2025 are shown in the following table.
| (Thousands of dollars) | September 30, 2026 | September 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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note H – Employee and Retiree Benefit Plans (Continued)
The table that follows provides the components of net periodic benefit expense for the three and nine months ended September 30, 2026 and 2025.
| Three Months Ended September 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) | $ | $ | $ | $ | ( | ||||||||||||||||||
| Nine Months Ended September 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 nine months ended September 30, 2026, the Company made contributions of $22.5 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 $8.1 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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
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 nine months ended September 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 | |||||||||||||||||||||||
Performance-based RSUs 1 | August 31, 2026 | $ | Monte Carlo | |||||||||||||||||||||||
Time-based RSUs (Stock-Settled) 2 | August 31, 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 nine months ended September 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 | |||||||||||||||||||||||
Time-Based RSUs 2 | September 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note I – Incentive Plans (Continued)
Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.
| Nine Months Ended September 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 (loss) attributable to Murphy was used as the numerator in computing both basic and diluted income (loss) per common share for the three and nine months ended September 30, 2026 and 2025. The following table reconciles the weighted-average shares outstanding used for these computations.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Weighted-average shares, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Basic method | |||||||||||||||||||||||
Dilutive restricted stock units 1 | |||||||||||||||||||||||
| Diluted method | |||||||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – BASIC | $ | $ | ( | $ | $ | ||||||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – DILUTED | $ | $ | ( | $ | $ | ||||||||||||||||||
1 Due to a net loss recognized by the Company for the three months ended September 30, 2025, no unvested stock awards were included in the computation of the diluted net income (loss) per common share as the effect would have been antidilutive.
The following table reflects the dilutive restricted stock units during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Antidilutive restricted stock units excluded from diluted shares | |||||||||||||||||||||||
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 nine months ended September 30, 2026 and 2025, the Company’s effective income tax rates were as follows:
| 2026 | 2025 | ||||||||||
| Three months ended September 30, | ( | ||||||||||
| Nine months ended September 30, | |||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note K – Income Taxes (Continued)
The effective tax rate for the three months ended September 30, 2026 was below the U.S. statutory tax rate of 21% primarily due to an income tax deduction for prior years’ Australia exploration spend, which resulted in an income tax benefit of $11.9 million.
The effective tax rate for the three months ended September 30, 2025 was below 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; foreign currency translation adjustments; no tax benefit applied to the pretax loss of the noncontrolling interest in MP GOM; 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 unfavorable impact on the effective tax rate was partially offset by the tax effect of stock-based compensation and U.S. state tax expense.
The effective tax rate for the nine months ended September 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 an income tax deduction for prior years’ Australia exploration spend and no tax applied to the pretax income of the noncontrolling interest in MP GOM.
The effective tax rate for the nine months ended September 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; foreign currency translation adjustments; 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 nine months ended September 30, 2026, the Company paid $14.4 million in net cash income tax, compared to $9.2 million in net cash income tax for the nine months ended September 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 September 30, 2026, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: U.S. – 2016; Canada – 2022. 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
Commodity Price Risks
The Company is subject to commodity price risk related to products it produces and sells. During the three and nine months ended September 30, 2026, the Company did no t have any crude oil or natural gas derivative contracts.
During the third quarter of 2025, the Company held open natural gas swap contracts. Under the swaps contracts, which mature monthly, the Company pays the average monthly price in effect and receives the fixed contract price on a notional amount of sales volume, thereby fixing the price for the commodity sold.
At September 30, 2025, volumes per day associated with outstanding natural gas derivative contracts and the weighted average prices for these contracts were as follows:
| NYMEX Henry Hub | Area | Commodity | Volumes MMCF/d | Price/MCF | Start Date | End Date | ||||||||||||||
| Fixed price derivative swap | United States | Natural Gas | $ | 10/1/2025 | 12/31/2025 | |||||||||||||||
For the three and nine months ended September 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 September 30, | Nine Months Ended September 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 September 30, 2026 and December 31, 2025, are shown in the following table.
| September 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 September 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note L – Financial Instruments and Risk Management (Continued)
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.
| September 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
For the three and nine months ended September 30, 2025, an impairment charge of $115.0 92.0
The fair values were determined by internal discounted cash flow models using estimates of future production, prices, costs and discount rates believed to be consistent with those used by principal market participants in the applicable region.
The fair value information associated with the impaired properties is presented in the following tables.
| Nine Months Ended September 30, 2025 | |||||||||||||||||||||||||||||
| Net Book Value Prior to Impairment | Total Pretax Impairment | ||||||||||||||||||||||||||||
| Fair Value | |||||||||||||||||||||||||||||
| (Thousands of dollars) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||
| Property, plant and equipment: | |||||||||||||||||||||||||||||
| Impaired proved properties | |||||||||||||||||||||||||||||
| United States - Offshore | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Note M – Accumulated Other Comprehensive Loss
The components of “Accumulated other comprehensive loss” on the Consolidated Balance Sheets at December 31, 2025 and September 30, 2026, and the changes during the nine months ended September 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 September 30, 2026 | $ | ( | $ | ( | $ | ( | |||||||||||
1 Reclassifications before taxes of $5.0 million are included in the computation of net periodic benefit expense for the nine months ended September 30, 2026. See Note H for additional information. Related income taxes of $0.8 million are included in "Income tax expense” on the Consolidated Statements of Operations for the nine months ended September 30, 2026.
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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 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, United States executive agencies were ordered to cease participation in and withdraw from the United Nations Framework Convention on Climate Change. On February 12, 2026, the EPA announced the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note N – Environmental and Other Contingencies (Continued)
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.
In August 2026, the Company responded to a produced water release from a pipeline on private land in the Tupper Montney West field. The incident was reported by Murphy to the appropriate regulatory authorities, and the affected pipeline was isolated and drained. Murphy continues environmental monitoring and remediation activities while working closely with the British Columbia Energy Regulator and private landowners.
The Company currently owns or leases and has in the past owned or leased properties at which hazardous substances have been or are being handled. Hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to investigate, remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. Depending on the evolution of laws, regulations and litigation outcomes relating to climate change, there can be no guarantee that climate change litigation will not in the future materially adversely affect our results of operations, cash flows and financial condition.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and additional expenditures could be required at known sites. However, based on information currently available to the Company, the amount of future investigation and remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.
LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
Note O – Common Stock Issued and Outstanding
Activity in the number of shares of common stock issued and outstanding for the nine months ended September 30, 2026 and 2025 is shown below.
| (Number of shares outstanding) | September 30, 2026 | September 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note O – Common Stock Issued and Outstanding (Continued)
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 nine months ended September 30, 2026, the Company did no t repurchase any shares of its common stock. During the nine months ended September 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 September 30, 2026, the Company had $550.1 million of its common stock remaining available to repurchase under the program.
Note P – Business Segments
Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate includes interest income, other gains and losses, interest expense and unallocated overhead and is shown in the tables to reconcile the business segments to consolidated totals. The Company has accounted for its former United Kingdom (U.K.), Malaysia and U.S. refining and marketing operations as discontinued operations for all periods presented. Murphy’s President and Chief Executive Officer, Eric M. Hambly, acts as the Chief Operating Decision Maker (CODM).
“Other segment costs (income)” below are those items that are included in Segment income (loss) but are not regularly provided to the CODM or are reported to the CODM but are not considered to be significant segment expenses. “Other segment costs (income)” for the periods presented included certain pension amortization costs allocated to the reportable segments, and dividend income attributed to the Canada segment.
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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 September 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.
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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 September 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 | |||||||||||||||||||||||||||||||||||
| Impairment of assets | |||||||||||||||||||||||||||||||||||
| 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 (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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note P – Business Segments (Continued)
| Exploration and Production | |||||||||||||||||||||||||||||||||||
(Millions of dollars) | United States 1 | Canada | Other | Total E&P | Corporate and Discontinued Operations | Consolidated Total | |||||||||||||||||||||||||||||
| Nine Months Ended September 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.
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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 | |||||||||||||||||||||||||||||
| Nine Months Ended September 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 | |||||||||||||||||||||||||||||||||||
| Impairment of assets | |||||||||||||||||||||||||||||||||||
| 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Note Q – Leases
Nature of Leases
The Company has entered into various operating and finance leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and natural gas field equipment.
Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of Company discretion and mutual agreement between the Company and the lessor. Purchase options also exist for certain leases.
During the third quarter of 2026, the Company commenced a finance lease for a floating storage and offloading vessel associated with its Vietnam operations. The lease term extends from September 2026 through October 2039, coinciding with the expiration of the relevant production sharing contract. The Company recognized a finance lease right-of-use asset of $103.4 million and a finance lease liability of $83.9 million in connection with this arrangement, with approximately $19.5 million in lease payments made prior to commencement. Finance lease right-of-use assets are contained in “Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization” on the Consolidated Balance Sheets.
In October 2026, the Company entered into an agreement for the use of a deepwater drillship in the Gulf of America. The initial term of the agreement covers 10 wells. Based on current estimates of well durations and applicable rates, the aggregate consideration associated with the initial term is approximately $225 million to $325 million on a gross basis. Actual payments may differ based on the duration of each well and the contractual rate applicable during periods of operation, movement, standby, or other activities. The agreement also provides the Company with options for up to five additional wells at rates to be agreed upon before exercise of the options. The agreement is anticipated to commence in the first quarter of 2027. As the agreement was executed after September 30, 2026 and had not commenced as of that date, no
Maturity of Lease Liabilities
| (Thousands of dollars) | Operating Leases | Finance Leases | Total | ||||||||||||||
| 2026 | $ | $ | $ | ||||||||||||||
| 2027 | |||||||||||||||||
| 2028 | |||||||||||||||||
| 2029 | |||||||||||||||||
| 2030 | |||||||||||||||||
| Remaining | |||||||||||||||||
| Total future minimum lease payments | |||||||||||||||||
| Less imputed interest | ( | ( | ( | ||||||||||||||
Present value of lease liabilities 1 | $ | $ | $ | ||||||||||||||
1 Includes both the current and long-term portion of the lease liabilities.
Lease Term and Discount Rate
| September 30, 2026 | December 31, 2025 | ||||||||||
| Weighted average remaining lease term: | |||||||||||
| Operating leases | |||||||||||
| Finance leases | |||||||||||
| Weighted average discount rate: | |||||||||||
| Operating leases | % | % | |||||||||
| Finance leases | % | % | |||||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the unaudited consolidated financial statements and accompanying notes for the period ended September 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, Canada and Vietnam. 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 third quarter of 2026 were as follows:
•Production was 192,283 barrels of oil equivalent (BOE) per day (including NCI), a decrease from 206,936 BOE per day in the third quarter of 2025;
•Advanced the Bubale appraisal program offshore Côte d’Ivoire, with the Bubale West-1X well;
•Drilled an oil discovery at the Lac Da Trang (White Camel) North-1X exploration well offshore Vietnam;
•Achieved first oil from the Lac Da Vang (Golden Camel) development offshore Vietnam;
•Commenced production from the Chinook #8 development well in the Gulf of America; and
•Brought online 14 operated and four non-operated Eagle Ford Shale wells, and eight wells in the Tupper Montney.
Subsequent to the third quarter:
•Secured six exploration blocks from the August Gulf of America federal offshore lease sale.
•Signed agreements with the government of Mauritania for two offshore exploration blocks
Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended September 30, 2026 was $195.8 million compared to net loss of $7.8 million for the same period in 2025. The increase in 2026 was primarily driven by higher revenues from production ($128.2 million), no impairment charges in the current year ($115.0 million), and lower lease operating expenses ($35.2 million). These favorable items were partially offset by higher income tax expense ($35.2 million), and higher other operating expenses ($22.7 million).
Higher revenues were driven by higher realized prices in the United States and Canada. These favorable impacts were partially offset by lower volumes in the Eagle Ford Shale and the Gulf of America. The prior-year period included impairment charges related to the Dalmatian field, while no impairment charges were recorded in the current year. Lower lease operating expenses were primarily driven by lower workover activity, insurance proceeds received related to past workovers, and production-related costs in the Gulf of America, partially offset by increased activity in the Eagle Ford Shale and Canada. Higher income tax expense primarily reflected higher pretax income. Higher other operating expenses primarily related to abandonment and environmental remediation costs in the Gulf of America and Canada, respectively.
For the three months ended September 30, 2026 total hydrocarbon production was 192,283 barrels of oil equivalent per day, a decrease of 7% compared to the third quarter of 2025. The decrease was principally due to lower volumes in the Gulf of America and the Eagle Ford Shale. Lower Gulf of America volumes primarily
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Overview (Continued)
reflected natural declines at various wells, and lower Eagle Ford Shale and Tupper Montney volumes primarily reflected the timing of new wells. These decreases were partially offset by higher Canada Offshore volumes due to less downtime at Terra Nova.
Net income from continuing operations, including noncontrolling interest, for the nine months ended September 30, 2026 was $529.0 million, an increase of $412.9 million compared to the same period of 2025. Higher net income from continuing operations was primarily driven by higher revenues from production ($431.1 million), lower lease operating expenses ($168.6 million), no impairment charges in the current year ($115.0 million), and higher other income ($38.6 million). These favorable items were partially offset by higher income tax expense ($128.4 million), higher exploration expenses ($97.8 million), higher depreciation, depletion and amortization (DD&A) ($51.0 million), and higher other operating expenses ($34.4 million).
Higher revenues were primarily driven by higher realized crude oil prices across the United States and Canada, together with higher sales volumes at Eagle Ford Shale, Kaybob and Terra Nova. These favorable impacts were partially offset by lower oil sales volumes in the Gulf of America and lower natural gas sales volumes at Tupper Montney. Lower lease operating expenses were primarily driven by substantially lower workover and production-related costs in the Gulf of America, partially offset by higher activity in the Eagle Ford Shale and higher repair, maintenance and workover costs in Canada. The prior-year period included impairment charges, while no impairment charges were recorded in the current year. Higher other income was primarily due to favorable foreign exchange movements. Higher income tax expense primarily reflected higher pretax income. Higher exploration expenses were primarily driven by dry hole costs in Côte d’Ivoire and Vietnam. Higher DD&A was primarily driven by higher sales volumes and depletion rates in the Eagle Ford Shale, higher rates in the Gulf of America and higher sales volumes at Kaybob and offshore Canada, partially offset by lower sales volumes in the Gulf of America and at Tupper Montney. Higher other operating expenses primarily related to abandonment and environmental remediation costs in the Gulf of America and Canada.
For the nine months ended September 30, 2026, total hydrocarbon production was 182,494 barrels of oil equivalent per day, a decrease of 3% compared to the same period in 2025. The decrease was principally due to lower volumes in the Gulf of America as a result of natural decline, and at Tupper Montney in Canada due to fewer new wells online in the current year. These decreases were partially offset by new Eagle Ford Shale production.
Murphy’s continuing operations generate revenues through the production and sale of crude oil, natural gas and natural gas liquids in the United States and Canada. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders. International conflicts and geopolitical uncertainty surrounding domestic and foreign governmental regulations, including effects of trade policies, tariffs and other trade restrictions, can affect the demand for crude oil, natural gas and natural gas liquids, as well as the cost of oil field goods and services.
At September 30, 2026, the West Texas Intermediate (WTI) crude oil futures price was $89.42 per barrel, whereas the crude oil futures price at the end of October 2026 was $104.12, reflecting a 16% increase in price. As of November 2, 2026 closing, the NYMEX WTI forward curve price for the remainder of 2026 was $96.46 per barrel. Changes in commodity prices will directly affect the Company’s future profits and operating cash flows.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations
Murphy’s Net income (loss) by type of business and geographic segment is presented below:
| Income (Loss) | |||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
| United States | $ | 222.4 | $ | 28.9 | $ | 653.3 | $ | 223.3 | |||||||||||||||
| Canada | 20.9 | (6.1) | 104.4 | 45.8 | |||||||||||||||||||
| Other | (16.1) | (12.0) | (128.9) | (30.4) | |||||||||||||||||||
| Total exploration and production | 227.2 | 10.8 | 628.8 | 238.7 | |||||||||||||||||||
| Corporate | (31.5) | (18.6) | (99.9) | (122.7) | |||||||||||||||||||
| Income (loss) from continuing operations | 195.7 | (7.8) | 528.9 | 116.0 | |||||||||||||||||||
Discontinued operations, net of tax 1 | (0.2) | (0.5) | (1.2) | 0.2 | |||||||||||||||||||
| Net income (loss) including noncontrolling interest | 195.5 | (8.3) | 527.7 | 116.2 | |||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 24.4 | (5.3) | 71.4 | 23.9 | |||||||||||||||||||
| Net income (loss) attributable to Murphy | $ | 171.1 | $ | (3.0) | $ | 456.3 | $ | 92.3 | |||||||||||||||
1 The Company has presented its former U.K., Malaysia and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Exploration and Production Continuing Operations
The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment unless otherwise noted.
The following is a summarized statement of operations for E&P continuing operations:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Revenues and other income | |||||||||||||||||||||||
Revenue from production | $ | 849.2 | $ | 721.0 | $ | 2,507.9 | $ | 2,076.8 | |||||||||||||||
Other income | 2.0 | 0.8 | 4.5 | 4.9 | |||||||||||||||||||
Total revenues and other income | 851.2 | 721.8 | 2,512.4 | 2,081.7 | |||||||||||||||||||
Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 149.2 | 184.4 | 436.4 | 605.0 | |||||||||||||||||||
| Severance and ad valorem taxes | 13.6 | 12.3 | 42.3 | 31.8 | |||||||||||||||||||
| Transportation, gathering and processing | 47.1 | 48.1 | 139.4 | 151.1 | |||||||||||||||||||
| Depreciation, depletion and amortization | 268.8 | 281.4 | 780.5 | 730.7 | |||||||||||||||||||
Impairment of assets | — | 115.0 | — | 115.0 | |||||||||||||||||||
| Accretion of asset retirement obligations | 15.0 | 14.6 | 44.2 | 43.1 | |||||||||||||||||||
Exploration expenses, including undeveloped lease amortization | 33.1 | 32.5 | 155.2 | 57.4 | |||||||||||||||||||
| Selling and general expenses | 17.8 | 9.5 | 50.1 | 32.5 | |||||||||||||||||||
| Other | 30.0 | 6.6 | 53.8 | 13.0 | |||||||||||||||||||
| Results of operations before taxes | 276.6 | 17.4 | 810.5 | 302.1 | |||||||||||||||||||
Income tax provisions | 49.4 | 6.6 | 181.7 | 63.4 | |||||||||||||||||||
Results of operations (excluding Corporate segment) 1 | $ | 227.2 | $ | 10.8 | $ | 628.8 | $ | 238.7 | |||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Pricing
The following table contains the weighted average sales prices for the three and nine months ended September 30, 2026 and 2025:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Weighted average sales prices) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Crude oil and condensate – dollars per barrel | |||||||||||||||||||||||
United States - Onshore | $ | 86.48 | $ | 65.48 | $ | 86.29 | $ | 66.24 | |||||||||||||||
United States - Offshore 1 | 89.38 | 67.00 | 86.40 | 67.81 | |||||||||||||||||||
Canada - Onshore 2 | 78.40 | 56.33 | 77.66 | 59.46 | |||||||||||||||||||
Canada - Offshore 2 | 108.21 | 69.42 | 97.33 | 70.17 | |||||||||||||||||||
Other 2 | — | — | 71.04 | 72.97 | |||||||||||||||||||
| Natural gas liquids – dollars per barrel | |||||||||||||||||||||||
| United States - Onshore | 23.89 | 18.57 | 21.82 | 19.92 | |||||||||||||||||||
United States - Offshore 1 | 20.12 | 20.18 | 19.35 | 21.85 | |||||||||||||||||||
Canada - Onshore 2 | 33.66 | 26.88 | 32.05 | 32.54 | |||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | |||||||||||||||||||||||
| United States - Onshore | 2.54 | 2.64 | 2.89 | 2.87 | |||||||||||||||||||
United States - Offshore 1 | 3.50 | 3.39 | 4.22 | 3.73 | |||||||||||||||||||
Canada - Onshore 2 | 1.63 | 1.22 | 1.84 | 1.68 | |||||||||||||||||||
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 nine months ended September 30, 2026 and 2025:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Average price for the period) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Oil and NGLs | |||||||||||||||||||||||
| WTI ($/BBL) | $ | 85.79 | $ | 64.93 | $ | 83.50 | $ | 66.70 | |||||||||||||||
| Natural gas | |||||||||||||||||||||||
| Henry Hub ($/MMBTU) | 2.88 | 3.03 | 3.56 | 3.49 | |||||||||||||||||||
| AECO (C$/MCF) | 1.56 | 0.63 | 1.73 | 1.50 | |||||||||||||||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Production Volumes
The following table contains hydrocarbons produced during the three and nine months ended September 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 36.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net crude oil and condensate | |||||||||||||||||||||||
United States - Onshore | 30,157 | 34,703 | 28,509 | 26,797 | |||||||||||||||||||
United States - Offshore 1 | 48,183 | 56,071 | 50,300 | 56,835 | |||||||||||||||||||
Canada - Onshore | 3,901 | 3,495 | 3,899 | 2,799 | |||||||||||||||||||
Canada - Offshore | 6,972 | 5,518 | 7,945 | 6,658 | |||||||||||||||||||
| Other | 237 | 278 | 234 | 276 | |||||||||||||||||||
Total net crude oil and condensate | 89,450 | 100,065 | 90,887 | 93,365 | |||||||||||||||||||
| Net natural gas liquids | |||||||||||||||||||||||
United States - Onshore | 7,580 | 8,042 | 6,741 | 5,905 | |||||||||||||||||||
United States - Offshore 1 | 4,059 | 4,500 | 4,110 | 4,344 | |||||||||||||||||||
Canada - Onshore | 543 | 442 | 547 | 491 | |||||||||||||||||||
Total net natural gas liquids | 12,182 | 12,984 | 11,398 | 10,740 | |||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | |||||||||||||||||||||||
United States - Onshore | 34,923 | 39,411 | 33,629 | 32,711 | |||||||||||||||||||
United States - Offshore 1 | 44,721 | 50,477 | 48,327 | 51,528 | |||||||||||||||||||
Canada - Onshore | 464,262 | 473,431 | 399,298 | 425,342 | |||||||||||||||||||
Total net natural gas | 543,906 | 563,319 | 481,254 | 509,581 | |||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 192,283 | 206,936 | 182,494 | 189,035 | |||||||||||||||||||
| Noncontrolling interest | |||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,286) | (5,998) | (5,349) | (5,950) | |||||||||||||||||||
| Net natural gas liquids – barrels per day | (197) | (228) | (206) | (214) | |||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (1,829) | (1,963) | (1,913) | (1,715) | |||||||||||||||||||
Total noncontrolling interest 2,3 | (5,788) | (6,553) | (5,874) | (6,450) | |||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 186,495 | 200,383 | 176,620 | 182,585 | |||||||||||||||||||
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Sales Volumes
The following table contains hydrocarbons sold during the three and nine months ended September 30, 2026 and 2025. For further discussion on volumes, please see the “Revenues from Production” section on page 36.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||
| Net crude oil and condensate | ||||||||||||||||||||||||||
United States - Onshore | 30,157 | 34,703 | 28,509 | 26,797 | ||||||||||||||||||||||
United States - Offshore 1 | 47,856 | 57,903 | 50,124 | 56,849 | ||||||||||||||||||||||
Canada - Onshore | 3,901 | 3,495 | 3,899 | 2,799 | ||||||||||||||||||||||
Canada - Offshore | 6,975 | 5,513 | 8,249 | 8,114 | ||||||||||||||||||||||
| Other | — | — | 150 | 152 | ||||||||||||||||||||||
Total net crude oil and condensate | 88,889 | 101,614 | 90,931 | 94,711 | ||||||||||||||||||||||
| Net natural gas liquids | ||||||||||||||||||||||||||
United States - Onshore | 7,580 | 8,042 | 6,741 | 5,905 | ||||||||||||||||||||||
United States - Offshore 1 | 4,059 | 4,500 | 4,110 | 4,344 | ||||||||||||||||||||||
Canada - Onshore | 543 | 442 | 547 | 491 | ||||||||||||||||||||||
Total net natural gas liquids | 12,182 | 12,984 | 11,398 | 10,740 | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | ||||||||||||||||||||||||||
United States - Onshore | 34,923 | 39,411 | 33,629 | 32,711 | ||||||||||||||||||||||
United States - Offshore 1 | 44,721 | 50,477 | 48,327 | 51,528 | ||||||||||||||||||||||
Canada - Onshore | 464,262 | 473,431 | 399,298 | 425,342 | ||||||||||||||||||||||
Total net natural gas | 543,906 | 563,319 | 481,254 | 509,581 | ||||||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 191,722 | 208,484 | 182,538 | 190,381 | ||||||||||||||||||||||
| Noncontrolling interest | ||||||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,234) | (6,273) | (5,320) | (5,954) | ||||||||||||||||||||||
| Net natural gas liquids – barrels per day | (197) | (228) | (206) | (214) | ||||||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | (1,829) | (1,963) | (1,913) | (1,715) | ||||||||||||||||||||||
Total noncontrolling interest 2,3 | (5,736) | (6,828) | (5,845) | (6,454) | ||||||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 185,986 | 201,656 | 176,693 | 183,927 | ||||||||||||||||||||||
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
The following discussion of E&P continuing operations includes amounts attributable to a noncontrolling interest in MP GOM and excludes the Corporate segment unless otherwise noted.
Revenues from Production
The Company’s production revenues by country and product were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Revenues from production | |||||||||||||||||||||||
United States - Oil | $ | 633.4 | $ | 566.0 | $ | 1,853.8 | $ | 1,537.0 | |||||||||||||||
United States - Natural gas liquids | 24.2 | 22.1 | 61.9 | 58.0 | |||||||||||||||||||
United States - Natural gas | 22.6 | 25.3 | 82.2 | 78.0 | |||||||||||||||||||
Canada - Oil | 97.6 | 53.3 | 301.9 | 200.9 | |||||||||||||||||||
Canada - Natural gas liquids | 1.7 | 1.1 | 4.8 | 4.4 | |||||||||||||||||||
Canada - Natural gas | 69.7 | 53.1 | 200.4 | 195.5 | |||||||||||||||||||
Other - Oil | — | 0.1 | 2.9 | 3.0 | |||||||||||||||||||
Total revenue from production | $ | 849.2 | $ | 721.0 | $ | 2,507.9 | $ | 2,076.8 | |||||||||||||||
Revenue from production for the three months ended September 30, 2026 increased $128.2 million compared to the same period in 2025. The increase was primarily driven by higher realized oil prices in the U.S. and Canada. In Canada, higher volumes at Terra Nova and Kaybob further increased revenues, while higher natural gas prices at Tupper Montney offset lower sales volumes. These favorable impacts were partially offset by lower volumes in the Eagle Ford Shale due to fewer new wells online in the period, and in the Gulf of America due to the natural decline of wells.
Revenues from production for the nine months ended September 30, 2026 increased $431.1 million compared to the same period in 2025. Higher revenues were primarily driven by higher realized oil prices across the U.S. and Canada. The Eagle Ford Shale had higher oil volumes from new wells, while higher volumes at Kaybob and Terra Nova further increased revenues. At Tupper Montney, higher natural gas prices offset lower volumes. These favorable impacts were partially offset by lower Gulf of America oil volumes, particularly at Mormont and Khaleesi due to natural decline.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Lease Operating and Transportation, Gathering and Processing Expenses
The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:
| Three Months Ended September 30, | Nine Months Ended September 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 | $ | 39.0 | $ | 31.9 | $ | 9.75 | $ | 7.04 | $ | 105.6 | $ | 91.2 | $ | 9.47 | $ | 8.75 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 60.5 | 109.4 | 11.08 | 16.79 | 185.2 | 374.2 | 10.89 | 19.64 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 31.9 | 30.0 | 4.22 | 3.94 | 97.4 | 95.8 | 5.02 | 4.73 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 17.7 | 12.7 | 27.52 | 24.96 | 47.0 | 42.2 | 20.88 | 19.05 | ||||||||||||||||||||||||||||||||||||||||||
| Other | 0.1 | 0.4 | — | — | 1.2 | 1.6 | 30.43 | 37.54 | ||||||||||||||||||||||||||||||||||||||||||
Total lease operating expenses | $ | 149.2 | $ | 184.4 | $ | 8.46 | $ | 9.61 | $ | 436.4 | $ | 605.0 | $ | 8.76 | $ | 11.64 | ||||||||||||||||||||||||||||||||||
Transportation, gathering and processing | ||||||||||||||||||||||||||||||||||||||||||||||||||
United States - Onshore | $ | 3.5 | $ | 3.2 | $ | 0.88 | $ | 0.72 | $ | 9.9 | $ | 7.8 | $ | 0.89 | $ | 0.75 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 19.9 | 20.1 | 3.64 | 3.08 | 63.2 | 74.6 | 3.72 | 3.91 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 22.0 | 23.0 | 2.91 | 3.02 | 61.3 | 63.3 | 3.16 | 3.13 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 1.7 | 1.8 | 2.69 | 3.49 | 5.0 | 5.4 | 2.21 | 2.42 | ||||||||||||||||||||||||||||||||||||||||||
Total transportation, gathering and processing | $ | 47.1 | $ | 48.1 | $ | 2.67 | $ | 2.51 | $ | 139.4 | $ | 151.1 | $ | 2.80 | $ | 2.91 | ||||||||||||||||||||||||||||||||||
For the three months ended September 30, 2026 lease operating expenses decreased by $35.2 million and transportation, gathering and processing expenses decreased by $1.0 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by lower Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and the non-recurrence of prior-year workover costs at Marmalard and Khaleesi. These decreases were partially offset by current-quarter workover costs at Mormont.
For the nine months ended September 30, 2026 lease operating expenses decreased by $168.6 million, and transportation, gathering and processing expenses decreased by $11.7 million compared to the same period in 2025. Lower lease operating expenses were primarily driven by favorable Gulf of America workover costs, favorably impacted by insurance reimbursements at Marmalard and Neidermeyer and lower workover costs at Samurai and Khaleesi. In addition, lower FPSO rental fees at Cascade & Chinook also decreased lease operating expenses. The Company also received a one-time access fee related to the Lucius field, which further contributed to decreases during the period. These decreases were partially offset by higher Eagle Ford Shale operating costs related to workover costs and increased number of wells.
Lower transportation, gathering and processing expenses were primarily due to lower sales volumes in the Gulf of America.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Depreciation, Depletion and Amortization Expenses
The Company’s DD&A by geographic area were as follows:
| Three Months Ended September 30, | Nine Months Ended September 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 | $ | 128.3 | $ | 137.5 | $ | 32.03 | $ | 30.30 | $ | 355.6 | $ | 311.9 | $ | 31.88 | $ | 29.95 | ||||||||||||||||||||||||||||||||||
United States - Offshore | 101.0 | 104.6 | 18.48 | 16.06 | 311.1 | 307.8 | 18.30 | 16.16 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Onshore | 32.8 | 33.5 | 4.36 | 4.38 | 88.4 | 87.6 | 4.56 | 4.32 | ||||||||||||||||||||||||||||||||||||||||||
Canada - Offshore | 6.6 | 5.8 | 10.36 | 11.53 | 24.2 | 22.2 | 10.74 | 10.03 | ||||||||||||||||||||||||||||||||||||||||||
| Other | 0.1 | — | — | — | 1.2 | 1.2 | 28.74 | 31.66 | ||||||||||||||||||||||||||||||||||||||||||
Total DD&A | $ | 268.8 | $ | 281.4 | $ | 15.24 | $ | 14.67 | $ | 780.5 | $ | 730.7 | $ | 15.66 | $ | 14.06 | ||||||||||||||||||||||||||||||||||
DD&A for the three months ended September 30, 2026 decreased by $12.6 million compared to the same period in 2025. The decrease was primarily driven by lower volumes in the Eagle Ford Shale due to fewer new wells online in the quarter, as well as lower production in the Gulf of America due to the natural decline of wells.
DD&A for the nine months ended September 30, 2026 increased by $49.8 million compared to the same period in 2025. The increase was primarily driven by higher volumes and depletion rates in the Eagle Ford Shale and higher depletion rates in the Gulf of America. These increases were partially offset by lower volumes in the Gulf of America.
Exploration Expenses
The Company’s exploration expenses were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
Exploration expenses | |||||||||||||||||||||||
| Dry holes and previously suspended exploration costs | $ | 6.1 | $ | 0.8 | $ | 86.7 | $ | 0.1 | |||||||||||||||
| Geological and geophysical | 17.6 | 20.3 | 30.4 | 24.7 | |||||||||||||||||||
| Other exploration | 6.9 | 8.5 | 30.9 | 25.8 | |||||||||||||||||||
| Undeveloped lease amortization | 2.5 | 2.9 | 7.2 | 6.8 | |||||||||||||||||||
Total exploration expenses, including undeveloped lease amortization | $ | 33.1 | $ | 32.5 | $ | 155.2 | $ | 57.4 | |||||||||||||||
Exploration expenses for the three months ended September 30, 2026 increased by $0.6 million compared to the same period in 2025. Higher dry hole costs related to the Hai Su Vang-4X (Golden Sea Lion) appraisal well (Block 15-2/17) were offset by lower geological and geophysical activity in the Gulf of America.
Exploration expenses for the nine months ended September 30, 2026 increased by $97.8 million compared to the same period in 2025. Higher exploration expenses in the current period were primarily driven by 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.
Selling and General Expenses
Selling and general expenses increased $8.3 million and $17.6 million for the three and nine months ended September 30, 2026, respectively, compared with the same periods in 2025. Increases were primarily due to higher compensation costs, incentive awards and professional fees.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Results of Operations (Continued)
Other
Other expenses increased $23.4 million for the three months ended September 30, 2026 compared with the same period in 2025, primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney and additional abandonment costs in the Gulf of America.
Other expenses increased $40.8 million for the nine months ended September 30, 2026 compared with the same period in 2025 primarily due to environmental monitoring and remediation activities associated with a produced water release from a pipeline in the Tupper Montney, combined with the settlement of a joint venture dispute and additional abandonment costs in the Gulf of America.
Income Taxes
Income taxes for the three and nine months ended September 30, 2026 increased by $42.8 million and $118.3 million, respectively, compared to the same periods in 2025. Higher income tax expenses were primarily due to higher pretax income in the United States and Canada. The tax impact was also affected by exploration expenses incurred in foreign jurisdictions where no income tax benefits are currently available. The Company also recognized an income tax deduction for prior years’ Australia exploration spend.
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 $31.5 million for the three months ended September 30, 2026, an unfavorable variance of $12.9 million compared to the same period in 2025. The unfavorable variance was primarily due to lower foreign exchange gains ($11.3 million) and the non-repeat of prior year derivative gains ($5.7 million), partially offset by a higher income tax benefit ($7.7 million).
The Corporate segment reported a loss of $99.9 million for the nine months ended September 30, 2026, a favorable variance of $22.8 million compared to the same period in 2025. The favorable variance was primarily due to higher foreign exchange gains ($41.5 million) and was partially offset by higher net interest expense associated with the 2034 Notes and a lower income tax benefit ($10.1 million).
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its Amended RCF. The Company’s liquidity requirements, both in the short-term (2026) and long-term (beyond 2026), consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. The Company may, from time to time, redeem, repurchase or otherwise acquire its outstanding notes through open market purchases, tender offers or pursuant to the terms of such securities. The Company believes that the primary sources of liquidity described above will be adequate to fund its liquidity needs over the next 12 months and the foreseeable future.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Cash Flows
The following table presents the Company’s cash flows for the periods presented:
| Nine Months Ended September 30, | |||||||||||
| (Millions of dollars) | 2026 | 2025 | |||||||||
| Net cash provided (required) by: | |||||||||||
| Net cash provided by continuing operations activities | $ | 1,517.6 | $ | 998.2 | |||||||
| Net cash required by investing activities | (1,361.7) | (851.4) | |||||||||
| Net cash required by financing activities | (32.8) | (143.9) | |||||||||
| Effect of exchange rate changes on cash and cash equivalents | — | (0.5) | |||||||||
| Net increase in cash and cash equivalents | $ | 123.1 | $ | 2.4 | |||||||
Cash Provided by Continuing Operations Activities
Net cash provided by continuing operations activities for the nine months ended September 30, 2026 increased by $519.4 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 an increase in revenue from production ($431.1 million), and lower lease operating expenses ($168.6 million), primarily driven by lower workover expenses in the Gulf of America. These favorable impacts were partially offset by a $51.3 million increase in other operating activities, net, primarily related to contract prepayments in Vietnam and foreign exchange rate fluctuations.
Cash Required by Investing Activities
Net cash required by investing activities for the nine months ended September 30, 2026 was $510.3 million higher compared to the same period in 2025. The increase was primarily due to higher property additions and dry hole costs ($506.0 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.
| Nine Months Ended September 30, | |||||||||||
| (Millions of dollars) | 2026 | 2025 | |||||||||
| Property additions and dry hole costs | $ | 1,333.0 | $ | 827.0 | |||||||
| Acquisition of oil and natural gas properties | 28.6 | 24.4 | |||||||||
| Geophysical and other exploration expenses | 57.8 | 46.8 | |||||||||
| Capital expenditure accrual changes and other | 5.4 | (30.6) | |||||||||
| Total capital expenditures | $ | 1,424.8 | $ | 867.6 | |||||||
Total accrual basis capital expenditures are shown below.
| Nine Months Ended September 30, | |||||||||||
| (Millions of dollars) | 2026 | 2025 | |||||||||
| Capital Expenditures | |||||||||||
| Exploration and production | $ | 1,397.6 | $ | 858.4 | |||||||
| Corporate | 27.2 | 9.2 | |||||||||
| Total capital expenditures | $ | 1,424.8 | $ | 867.6 | |||||||
Higher capital expenditures in the nine months ended September 30, 2026 compared to the same period of 2025 were primarily attributable to higher exploratory drilling in Côte d'Ivoire, higher exploratory spending and development drilling in the Gulf of America and in Vietnam. These increases were partially offset by lower development spending in the Eagle Ford Shale and the prior year purchase of the Pioneer FPSO vessel in the Gulf of America.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Development capital expenditures in 2026 primarily related to development drilling and field development activities in the Gulf of America ($447.8 million), the Eagle Ford Shale ($232.2 million), the Tupper Montney and the Kaybob Duvernay ($128.1 million), and in Vietnam ($99.4 million).
Exploration expenditures in 2026 were $471.0 million, primarily comprised of activities in Côte d’Ivoire related to exploration drilling for the Bubale exploration and appraisal program (Blocks CI-709 and CI-103), and the Civette-1X (Block CI-502) and Caracal-1X (Block CI-102) exploration wells. Exploration spending was also driven by activities in the Gulf of America, including federal lease acquisitions and exploration drilling at the Cello #1 and Banjo #1 exploration wells (Mississippi Canyon 385), and in Vietnam, including the Hai Su Vang (Golden Sea Lion) appraisal campaign (Blocks 15-2/17 and 15-1/05) and the Lac Da Trang (White Camel) North (Block 15-1/05) exploration well.
Cash Required by Financing Activities
Net cash required by financing activities for the nine months ended September 30, 2026 decreased by $111.0 million compared to the same period in 2025.
In 2026, net cash required by financing activities was principally from 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 $1.05 per share ($150.5 million), debt issue costs for the upsize and extension of the Amended RCF and 2034 Notes bond issuance ($20.5 million), and distributions to the noncontrolling interest in MP GOM ($21.2 million). These amounts were partially offset by a refinancing transaction whereby new 2034 Notes were issued in the aggregate amount of $500.0 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 $0.975 per share ($139.8 million), and distributions to the noncontrolling interest in MP GOM ($43.2 million), and was partially offset by net borrowings on the senior unsecured guaranteed RCF ($150.0 million).
Liquidity
At September 30, 2026 the Company had approximately $2.5 billion of liquidity consisting of $500.3 million in cash and cash equivalents and $2.0 billion available on its committed senior unsecured guaranteed Amended RCF with a major banking consortium.
The Company’s $2.0 billion Amended RCF expires in January 2031. As of September 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 September 30, 2026 the interest rate in effect on borrowings under the Amended RCF was 6.16%. At September 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 September 30, 2026 cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $105.1 million, the majority of which was held in Canada ($60.1 million), Côte d'Ivoire ($11.9 million), Vietnam ($9.5 million), Mexico ($7.7 million), Brunei ($5.4 million), and the U.K. ($4.4 million). In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.
Working Capital
| (Millions of dollars) | September 30, 2026 | December 31, 2025 | |||||||||
Working capital | |||||||||||
| Total current assets | $ | 1,065.1 | $ | 816.7 | |||||||
| Total current liabilities | 1,122.3 | 1,062.7 | |||||||||
Net working capital liability | $ | (57.2) | $ | (246.0) | |||||||
As of September 30, 2026 net working capital increased by $188.8 million compared to December 31, 2025. The increase was primarily attributable to a higher cash balance at the end of the period ($123.1 million) and higher accounts receivable ($112.5 million), partially offset by higher accounts payable ($50.6 million).
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Financial Condition (Continued)
Higher accounts receivable and accounts payable were primarily due to higher oil and NGL prices, and drilling activities in the Gulf of America, respectively.
Capital Employed
A summary of capital employed at September 30, 2026 and December 31, 2025 follows.
| September 30, 2026 | December 31, 2025 | ||||||||||||||||||||||
| (Millions of dollars) | Amount | % | Amount | % | |||||||||||||||||||
| Capital employed | |||||||||||||||||||||||
| Long-term debt | $ | 1,623.1 | 23.2 | % | $ | 1,382.6 | 21.3 | % | |||||||||||||||
| Murphy shareholders' equity | 5,384.9 | 76.8 | % | 5,118.4 | 78.7 | % | |||||||||||||||||
| Total capital employed | $ | 7,008.0 | 100.0 | % | $ | 6,501.0 | 100.0 | % | |||||||||||||||
At September 30, 2026, long-term debt of $1,623.1 million increased by $240.5 million compared to December 31, 2025 primarily as a result of a refinancing transaction whereby the Company issued $500.0 million of 2034 Notes and used the proceeds to redeem the 2027 Notes and 2028 Notes and pay down amounts drawn on the Amended RCF. The total of the fixed-rate notes had a weighted average maturity of 8.4 years and a weighted average coupon of 6.3%. In addition, during the quarter, the Company commenced a finance lease for a FSO supporting operations at the Lac Da Vang field in Vietnam, resulting in a $75.3 million increase in long-term debt.
Murphy shareholders’ equity increased by $266.5 million in 2026, primarily due to net income ($456.3 million) and ($24.1 million) stock award amortization, partially offset by dividends ($150.5 million) and foreign currency translation ($59.0 million). A summary of transactions in stockholders’ equity accounts is presented in the “Consolidated Statements of Stockholders’ Equity” on page 6 of this Form 10-Q report.
Critical Accounting Estimates
As of September 30, 2026 there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2025.
Accounting Changes and Recent Accounting Pronouncements
See Note B to the Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics
The Company uses other operational performance and income metrics to review operational performance.
Management uses adjusted net income, earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income, adjusted EBITDA and adjusted EBITDAX exclude certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered substitutes for net income (loss) or cash provided by operating activities as determined in accordance with GAAP.
The following table reconciles net income (loss) attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net income (loss) attributable to Murphy (GAAP) ¹ | $ | 171.1 | $ | (3.0) | $ | 456.3 | $ | 92.3 | |||||||||||||||
| Discontinued operations (income) loss | 0.2 | 0.5 | 1.2 | (0.2) | |||||||||||||||||||
| Net income (loss) from continuing operations attributable to Murphy | 171.3 | (2.5) | 457.5 | 92.1 | |||||||||||||||||||
| Adjustments: | |||||||||||||||||||||||
Impairment of assets 1 | — | 92.0 | — | 92.0 | |||||||||||||||||||
| Foreign exchange (gain) loss | (1.5) | (13.4) | (20.1) | 20.9 | |||||||||||||||||||
| Unrealized gain on derivative instruments | — | (2.5) | — | (3.9) | |||||||||||||||||||
| Total adjustments, before taxes | (1.5) | 76.1 | (20.1) | 109.0 | |||||||||||||||||||
| Income tax (benefit) expense related to adjustments | 0.4 | (15.5) | 5.2 | (23.8) | |||||||||||||||||||
| Tax benefits on investments in foreign areas | (11.8) | — | (11.8) | — | |||||||||||||||||||
| Total adjustments, after taxes | (12.9) | 60.6 | (26.7) | 85.2 | |||||||||||||||||||
| Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 158.4 | $ | 58.1 | $ | 430.8 | $ | 177.3 | |||||||||||||||
| Net income (loss) from continuing operations per average diluted share (GAAP) | $ | $ | ( | $ | $ | ||||||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 1.08 | $ | 0.41 | $ | 2.95 | $ | 1.23 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
The following table reconciles net income (loss) attributable to Murphy to EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX attributable to Murphy.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net income (loss) attributable to Murphy (GAAP) ¹ | $ | 171.1 | $ | (3.0) | $ | 456.3 | $ | 92.3 | |||||||||||||||
| Income tax expense | 39.3 | 4.1 | 166.3 | 37.9 | |||||||||||||||||||
| Interest expense, net | 24.2 | 24.7 | 78.1 | 73.3 | |||||||||||||||||||
Depreciation, depletion and amortization expense 1 | 264.1 | 275.0 | 764.9 | 713.2 | |||||||||||||||||||
EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 498.7 | $ | 300.8 | $ | 1,465.6 | $ | 916.7 | |||||||||||||||
Exploration expenses 1 | 33.0 | 32.5 | 155.1 | 57.3 | |||||||||||||||||||
EBITDAX attributable to Murphy (Non-GAAP) 1 | $ | 531.7 | $ | 333.3 | $ | 1,620.7 | $ | 974.0 | |||||||||||||||
EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 498.7 | $ | 300.8 | $ | 1,465.6 | $ | 916.7 | |||||||||||||||
Impairment of assets 1 | — | 92.0 | — | 92.0 | |||||||||||||||||||
| Foreign exchange (gain) loss | (1.5) | (13.4) | (20.1) | 20.9 | |||||||||||||||||||
Accretion of asset retirement obligations 1 | 13.5 | 13.2 | 39.8 | 38.6 | |||||||||||||||||||
| Unrealized gain on derivative instruments | — | (2.5) | — | (3.9) | |||||||||||||||||||
| Discontinued operations (income) loss | 0.2 | 0.5 | 1.2 | (0.2) | |||||||||||||||||||
Adjusted EBITDA attributable to Murphy (Non-GAAP) 1 | $ | 510.9 | $ | 390.6 | $ | 1,486.5 | $ | 1,064.1 | |||||||||||||||
Exploration expenses 1 | 33.0 | 32.5 | 155.1 | 57.3 | |||||||||||||||||||
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 1 | $ | 543.9 | $ | 423.1 | $ | 1,641.6 | $ | 1,121.4 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Other Key Performance Metrics (Continued)
Management uses free cash flow (FCF) and adjusted FCF internally as additional measures of liquidity to evaluate the Company’s ability to internally generate cash, excluding the timing impacts of working capital, and to measure funds available for investing and financing activities. Management also believes this information may be useful to investors and analysts to monitor the Company’s financial health and its performance over time. FCF and adjusted FCF are non-GAAP financial measures and should not be considered a substitute for net cash provided by operating, investing, or financing activities as determined in accordance with GAAP.
The following table reconciles net cash provided by continuing operations activities to FCF and adjusted FCF.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||
| Net cash provided by continuing operations activities (GAAP) | $ | 540.5 | $ | 339.4 | $ | 1,517.6 | $ | 998.2 | |||||||||||||||
| Exclude: increase (decrease) in non-cash working capital | (25.5) | 28.4 | 15.0 | 20.5 | |||||||||||||||||||
Operating cash flow excluding working capital adjustments (Non-GAAP) | 515.0 | 367.8 | 1,532.6 | 1,018.7 | |||||||||||||||||||
Less: property additions and dry hole costs 1 | (466.8) | (149.0) | (1,333.0) | (827.0) | |||||||||||||||||||
| Free cash flow (Non-GAAP) | $ | 48.2 | $ | 218.8 | $ | 199.6 | $ | 191.7 | |||||||||||||||
| Adjustments: | |||||||||||||||||||||||
| Cash dividends paid | (50.2) | (46.4) | (150.5) | (139.8) | |||||||||||||||||||
| Distributions to noncontrolling interest | — | (25.0) | (21.2) | (43.2) | |||||||||||||||||||
| Debt costs | (0.6) | — | (23.0) | — | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | (0.7) | — | (8.5) | (7.7) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | (5.1) | (23.0) | (28.6) | (24.4) | |||||||||||||||||||
| Adjusted free cash flow (Non-GAAP) | $ | (8.4) | $ | 124.4 | $ | (32.2) | $ | (23.4) | |||||||||||||||
1 Property additions for the nine months ended September 30, 2025 include a payment of $125.0 million for the purchase of the Pioneer FPSO in the Gulf of America, including amounts attributable to a noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook
The oil and natural gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the “Results of Operations” section discussing revenues, on page 36, higher average crude oil and natural gas pricing during the third quarter of 2026 compared to the same period in 2025 directly impacted the Company’s product sales revenue.
As of close on November 2, 2026 forward price curves for existing forward contracts for the remainder of 2026 and 2027 are shown in the following table.
| 2026 | 2027 | |||||||||||||
| WTI ($/BBL) | $ | 96.46 | $ | 86.12 | ||||||||||
| NYMEX ($/MMBTU) | 2.86 | 2.91 | ||||||||||||
| AECO (US$ Equivalent/MCF) | 1.35 | 1.41 | ||||||||||||
The regional conflict involving Iran continues to contribute to heightened geopolitical risk and volatility in global energy markets, including disruptions and security risks affecting transit through the Strait of Hormuz. The Company has not experienced any direct physical disruption to its operations as a result of the conflict. However, the conflict may indirectly affect the Company through fluctuations in oil and natural gas prices and demand, increased costs or reduced availability of equipment and services, and broader supply chain pressures. A prolonged or escalating conflict, including further disruptions to critical energy infrastructure or maritime routes, could increase market volatility and adversely affect economic conditions, which could affect the Company’s future operating results, cash flows and financial position.
Changes in tariffs and trade policies may affect the cost and availability of goods and services used in E&P operations or contribute to inflation in the countries in which the Company operates. In July 2026, the Trump Administration implemented tariffs of generally 10% or 12.5% on imports from 60 economies pursuant to Section 301 of the Trade Act of 1974. The Company continues to monitor the actual and potential effects of these tariffs, other trade restrictions and related governmental actions, as well as opportunities to mitigate their impacts. The ultimate effects of these measures on the Company’s supply chain, capital expenditures and operating costs remain uncertain.
The Company cannot predict the impact economic conditions, including inflation, trade policies, tariffs, other trade restrictions and a possible economic recession, may have on future commodity prices or the cost and availability of goods and services used in E&P operations. Similarly, the Company cannot predict the effects of political instability, armed conflict, sanctions, changes in sanctions policy or other governmental actions affecting oil- and natural-gas-producing regions, including Russia and Ukraine, the Middle East and Venezuela. Such developments may affect global oil and natural gas supply, demand and pricing. It is also uncertain how production decisions by OPEC and participating non-OPEC countries, compliance with production targets and changes in participation or production capacity may influence commodity prices and the global supply-demand balance. Lower commodity prices or higher costs, should they occur, would reduce earnings and operating cash flows and could result in material future impairment charges.
For the fourth quarter of 2026, production is expected to average between 174.0 and 182.0 thousand barrels of oil equivalent per day, excluding noncontrolling interest. The Company now also expects full-year 2026 production, excluding noncontrolling interest, to be between 176.0 and 178.0 thousand barrels of oil equivalent per day, compared with its prior guidance of 167.0 to 175.0 thousand barrels of oil equivalent per day. The increased guidance is primarily attributable to accelerated Eagle Ford Shale activity, new well outperformance and lower royalties at Tupper Montney.
The Company expects full-year 2026 capital expenditures, excluding noncontrolling interest, to be between $1,500 million and $1,600 million.
In the Gulf of America, the Chinook #8 (Walker Ridge 425) well commenced production during the quarter. Murphy will also continue progressing 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. Finally, the evaluation of multiple blocks acquired in federal lease sales is ongoing.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Outlook (Continued)
In Côte d’Ivoire, the Company drilled a successful appraisal well at Bubale West-1X (Block CI-103). Going forward, the Bubale appraisal program is expected to include two to four wells over the next 18 to 24 months.
The Company commenced production at Lac Da Vang (Golden Camel), Block 15-1/05 in Vietnam during the quarter, and also drilled a discovery at the Lac Da Trang (White Camel) North-1X (Block 15-1/05) exploration well. At Hai Su Vang (Golden Sea Lion), the Company is evaluating development alternatives and advancing post-appraisal studies, with a final investment decision currently anticipated in late 2027.
In addition to ongoing activities in Côte d’Ivoire and Vietnam, the Company continues to pursue future exploration opportunities internationally. Subsequent to the third quarter, the Company signed agreements with the government of Mauritania for two offshore exploration blocks, and is working to finalize an agreement in Cameroon before year-end.
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 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, our planned exploration and appraisal program and our bond terms, 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 September 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 guaranteed Amended RCF (see Note E).
As of November 2, 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 | 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 ongoing conflict in the Middle East involving 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. SEC and on page 50 of this Form 10-Q report and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Each forward-looking statement contained in this report speaks only as of the date of this report. Except as required by applicable law, Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with prices of crude oil, natural gas and petroleum products, foreign currency exchange rates, and interest rates. As described in Note L, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.
Commodity Price Risk
There were no commodity-based derivative contracts in place as of September 30, 2026.
Foreign Exchange Risk
There were no derivative foreign exchange contracts in place at September 30, 2026.
Interest Rate Risk
The Company’s senior unsecured guaranteed Amended RCF provides for variable interest rate borrowings. As of September 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 September 30, 2026 there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Murphy and its subsidiaries are engaged in a number of legal proceedings (including litigation related to climate change), all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.
ITEM 1A. RISK FACTORS
The Company’s operations in the oil and natural gas business naturally lead to various risks and uncertainties. These risk factors are discussed in “Item 1A. Risk Factors” in the Company’s 2025 Form 10-K filed on February 25, 2026. The Company has not identified any additional risk factors not previously disclosed in its 2025 Form 10-K report.
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ITEM 5. OTHER INFORMATION
Amended and Restated By-Laws
On November 4, 2026, the Board of Directors of Murphy Oil Corporation (the “Company”) approved and adopted amendments to Article II, Section 6 of the Company’s By-Laws (the “Amended By-laws”). The Amended By-laws were effective immediately upon adoption.
The foregoing description of the Amended By-Laws does not purport to be complete and is qualified in its entirety by reference to the text of the Amended By-Laws, which are attached hereto as Exhibit 3.2 and incorporated herein by reference.
Trading Plan Arrangements
During the three months ended September 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 | |||||||
3.1 | Certificate of Incorporation of Murphy Oil Corporation, as amended effective May 11, 2005 (incorporated by reference to Exhibit 3.1 to Form 10-K of Registrant filed on February 28, 2011) | |||||||
*3.2 | By-Laws of Murphy Oil Corporation, as amended effective November 4, 2026 | |||||||
*31.1 | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||
*31.2 | Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||
**32.1 | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||
| 101. INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | |||||||
| 101. SCH | Inline XBRL Taxonomy Extension Schema Document | |||||||
| 101. CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| 101. DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | |||||||
| 101. LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document | |||||||
| 101. PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| MURPHY OIL CORPORATION | ||||||||
| (Registrant) | ||||||||
| By | /s/ PAUL D. VAUGHAN | |||||||
| Paul D. Vaughan | ||||||||
| Vice President and Controller | ||||||||
| (Chief Accounting Officer and Duly Authorized Officer) | ||||||||
November 4, 2026
(Date)
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