Murphy Oil Corp 8-K, filed Nov 5, 2025
Murphy Oil Corp (MUR)
8-K
2025-11-05
For: 2025-11-05
View Original
Added on
April 09, 2026
About this 8-K
Murphy Oil Corp filed this 8-K on November 5, 2025.
Items reported
- Item 2.02: Financial results
- Item 9.01: Financial statements and exhibits
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): November 5, 2025
(Exact name of registrant as specified in its charter)
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
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Securities registered pursuant to Section 12(b) of the Act:
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). 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. ☐
Item 2.02. Results of Operations and Financial Condition
The following information is furnished pursuant to Item 2.02, “Results of Operations and Financial Condition.”
On November 5, 2025 Murphy Oil Corporation issued a news release announcing its financial and operating results for the quarter ended September 30, 2025. The full text of this news release is attached hereto as Exhibit 99.1. The Company also issued a quarterly stockholder update as a supplement to the earnings release, which is furnished hereto as Exhibit 99.2.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, unless specifically identified as such.
Item 9.01. Financial Statements and Exhibits
| (d) | Exhibits | ||||
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 hereunto duly authorized.
MURPHY OIL CORPORATION | ||||||||
| Date: November 5, 2025 | ||||||||
By: | /s/ Paul D. Vaughan | |||||||
| Paul D. Vaughan | ||||||||
Vice President and Controller | ||||||||
Exhibit Index
| Exhibit No. | |||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document) | ||||
EXHIBIT 99.1
NEWS RELEASE
MURPHY OIL CORPORATION ANNOUNCES THIRD QUARTER RESULTS
Delivered Sequential Increase in Production to 200 MBOEPD and 94 MBOPD
Reduced Debt by $50 Million and Paid Dividends of $46 Million
Progressed Lac Da Vang (Golden Camel) Platform Jacket Installation and Pipeline Laying Campaign in Vietnam Ahead of Schedule
HOUSTON, Texas, November 5, 2025 – Murphy Oil Corporation (NYSE: MUR) today announced its financial and operating results for the third quarter ended September 30, 2025. As a supplement to this release, Murphy has also furnished a Quarterly Stockholder Update.
Unless otherwise noted, the financial and operating highlights and metrics discussed in this commentary exclude noncontrolling interest (NCI).†
(Millions of dollars, except volumes and per share amounts) | Three months ended September 30, 2025 | ||||||||||
Net loss from continuing operations attributable to Murphy | $ | (3.0) | |||||||||
Net loss attributable to Murphy per common share - Diluted | $ | (0.02) | |||||||||
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) 1,2 | $ | 58.1 | |||||||||
Adjusted net income from continuing operations per average common share - Diluted (Non-GAAP) 1,2 | $ | 0.41 | |||||||||
Adjusted EBITDA attributable to Murphy (Non-GAAP) 2 | $ | 390.6 | |||||||||
Adjusted EBITDAX attributable to Murphy (Non-GAAP) 2 | $ | 423.1 | |||||||||
| Net cash provided by continuing operations activities | $ | 339.4 | |||||||||
Free cash flow (Non-GAAP) 2 | $ | 218.8 | |||||||||
Oil production, net (BOPD) 3 | 94,067 | ||||||||||
Total production, net (BOEPD) 3 | 200,383 | ||||||||||
Accrued capital expenditures (CAPEX) 4 | $ | 163.9 | |||||||||
Lease operating expense ($/BOE) 5 | $ | 9.39 | |||||||||
1 Adjustments to net loss totaled $76 million (before tax) and were comprised of a $92 million impairment of assets, offset by foreign exchange gains and unrealized gains on derivatives of $16 million. The net tax effect of these adjustments was a tax benefit of $16 million, for a total after-tax adjustment of $61 million.
2 Adjusted net income, adjusted EBITDA, adjusted EBITDAX and free cash flow are non-GAAP financial measures and are not a substitute for measures prepared in accordance with U.S. generally accepted accounting principles (GAAP). Reconciliations and definitions of these measures can be found in the attached schedules.
3 Barrels of oil per day (BOPD) and barrels of oil equivalent per day (BOEPD).
4 Excludes $23 million Eagle Ford Shale acquisition.
5 Lease operating expense per barrel of oil equivalent sold for total oil and gas continuing operations.
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Highlights for the third quarter include:
•Delivered sequential increase in production to 200,000 BOEPD and 94,000 BOPD; production outperformed high-end of guidance on strong new well productivity and no storm downtime in the Gulf of America
•Paid down $50 million of debt under the senior unsecured credit facility and returned $46 million to shareholders through quarterly dividend
•Reaffirmed full year production and CAPEX guidance
Subsequent to the third quarter:
•Completed installation of platform jacket and initiated development drilling at Lac Da Vang (Golden Camel) development project in Vietnam ahead of schedule
“I am pleased with our operational performance across our asset base including Eagle Ford, Tupper Montney, and Gulf of America. I am proud of our team for continuing to innovate and evolve our completions and flowback designs to achieve higher capital efficiency in our onshore operations. We saw great performance from our Gulf of America asset and successfully completed all planned workover activity. Additionally, subsequent to quarter end, we executed major milestones on our Lac Da Vang (Golden Camel) project. We remain focused on core execution as we progress our impactful offshore exploration and appraisal program across three continents in the fourth quarter,” stated Eric M. Hambly, President and Chief Executive Officer.
RETURN OF CAPITAL
In the third quarter of 2025, return of capital totaled $46 million through the quarterly dividend. Through the first three quarters of 2025, Murphy has returned $240 million to shareholders, which includes $100 million of share repurchases and $140 million in dividends.
The company had $550 million remaining under its share repurchase authorization and 142.7 million shares outstanding as of September 30, 2025.
FINANCIAL POSITION
Murphy had approximately $1.6 billion of liquidity on September 30, 2025, comprised of $1.2 billion undrawn under the $1.35 billion senior unsecured credit facility and $426 million of cash and cash equivalents, inclusive of NCI. During the quarter, Murphy paid down $50 million of debt under the senior unsecured credit facility.
As of September 30, 2025, Murphy’s total debt of $1.4 billion was comprised of long-term, fixed-rate notes and $150 million drawn under the senior unsecured credit facility. The fixed-rate notes had a weighted average maturity of 8.6 years and a weighted average coupon of 6.1 percent.
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ONSHORE OPERATIONS SUMMARY
In the third quarter of 2025, the onshore business produced approximately 132 MBOEPD, which included 35 percent liquids.
Onshore | Oil Production (BOPD) | Total Production (BOEPD) | New Wells Online (Operated) | ||||||||||||||
Eagle Ford Shale | 35,000 | 49,000 | 10 | ||||||||||||||
Tupper Montney | 200 | 78,000 | — | ||||||||||||||
Kaybob Duvernay | 3,000 | 5,000 | 4 | ||||||||||||||
OFFSHORE OPERATIONS SUMMARY
Excluding NCI, in the third quarter of 2025, the offshore business produced approximately 68 MBOEPD, which included 88 percent liquids.
Offshore | Oil production (BOPD) | Total Production (BOEPD) | |||||||||||||||
Gulf of America | 50,000 | 62,000 | |||||||||||||||
Canada | 6,000 | 6,000 | |||||||||||||||
Gulf of America – Murphy completed the Khaleesi #2 and Marmalard #3 workovers and returned the wells to production in the third quarter, concluding the planned workover program. During the quarter, Murphy recorded a pretax impairment totaling $115 million ($92 million excluding NCI) on the operated Dalmatian asset due to reserve reductions in the quarter, as certain future projects in the field were less competitive for capital allocation.
Vietnam – Subsequent to the third quarter, Murphy installed the platform jacket and initiated development drilling at the Lac Da Vang (Golden Camel) development project. The project remains on schedule for first oil in the fourth quarter of 2026.
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2025 PRODUCTION AND CAPITAL EXPENDITURE GUIDANCE
The table below illustrates fourth quarter 2025 production guidance by area.
4Q 2025 Guidance | ||||||||||||||||||||||||||
| Producing Asset | Oil (BOPD) | NGLs (BOPD) | Natural Gas (MCFD) | Total (BOEPD) | ||||||||||||||||||||||
| Eagle Ford Shale | 25,000 | 6,100 | 31,200 | 36,300 | ||||||||||||||||||||||
| Gulf of America, excl. NCI | 50,000 | 4,000 | 49,500 | 62,300 | ||||||||||||||||||||||
| Tupper Montney | 200 | — | 403,700 | 67,500 | ||||||||||||||||||||||
| Kaybob Duvernay | 3,600 | 500 | 8,300 | 5,500 | ||||||||||||||||||||||
| Offshore Canada | 8,200 | — | — | 8,200 | ||||||||||||||||||||||
| Other | 200 | — | — | 200 | ||||||||||||||||||||||
Total Net Production, excl. NCI 1 (BOEPD) | 176,000 to 184,000 | |||||||||||||||||||||||||
| Exploration Expense ($ MM) | $80 | |||||||||||||||||||||||||
| Full Year 2025 Guidance | ||||||||||||||||||||||||||
Total Net Production, excl. NCI 2 (BOEPD) | 174,500 to 182,500 | |||||||||||||||||||||||||
Capital Expenditures, excl. NCI 3 ($ MM) | $1,135 to $1,285 | |||||||||||||||||||||||||
| ¹ Excludes noncontrolling interest of MP GOM of 5,400 BOPD of oil, 200 BOPD of NGLs and 1,900 MCFD natural gas | ||||||||||||||||||||||||||
| ² Excludes noncontrolling interest of MP GOM of 5,600 BOPD of oil, 200 BOPD of NGLs and 1,700 MCFD natural gas | ||||||||||||||||||||||||||
| ³ Excludes noncontrolling interest of MP GOM of $40 million | ||||||||||||||||||||||||||
The table below details the 2025 CAPEX plan by quarter.
2025 CAPEX 1 by Quarter ($ MM) | ||||||||||||||||||||
| 1Q 2025A | 2Q 2025A | 3Q 2025A | 4Q 2025E | FY 2025E | ||||||||||||||||
$4032 | $251 | $1643 | $392 | $1,2102,3 | ||||||||||||||||
1 Accrual CAPEX, based on midpoint of guidance range and excluding NCI
2 Includes net acquisition CAPEX of $104 million for the Pioneer FPSO and $1.4 million
for non-operated working interests near the Zephyrus field in the Gulf of America
3 Excludes $23 million Eagle Ford Shale acquisition
The table below details the 2025 onshore well delivery plan by quarter.
| 2025 Onshore Wells Online | |||||||||||||||||||||||||||||
| 1Q 2025A | 2Q 2025A | 3Q 2025A | 4Q 2025E | 2025E Total | |||||||||||||||||||||||||
| Eagle Ford Shale | - | 24 | 10 | - | 34 | ||||||||||||||||||||||||
| Kaybob Duvernay | - | - | 4 | - | 4 | ||||||||||||||||||||||||
| Tupper Montney | 5 | 5 | - | - | 10 | ||||||||||||||||||||||||
| Non-Op Eagle Ford Shale | 1 | 10 | 7 | - | 18 | ||||||||||||||||||||||||
Note: All well counts are shown gross. Eagle Ford Shale non-operated working interest
averages 25 percent.
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CONFERENCE CALL AND WEBCAST SCHEDULED FOR NOVEMBER 6, 2025
Murphy will host a conference call to discuss third quarter 2025 financial and operating results on Thursday, November 6, 2025, at 9:00 a.m. ET. The call can be accessed either via the Internet through the events calendar on the Murphy Oil Corporation Investor Relations website at http://ir.murphyoilcorp.com or via telephone by dialing toll free 1-800-717-1738, reservation number 40758. For additional information, please refer to the Third Quarter 2025 Earnings Presentation and Quarterly Stockholder Update available under the News and Events section of the Investor Relations website.
FINANCIAL DATA
Summary financial data and operating statistics for third quarter 2025, with comparisons to the same period from the previous year, are contained in the attached schedules. Additionally, a schedule indicating the impacts of items affecting comparability of results between periods and a reconciliation of the non-GAAP financial measures of adjusted net income from continuing operations attributable to Murphy, EBITDA, EBITDAX, adjusted EBITDA, adjusted EBITDAX, free cash flow and adjusted free cash flow to the most directly comparable GAAP financial measures for such periods are also included.
ABOUT MURPHY OIL CORPORATION
Murphy Oil Corporation is an independent oil and natural gas company with a multi-basin onshore and offshore portfolio and significant exploration opportunities. The company has more than a century-long history of demonstrating strong execution and innovative, full-cycle development capabilities with a focus on value creation that drives shareholder returns. Murphy’s foresight and financial discipline, along with its culture of adaptability and accountability, will allow the company to continue its outstanding legacy and exceptional reputation. The company’s current operations include extensive inventory located onshore in the Eagle Ford Shale, Tupper Montney and Kaybob Duvernay, as well as offshore in the Gulf of America and Canada. Murphy also strives to create long-term shareholder value through offshore exploration and development in the Gulf of America, Vietnam and Côte d’Ivoire. Additional information can be found on the company’s website at www.murphyoilcorp.com.
FORWARD-LOOKING STATEMENTS
This news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks,
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uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the company’s future operating results or activities and returns or the company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the US 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 “Risk Factors” in our most recent Annual Report on Form 10-K filed with the US Securities and Exchange Commission (SEC) 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 news release. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
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NON-GAAP FINANCIAL MEASURES
This news release contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with US generally accepted accounting principles (GAAP) and should therefore be considered only as supplemental to such GAAP financial measures. Please see the attached schedules for reconciliations of the differences between the non-GAAP financial measures used in this news release and the most directly comparable GAAP financial measures.
† In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this news release, but not the accompanying schedules, exclude the NCI, thereby representing only the amounts attributable to Murphy.
| Investor Contacts: | ||
| InvestorRelations@murphyoilcorp.com | ||
Atif Riaz, 281-675-9358 | ||
Beth Heller, 281-675-9363 | ||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars, except per share amounts) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||
| Revenue from production | $ | 720,966 | $ | 753,169 | $ | 2,076,761 | $ | 2,345,282 | |||||||||||||||
| Sales of purchased natural gas | — | — | — | 3,742 | |||||||||||||||||||
| Total revenue from sales to customers | 720,966 | 753,169 | 2,076,761 | 2,349,024 | |||||||||||||||||||
| Gain (loss) on derivative instruments | 5,722 | (1,344) | 7,071 | (1,344) | |||||||||||||||||||
| Gain on sale of assets and other operating income | 6,297 | 6,506 | 10,434 | 9,834 | |||||||||||||||||||
| Total revenues and other income | 732,985 | 758,331 | 2,094,266 | 2,357,514 | |||||||||||||||||||
| Costs and expenses | |||||||||||||||||||||||
| Lease operating expenses | 184,353 | 222,886 | 604,986 | 716,778 | |||||||||||||||||||
| Severance and ad valorem taxes | 12,288 | 10,503 | 31,766 | 31,006 | |||||||||||||||||||
| Transportation, gathering and processing | 48,146 | 47,438 | 151,067 | 157,461 | |||||||||||||||||||
| Costs of purchased natural gas | — | — | — | 3,147 | |||||||||||||||||||
| Exploration expenses, including undeveloped lease amortization | 32,502 | 31,284 | 57,389 | 118,390 | |||||||||||||||||||
| Selling and general expenses | 30,858 | 24,871 | 98,692 | 78,925 | |||||||||||||||||||
| Depreciation, depletion and amortization | 283,465 | 223,632 | 736,949 | 650,309 | |||||||||||||||||||
| Accretion of asset retirement obligations | 14,676 | 13,241 | 43,153 | 39,068 | |||||||||||||||||||
| Impairment of assets | 115,002 | — | 115,002 | 34,528 | |||||||||||||||||||
| Other operating expense | 5,902 | 5,450 | 13,364 | 10,497 | |||||||||||||||||||
| Total costs and expenses | 727,192 | 579,305 | 1,852,368 | 1,840,109 | |||||||||||||||||||
| Operating income from continuing operations | 5,793 | 179,026 | 241,898 | 517,405 | |||||||||||||||||||
| Other income (loss) | |||||||||||||||||||||||
| Other income (loss) | 15,271 | (3,926) | (14,631) | 33,870 | |||||||||||||||||||
| Interest expense, net | (24,726) | (21,258) | (73,302) | (62,265) | |||||||||||||||||||
| Total other loss | (9,455) | (25,184) | (87,933) | (28,395) | |||||||||||||||||||
| Income (loss) from continuing operations before income taxes | (3,662) | 153,842 | 153,965 | 489,010 | |||||||||||||||||||
| Income tax expense | 4,157 | 2,122 | 37,911 | 64,855 | |||||||||||||||||||
| Income (loss) from continuing operations | (7,819) | 151,720 | 116,054 | 424,155 | |||||||||||||||||||
| Income (loss) from discontinued operations, net of income taxes | (497) | (608) | 172 | (2,123) | |||||||||||||||||||
| Net income (loss) including noncontrolling interest | (8,316) | 151,112 | 116,226 | 422,032 | |||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | (5,343) | 12,018 | 23,883 | 65,197 | |||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY | $ | (2,973) | $ | 139,094 | $ | 92,343 | $ | 356,835 | |||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – BASIC | |||||||||||||||||||||||
| Continuing operations | $ | (0.02) | $ | 0.93 | $ | 0.64 | $ | 2.37 | |||||||||||||||
| Discontinued operations | — | — | — | (0.01) | |||||||||||||||||||
| Net income (loss) | $ | (0.02) | $ | 0.93 | $ | 0.64 | $ | 2.36 | |||||||||||||||
| NET INCOME (LOSS) PER COMMON SHARE – DILUTED | |||||||||||||||||||||||
| Continuing operations | $ | (0.02) | $ | 0.93 | $ | 0.64 | $ | 2.35 | |||||||||||||||
| Discontinued operations | — | — | — | (0.01) | |||||||||||||||||||
| Net income (loss) | $ | (0.02) | $ | 0.93 | $ | 0.64 | $ | 2.34 | |||||||||||||||
| Cash dividends per common share | $ | 0.325 | $ | 0.300 | $ | 0.975 | $ | 0.900 | |||||||||||||||
| Average common shares outstanding (thousands) | |||||||||||||||||||||||
| Basic | 142,731 | 149,384 | 143,245 | 151,401 | |||||||||||||||||||
| Diluted | 142,731 | 150,353 | 143,976 | 152,437 | |||||||||||||||||||
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MURPHY OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Thousands of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||
| Net income (loss) including noncontrolling interest | $ | (8,316) | $ | 151,112 | $ | 116,226 | $ | 422,032 | |||||||||||||||
| Adjustments to reconcile net income to net cash provided by continuing operations activities | |||||||||||||||||||||||
| Depreciation, depletion and amortization | 283,465 | 223,632 | 736,949 | 650,309 | |||||||||||||||||||
| Accretion of asset retirement obligations | 14,676 | 13,241 | 43,153 | 39,068 | |||||||||||||||||||
| Long-term non-cash compensation | 6,498 | 8,237 | 28,514 | 30,060 | |||||||||||||||||||
Deferred income tax (benefit) expense | 2,089 | (8,792) | 23,305 | 45,136 | |||||||||||||||||||
| Amortization of undeveloped leases | 2,998 | 1,929 | 6,907 | 7,707 | |||||||||||||||||||
| Unrealized (gain) loss on derivative instruments | (2,533) | 1,344 | (3,904) | 1,344 | |||||||||||||||||||
| Unsuccessful exploration well costs and previously suspended exploration costs | 859 | 11,268 | 83 | 69,548 | |||||||||||||||||||
(Income) loss from discontinued operations | 497 | 608 | (172) | 2,123 | |||||||||||||||||||
| Impairment of assets | 115,002 | — | 115,002 | 34,528 | |||||||||||||||||||
| Other operating activities, net | (47,426) | (4,301) | (47,428) | (38,260) | |||||||||||||||||||
Net decrease (increase) in non-cash working capital | (28,378) | 30,709 | (20,473) | 31,835 | |||||||||||||||||||
| Net cash provided by continuing operations activities | 339,431 | 428,987 | 998,162 | 1,295,430 | |||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||
| Property additions and dry hole costs | (148,964) | (216,413) | (827,007) | (733,289) | |||||||||||||||||||
| Acquisition of oil and natural gas properties | (23,022) | — | (24,405) | — | |||||||||||||||||||
| Net cash required by investing activities | (171,986) | (216,413) | (851,412) | (733,289) | |||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||
| Borrowings on revolving credit facility | 125,000 | 150,000 | 475,000 | 350,000 | |||||||||||||||||||
| Repayment of revolving credit facility | (175,000) | (150,000) | (325,000) | (350,000) | |||||||||||||||||||
| Retirement of debt | — | — | — | (50,000) | |||||||||||||||||||
| Repurchase of common stock | — | (194,245) | (102,620) | (300,132) | |||||||||||||||||||
| Cash dividends paid | (46,387) | (44,663) | (139,799) | (136,208) | |||||||||||||||||||
| Withholding tax on stock-based incentive awards | (15) | (12) | (7,669) | (25,310) | |||||||||||||||||||
| Distributions to noncontrolling interest | (25,046) | (35,408) | (43,211) | (96,618) | |||||||||||||||||||
| Finance lease obligation payments | (57) | (171) | (543) | (502) | |||||||||||||||||||
| Issue costs of debt facility | — | — | (18) | — | |||||||||||||||||||
Net required by financing activities | (121,505) | (274,499) | (143,860) | (608,770) | |||||||||||||||||||
| Effect of exchange rate changes on cash and cash equivalents | 389 | (471) | (499) | 778 | |||||||||||||||||||
Net increase (decrease) in cash and cash equivalents | 46,329 | (62,396) | 2,391 | (45,851) | |||||||||||||||||||
| Cash and cash equivalents at beginning of period | 379,631 | 333,619 | 423,569 | 317,074 | |||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 425,960 | $ | 271,223 | $ | 425,960 | $ | 271,223 | |||||||||||||||
9
MURPHY OIL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
| (Thousands of dollars) | September 30, 2025 | December 31, 2024 1 | |||||||||
| ASSETS | |||||||||||
| Cash and cash equivalents | $ | 425,960 | $ | 423,569 | |||||||
Other current assets | 381,520 | 361,710 | |||||||||
Property, plant and equipment, net | 8,085,731 | 8,054,653 | |||||||||
Operating lease assets, net | 781,291 | 777,536 | |||||||||
Other long-term assets | 58,260 | 50,011 | |||||||||
| Total assets | $ | 9,732,762 | $ | 9,667,479 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current maturities of long-term debt, finance lease | $ | 918 | $ | 871 | |||||||
| Accounts payable | 429,658 | 472,165 | |||||||||
| Operating lease liabilities | 210,769 | 253,208 | |||||||||
Other current liabilities | 216,401 | 216,570 | |||||||||
| Long-term debt, including finance lease obligation | 1,425,235 | 1,274,502 | |||||||||
| Asset retirement obligations | 1,001,919 | 960,804 | |||||||||
| Non-current operating lease liabilities | 582,082 | 537,381 | |||||||||
Other long-term liabilities | 616,128 | 610,135 | |||||||||
| Total liabilities | $ | 4,483,110 | $ | 4,325,636 | |||||||
| Murphy Shareholders' Equity | 5,121,387 | 5,194,250 | |||||||||
| Noncontrolling interest | 128,265 | 147,593 | |||||||||
| Total liabilities and equity | $ | 9,732,762 | $ | 9,667,479 | |||||||
1 Reclassified to conform to current presentation.
10
MURPHY OIL CORPORATION
SCHEDULE OF ADJUSTED NET INCOME (LOSS) (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Millions of dollars, except per share amounts) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
Net income (loss) attributable to Murphy (GAAP) 1 | $ | (3.0) | $ | 139.1 | $ | 92.3 | $ | 356.8 | |||||||||||||||
| Discontinued operations (income) loss | 0.5 | 0.6 | (0.2) | 2.1 | |||||||||||||||||||
Net income (loss) from continuing operations attributable to Murphy | (2.5) | 139.7 | 92.1 | 358.9 | |||||||||||||||||||
| Adjustments: | |||||||||||||||||||||||
Impairment of assets 1 | 92.0 | — | 92.0 | 34.5 | |||||||||||||||||||
| Foreign exchange (gain) loss | (13.4) | 5.4 | 20.9 | (10.6) | |||||||||||||||||||
| Unrealized (gain) loss on derivative instruments | (2.5) | 1.3 | (3.9) | 1.3 | |||||||||||||||||||
| Write-off of previously suspended exploration well | — | — | — | 26.1 | |||||||||||||||||||
| Total adjustments, before taxes | 76.1 | 6.7 | 109.0 | 51.3 | |||||||||||||||||||
Income tax benefit related to adjustments | (15.5) | (1.7) | (23.8) | (10.5) | |||||||||||||||||||
| Tax benefits on investments in foreign areas | — | (34.0) | — | (34.0) | |||||||||||||||||||
| Total adjustments, after taxes | 60.6 | (29.0) | 85.2 | 6.8 | |||||||||||||||||||
Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) | $ | 58.1 | $ | 110.7 | $ | 177.3 | $ | 365.7 | |||||||||||||||
| Adjusted net income from continuing operations per average diluted share (Non-GAAP) | $ | 0.41 | $ | 0.74 | $ | 1.23 | $ | 2.40 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
Non-GAAP Financial Measures
Presented above is a reconciliation of net income (loss) to adjusted net income from continuing operations attributable to Murphy. Adjusted net income excludes certain items that management believes affect the comparability of results between periods. Management believes this is important information to provide because it is used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income is a non-GAAP financial measure and should not be considered a substitute for net income (loss) as determined in accordance with GAAP.
The pretax and income tax impacts for adjustments in the above table are shown below by area of operation and geographical location and corporate, as applicable, and exclude the share attributable to noncontrolling interests.
| Three Months Ended September 30, 2025 | Nine Months Ended September 30, 2025 | ||||||||||||||||||||||||||||||||||
| (Millions of dollars) | Pretax | Tax | Net | Pretax | Tax | Net | |||||||||||||||||||||||||||||
Exploration & Production: | |||||||||||||||||||||||||||||||||||
| United States | $ | 92.0 | $ | (19.4) | $ | 72.6 | $ | 92.0 | $ | (19.4) | $ | 72.6 | |||||||||||||||||||||||
| Corporate | (15.9) | 3.9 | (12.0) | 17.0 | (4.4) | 12.6 | |||||||||||||||||||||||||||||
| Total adjustments | $ | 76.1 | $ | (15.5) | $ | 60.6 | $ | 109.0 | $ | (23.8) | $ | 85.2 | |||||||||||||||||||||||
11
MURPHY OIL CORPORATION
SCHEDULE OF EBITDA, ADJUSTED EBITDA, EBITDAX AND ADJUSTED EBITDAX (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
Net income (loss) attributable to Murphy (GAAP) 1 | $ | (3.0) | $ | 139.1 | $ | 92.3 | $ | 356.8 | |||||||||||||||
| Income tax expense | 4.1 | 2.2 | 37.9 | 64.9 | |||||||||||||||||||
| Interest expense, net | 24.7 | 21.3 | 73.3 | 62.3 | |||||||||||||||||||
Depreciation, depletion and amortization expense 1 | 275.0 | 215.7 | 713.2 | 625.8 | |||||||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 300.8 | $ | 378.3 | $ | 916.7 | $ | 1,109.8 | |||||||||||||||
Exploration expenses 1 | 32.5 | 31.3 | 57.3 | 118.4 | |||||||||||||||||||
| EBITDAX attributable to Murphy (Non-GAAP) | $ | 333.3 | $ | 409.6 | $ | 974.0 | $ | 1,228.2 | |||||||||||||||
| EBITDA attributable to Murphy (Non-GAAP) | $ | 300.8 | $ | 378.3 | $ | 916.7 | $ | 1,109.8 | |||||||||||||||
Impairment of asset 1 | 92.0 | — | 92.0 | 34.5 | |||||||||||||||||||
| Foreign exchange (gain) loss | (13.4) | 5.4 | 20.9 | (10.6) | |||||||||||||||||||
Accretion of asset retirement obligations 1 | 13.2 | 11.7 | 38.6 | 34.9 | |||||||||||||||||||
| Unrealized (gain) loss on derivative instruments | (2.5) | 1.3 | (3.9) | 1.3 | |||||||||||||||||||
| Write-off of previously suspended exploration well | — | — | — | 26.1 | |||||||||||||||||||
| Discontinued operations (income) loss | 0.5 | 0.6 | (0.2) | 2.1 | |||||||||||||||||||
| Adjusted EBITDA attributable to Murphy (Non-GAAP) | $ | 390.6 | $ | 397.3 | $ | 1,064.1 | $ | 1,198.1 | |||||||||||||||
Other exploration expenses 2 | 32.5 | 31.3 | 57.3 | 92.3 | |||||||||||||||||||
Adjusted EBITDAX attributable to Murphy (Non-GAAP) | $ | 423.1 | $ | 428.6 | $ | 1,121.4 | $ | 1,290.4 | |||||||||||||||
1 Excludes amounts attributable to a noncontrolling interest in MP GOM.
2 Other exploration expenses consist of exploration expenses as reported in the consolidated statement of operations excluding amounts relating to the write-off of previously suspended exploration well included in Adjusted EBITDA calculation above.
Non-GAAP Financial Measures
Presented above is a reconciliation of net income (loss) to earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted EBITDA, earnings before interest, taxes, depreciation and amortization, and exploration expenses (EBITDAX) and adjusted EBITDAX. Management believes EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are important information to provide because they are used by management to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted EBITDAX excludes certain items that management believes affect the comparability of results between periods. Management also believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. EBITDA, adjusted EBITDA, EBITDAX and adjusted EBITDAX are non-GAAP financial measures and should not be considered a substitute for net income (loss) or Cash provided by operating activities as determined in accordance with GAAP.
12
MURPHY OIL CORPORATION
SCHEDULE OF FREE CASH FLOW AND ADJUSTED FREE CASH FLOW (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Net cash provided by continuing operations activities (GAAP) | $ | 339.4 | $ | 429.0 | $ | 998.2 | $ | 1,295.4 | |||||||||||||||
Exclude: (decrease) increase in non-cash working capital | 28.4 | (30.7) | 20.5 | (31.8) | |||||||||||||||||||
| Operating cash flow excluding working capital adjustments | 367.8 | 398.3 | 1,018.7 | 1,263.6 | |||||||||||||||||||
Less: property additions and dry hole costs 1 | (149.0) | (216.4) | (827.0) | (733.3) | |||||||||||||||||||
| Free cash flow (Non-GAAP) | $ | 218.8 | $ | 181.9 | $ | 191.7 | $ | 530.3 | |||||||||||||||
Less: cash dividends paid | (46.4) | (44.7) | (139.8) | (136.2) | |||||||||||||||||||
Less: distributions to noncontrolling interest | (25.0) | (35.4) | (43.2) | (96.6) | |||||||||||||||||||
| Less: withholding tax on stock-based incentive awards | — | — | (7.7) | (25.3) | |||||||||||||||||||
Less: acquisition of oil and natural gas properties | (23.0) | — | (24.4) | — | |||||||||||||||||||
| Adjusted free cash flow (Non-GAAP) | $ | 124.4 | $ | 101.8 | $ | (23.4) | $ | 272.2 | |||||||||||||||
1 Property additions for the nine months ended September 30, 2025, includes a payment of $125.0 million for the purchase of a floating production, storage, and offloading vessel in U.S. Offshore, including amounts attributable to a noncontrolling interest in MP GOM.
Non-GAAP Financial Measures
Presented above is a reconciliation of net cash provided by continuing operations activities to free cash flow (FCF) and adjusted FCF. Management believes FCF and adjusted FCF are important information to provide because they are additional measures of liquidity and are used by management 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. Adjusted FCF excludes certain items that management believes affect the comparability of results between periods. 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.
13
MURPHY OIL CORPORATION
FUNCTIONAL RESULTS OF OPERATIONS (unaudited)
| Three Months Ended September 30, 2025 | Three Months Ended September 30, 2024 | ||||||||||||||||||||||
| (Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
United States 1 | $ | 613.7 | $ | 28.9 | $ | 597.0 | $ | 138.8 | |||||||||||||||
| Canada | 108.0 | (6.1) | 157.9 | 24.2 | |||||||||||||||||||
| Other | 0.1 | (12.0) | (0.8) | 22.4 | |||||||||||||||||||
| Total exploration and production | 721.8 | 10.8 | 754.1 | 185.4 | |||||||||||||||||||
| Corporate | 11.2 | (18.6) | 4.2 | (33.7) | |||||||||||||||||||
| Income from continuing operations | 733.0 | (7.8) | 758.3 | 151.7 | |||||||||||||||||||
| Discontinued operations, net of tax | — | (0.5) | — | (0.6) | |||||||||||||||||||
Net income (loss) including noncontrolling interest | $ | 733.0 | $ | (8.3) | $ | 758.3 | $ | 151.1 | |||||||||||||||
Less: Net income (loss) attributable to noncontrolling interest | (5.3) | 12.0 | |||||||||||||||||||||
Net income (loss) attributable to Murphy | $ | (3.0) | $ | 139.1 | |||||||||||||||||||
| Nine Months Ended September 30, 2025 | Nine Months Ended September 30, 2024 | ||||||||||||||||||||||
| (Millions of dollars) | Revenues | Income (Loss) | Revenues | Income (Loss) | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
| United States ¹ | $ | 1,676.7 | $ | 223.3 | $ | 1,936.1 | $ | 459.0 | |||||||||||||||
| Canada | 402.0 | 45.8 | 413.8 | 52.5 | |||||||||||||||||||
| Other | 3.0 | (30.4) | 3.4 | 1.5 | |||||||||||||||||||
| Total exploration and production | 2,081.7 | 238.7 | 2,353.3 | 513.0 | |||||||||||||||||||
| Corporate | 12.6 | (122.7) | 4.2 | (88.9) | |||||||||||||||||||
| Income from continuing operations | 2,094.3 | 116.0 | 2,357.5 | 424.1 | |||||||||||||||||||
| Discontinued operations, net of tax | — | 0.2 | — | (2.1) | |||||||||||||||||||
| Net income including noncontrolling interest | $ | 2,094.3 | $ | 116.2 | $ | 2,357.5 | $ | 422.0 | |||||||||||||||
| Less: Net income attributable to noncontrolling interest | 23.9 | 65.2 | |||||||||||||||||||||
| Net income attributable to Murphy | $ | 92.3 | $ | 356.8 | |||||||||||||||||||
1 Includes results attributable to a noncontrolling interest in MP GOM.
14
MURPHY OIL CORPORATION
PRODUCTION-RELATED EXPENSES (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Dollars per barrel of oil equivalents sold) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
United States – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 7.04 | $ | 11.03 | $ | 8.75 | $ | 13.00 | |||||||||||||||
Severance and ad valorem taxes | 2.44 | 3.30 | 2.74 | 3.53 | |||||||||||||||||||
Depreciation, depletion and amortization expense | 30.30 | 29.60 | 29.95 | 29.25 | |||||||||||||||||||
United States – Offshore 1 | |||||||||||||||||||||||
Lease operating expense | $ | 16.79 | $ | 20.54 | $ | 19.64 | $ | 21.52 | |||||||||||||||
| Severance and ad valorem taxes | 0.12 | 0.06 | 0.11 | 0.06 | |||||||||||||||||||
Depreciation, depletion and amortization expense | 16.06 | 13.78 | 16.16 | 13.55 | |||||||||||||||||||
Canada – Onshore | |||||||||||||||||||||||
Lease operating expense | $ | 3.94 | $ | 4.96 | $ | 4.73 | $ | 5.28 | |||||||||||||||
Severance and ad valorem taxes | 0.06 | 0.05 | 0.06 | 0.05 | |||||||||||||||||||
Depreciation, depletion and amortization expense | 4.38 | 4.87 | 4.32 | 4.87 | |||||||||||||||||||
Canada – Offshore | |||||||||||||||||||||||
| Lease operating expense | $ | 24.96 | $ | 18.51 | $ | 19.05 | $ | 21.67 | |||||||||||||||
Depreciation, depletion and amortization expense | 11.53 | 8.27 | 10.03 | 9.58 | |||||||||||||||||||
Total E&P continuing operations 1 | |||||||||||||||||||||||
| Lease operating expense | $ | 9.61 | $ | 12.60 | $ | 11.64 | $ | 14.05 | |||||||||||||||
Severance and ad valorem taxes | 0.64 | 0.59 | 0.61 | 0.61 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 14.67 | 12.56 | 14.06 | 12.61 | |||||||||||||||||||
| Total oil and gas continuing operations – excluding noncontrolling interest | |||||||||||||||||||||||
Lease operating expense 3 | $ | 9.39 | $ | 11.99 | $ | 11.46 | $ | 13.75 | |||||||||||||||
Severance and ad valorem taxes | 0.66 | 0.61 | 0.63 | 0.63 | |||||||||||||||||||
Depreciation, depletion and amortization expense 2 | 14.71 | 12.54 | 14.08 | 12.61 | |||||||||||||||||||
1 Includes amounts attributable to a noncontrolling interest in MP GOM.
2 Excludes expenses attributable to the Corporate segment.
3 Lease operating expense per barrel of oil equivalent sold for total oil and gas continuing operations, excluding NCI and workover costs, was $7.69 and $9.70 for the three months ended September 30, 2025 and 2024, respectively and $8.83 and $10.28 for the nine months ended September 30, 2025 and 2024, respectively.
15
MURPHY OIL CORPORATION
CAPITAL EXPENDITURES (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
(Millions of dollars) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Exploration and production | |||||||||||||||||||||||
United States 1 | $ | 113.8 | $ | 160.8 | $ | 614.3 | $ | 575.1 | |||||||||||||||
| Canada | 26.2 | 13.5 | 127.3 | 123.0 | |||||||||||||||||||
| Other | 47.0 | 29.6 | 116.8 | 62.1 | |||||||||||||||||||
| Total | 187.0 | 203.9 | 858.4 | 760.2 | |||||||||||||||||||
| Corporate | 2.2 | 8.0 | 9.2 | 16.4 | |||||||||||||||||||
Total capital expenditures - continuing operations 1 | 189.2 | 211.9 | 867.6 | 776.6 | |||||||||||||||||||
Less: capital expenditures attributable to noncontrolling interest | 2.3 | 0.7 | 27.0 | 9.6 | |||||||||||||||||||
Total capital expenditures - continuing operations attributable to Murphy 2 | $ | 186.9 | $ | 211.2 | $ | 840.6 | $ | 767.0 | |||||||||||||||
Charged to exploration expenses 3 | |||||||||||||||||||||||
United States 1 | 20.7 | 22.1 | 28.0 | 85.9 | |||||||||||||||||||
Canada | 0.2 | 0.2 | 0.3 | 0.4 | |||||||||||||||||||
Other | 8.7 | 7.0 | 22.3 | 24.4 | |||||||||||||||||||
Total charged to exploration expenses - continuing operations 1,3 | 29.6 | 29.3 | 50.6 | 110.7 | |||||||||||||||||||
Less: charged to exploration expenses attributable to noncontrolling interest | — | — | 0.1 | — | |||||||||||||||||||
Total charged to exploration expenses - continuing operations attributable to Murphy 4 | 29.6 | 29.3 | 50.5 | 110.7 | |||||||||||||||||||
| Total capitalized - continuing operations attributable to Murphy | $ | 157.3 | $ | 181.9 | $ | 790.1 | $ | 656.3 | |||||||||||||||
1 Includes amounts attributable to a noncontrolling interest in MP GOM.
2 For the three months ended September 30, 2025, total capital expenditures attributable to Murphy, excluding acquisition-related costs of $23.0 million (2024:nil), is $163.9 million (2024: $211.2 million). For the nine months ended September 30, 2025, total capital expenditures attributable to Murphy, excluding acquisition-related costs of $128.6 million, primarily related to the purchase of a floating production, storage, and offloading vessel in U.S. Offshore (2024: nil), is $712.0 million (2024: $767.0 million).
3 For the three-month and nine-month periods ended September 30, 2025, total charged to exploration expense attributable to Murphy, excludes amortization of undeveloped leases of $2.9 million (2024: $1.9 million) and $6.8 million (2024 $7.7 million), respectively.
4 For the three months ended September 30, 2025 and 2024, no amounts were expensed for previously suspended exploration costs. For the nine months ended September 30, 2025, total charged to exploration expense attributable to Murphy, excluding previously suspended exploration costs of nil (2024: $26.1 million), is $50.5 million (2024: $84.6 million).
16
MURPHY OIL CORPORATION
PRODUCTION SUMMARY (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Net crude oil and condensate | |||||||||||||||||||||||
United States - Onshore | 34,703 | 23,320 | 26,797 | 21,199 | |||||||||||||||||||
United States - Offshore 1 | 56,071 | 59,282 | 56,835 | 64,042 | |||||||||||||||||||
Canada - Onshore | 3,495 | 3,425 | 2,799 | 2,888 | |||||||||||||||||||
Canada - Offshore | 5,518 | 7,880 | 6,658 | 7,219 | |||||||||||||||||||
| Other | 278 | 171 | 276 | 221 | |||||||||||||||||||
Total net crude oil and condensate | 100,065 | 94,078 | 93,365 | 95,569 | |||||||||||||||||||
| Net natural gas liquids | |||||||||||||||||||||||
United States - Onshore | 8,042 | 4,640 | 5,905 | 4,312 | |||||||||||||||||||
United States - Offshore 1 | 4,500 | 4,739 | 4,344 | 4,644 | |||||||||||||||||||
Canada - Onshore | 442 | 768 | 491 | 572 | |||||||||||||||||||
Total net natural gas liquids | 12,984 | 10,147 | 10,740 | 9,528 | |||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | |||||||||||||||||||||||
United States - Onshore | 39,411 | 26,223 | 32,711 | 24,556 | |||||||||||||||||||
United States - Offshore 1 | 50,477 | 58,747 | 51,528 | 56,565 | |||||||||||||||||||
Canada - Onshore | 473,431 | 437,316 | 425,342 | 400,012 | |||||||||||||||||||
Total net natural gas | 563,319 | 522,286 | 509,581 | 481,133 | |||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 206,936 | 191,273 | 189,035 | 185,286 | |||||||||||||||||||
| Noncontrolling interest | |||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (5,998) | (6,188) | (5,950) | (6,467) | |||||||||||||||||||
| Net natural gas liquids – barrels per day | (228) | (193) | (214) | (207) | |||||||||||||||||||
Net natural gas – thousands of cubic feet per day | (1,963) | (1,947) | (1,715) | (2,008) | |||||||||||||||||||
Total noncontrolling interest 2,3 | (6,553) | (6,706) | (6,450) | (7,009) | |||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 200,383 | 184,567 | 182,585 | 178,277 | |||||||||||||||||||
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.
17
MURPHY OIL CORPORATION
SALES SUMMARY (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (Barrels per day unless otherwise noted) | 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||
| Net crude oil and condensate | |||||||||||||||||||||||
United States - Onshore | 34,703 | 23,320 | 26,797 | 21,199 | |||||||||||||||||||
United States - Offshore 1 | 57,903 | 57,467 | 56,849 | 64,317 | |||||||||||||||||||
Canada - Onshore | 3,495 | 3,425 | 2,799 | 2,888 | |||||||||||||||||||
Canada - Offshore | 5,513 | 10,892 | 8,114 | 7,857 | |||||||||||||||||||
| Other | — | — | 152 | 159 | |||||||||||||||||||
Total net crude oil and condensate | 101,614 | 95,104 | 94,711 | 96,420 | |||||||||||||||||||
| Net natural gas liquids | |||||||||||||||||||||||
United States - Onshore | 8,042 | 4,640 | 5,905 | 4,312 | |||||||||||||||||||
United States - Offshore 1 | 4,500 | 4,739 | 4,344 | 4,644 | |||||||||||||||||||
Canada - Onshore | 442 | 768 | 491 | 572 | |||||||||||||||||||
Total net natural gas liquids | 12,984 | 10,147 | 10,740 | 9,528 | |||||||||||||||||||
| Net natural gas – thousands of cubic feet per day | |||||||||||||||||||||||
United States - Onshore | 39,411 | 26,223 | 32,711 | 24,556 | |||||||||||||||||||
United States - Offshore 1 | 50,477 | 58,747 | 51,528 | 56,565 | |||||||||||||||||||
Canada - Onshore | 473,431 | 437,316 | 425,342 | 400,012 | |||||||||||||||||||
Total net natural gas | 563,319 | 522,286 | 509,581 | 481,133 | |||||||||||||||||||
Total net hydrocarbons - including NCI 2,3 | 208,484 | 192,299 | 190,381 | 186,137 | |||||||||||||||||||
| Noncontrolling interest | |||||||||||||||||||||||
| Net crude oil and condensate – barrels per day | (6,273) | (5,920) | (5,954) | (6,503) | |||||||||||||||||||
| Net natural gas liquids – barrels per day | (228) | (193) | (214) | (207) | |||||||||||||||||||
Net natural gas – thousands of cubic feet per day | (1,963) | (1,947) | (1,715) | (2,008) | |||||||||||||||||||
Total noncontrolling interest 2,3 | (6,828) | (6,438) | (6,454) | (7,045) | |||||||||||||||||||
Total net hydrocarbons - excluding NCI 2,3 | 201,656 | 185,861 | 183,927 | 179,092 | |||||||||||||||||||
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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MURPHY OIL CORPORATION
WEIGHTED AVERAGE PRICE SUMMARY (unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Crude oil and condensate – dollars per barrel | |||||||||||||||||||||||
United States - Onshore | $ | 65.48 | $ | 75.49 | $ | 66.24 | $ | 77.55 | |||||||||||||||
United States - Offshore 1 | 67.00 | 75.65 | 67.81 | 78.42 | |||||||||||||||||||
Canada - Onshore 2 | 56.33 | 66.18 | 59.46 | 68.62 | |||||||||||||||||||
Canada - Offshore 2 | 69.42 | 80.06 | 70.17 | 82.83 | |||||||||||||||||||
Other 2 | — | — | 72.97 | 78.20 | |||||||||||||||||||
| Natural gas liquids – dollars per barrel | |||||||||||||||||||||||
| United States - Onshore | 18.57 | 19.05 | 19.92 | 19.71 | |||||||||||||||||||
United States - Offshore 1 | 20.18 | 22.50 | 21.85 | 23.20 | |||||||||||||||||||
Canada - Onshore 2 | 26.88 | 34.00 | 32.54 | 34.64 | |||||||||||||||||||
| Natural gas – dollars per thousand cubic feet | |||||||||||||||||||||||
| United States - Onshore | 2.64 | 1.77 | 2.87 | 1.77 | |||||||||||||||||||
United States - Offshore 1 | 3.39 | 2.28 | 3.73 | 2.30 | |||||||||||||||||||
Canada - Onshore 2 | 1.22 | 1.34 | 1.68 | 1.56 | |||||||||||||||||||
1 Prices include the effect of noncontrolling interest in MP GOM.
2 U.S. dollar equivalent.
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MURPHY OIL CORPORATION
FIXED PRICE FORWARD SALES AND COMMODITY HEDGE POSITIONS
AS OF NOVEMBER 3, 2025 (unaudited)
| Volumes (MMCF/d) | Price/MCF | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type 1 | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 40 | C$2.75 | 10/1/2025 | 12/31/2025 | ||||||||||||||||||||||||||||||||
| Canada | Natural Gas | Fixed price forward sales | 50 | C$3.03 | 1/1/2026 | 12/31/2026 | ||||||||||||||||||||||||||||||||
1 Fixed price forward sale contracts listed above are accounted for as normal sales and purchases for accounting purposes.
Volumes (MMCF/d) | Price/MCF | Remaining Period | ||||||||||||||||||||||||||||||||||||
| Area | Commodity | Type | Start Date | End Date | ||||||||||||||||||||||||||||||||||
| United States | Natural Gas | Fixed price derivative swap | 60 | US$3.74 | 10/1/2025 | 12/31/2025 | ||||||||||||||||||||||||||||||||
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Quarterly Stockholder Update by Murphy Oil Corporation
HOUSTON, Texas, November 5, 2025
Murphy Oil Corporation Stockholders,
This letter serves as a supplement to our earnings release for the third quarter of 2025. Please see the information regarding forward-looking statements and non-GAAP financial information1 included at the end of this letter. Unless otherwise noted, the financial and operating highlights and metrics discussed in this letter exclude noncontrolling interest (NCI).2
THIRD QUARTER 2025 SUMMARY
Murphy delivered exceptional operational performance in the third quarter, exceeding the high-end of our quarterly production guidance for the second consecutive quarter. We achieved 200.4 thousand barrels of oil equivalent per day (MBOEPD) compared to our guidance range of 185 to 193 MBOEPD. Notably, oil production of 94.1 thousand barrels of oil per day (MBOPD) also exceeded guidance. As a result of our ongoing focus on execution and cost management, operating expenses improved further in the third quarter to $9.39 per BOE, which is $2.41 per BOE lower than in the second quarter.
Realized oil prices were $66.18 per barrel in the third quarter, which is $1.87 per barrel higher than in the second quarter. In addition, realized natural gas prices were $1.50 per thousand cubic feet (MCF) in the third quarter, which is $0.38 per MCF or 20 percent lower than in the second quarter. This reduction, driven by exceptionally weak AECO prices through the 2025 shoulder season, is particularly significant as natural gas comprises 47 percent of our production mix in the quarter. We recorded net loss of $3.0 million, or $0.02 net loss per diluted share, and adjusted net income1 of $58.1 million, or $0.41 per diluted share for the third quarter. This compares to second quarter net income of $22.3 million, or $0.16 per diluted share, and adjusted net income1 of $38.5 million, or $0.27 per diluted share. Also in the third quarter, earnings before interest, taxes, depreciation and amortization (EBITDA)1 was $300.8 million, adjusted EBITDA1 was $390.6 million, cash flow from operations was $339.4 million, and we generated adjusted free cash flow1 of $124.4 million.
I will note that our unadjusted net loss for the quarter was primarily attributable to a non-cash pre-tax impairment of $92 million (excluding NCI) related to the Dalmatian
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field in the Gulf of America. This impairment resulted from a reduction in reserves following our strategic decision to cease investment in future Dalmatian wells that were unfavorably impacted by high third-party operating cost allocations. We will reallocate capital toward projects with higher value potential.
As we close out the year, we remain focused on the parts of our business that we can control: strong execution, production rates and costs, a solid balance sheet and liquidity, and a first-rate exploration program followed by best-in-class oil field development skills.
OPERATIONAL UPDATE
During the third quarter of 2025, we continued to see strong execution and performance across our business. We delivered a new well program in the Eagle Ford Shale and Kaybob Duvernay, wrapped up the Gulf of America workover program, and progressed the Lac Da Vang (Golden Camel) field development and our international exploration program in line with guidance.
At our Eagle Ford Shale asset, we brought online 10 operated wells in Catarina and 7 gross non-operated wells. All new operated pads in Catarina surpassed initial production expectations, with three of our wells ranking as the all-time top three wells in Dimmit County based on three-month cumulative oil production per 1,000 feet. The positive performance from our Karnes wells in the second quarter, and now Catarina wells in third quarter, demonstrates the success of our improved completions design and operating practices. Additionally, we continue to realize capital efficiency gains in our drilling and completions. We have reduced drilling cost per foot by 8% and completion cost per lateral foot by 9% in year-to-date 2025 compared to 2024. With the savings we've captured this year, we are able to drill six additional Eagle Ford Shale wells in the fourth quarter, which will come online in 2026. We remain committed to targeting efficiencies as we develop our robust remaining tier-one well location inventory.
At our Tupper Montney asset, we continued to see strong well performance from the new well program completed in the second quarter, leading to record quarterly gross production of 77.8 MBOEPD in the third quarter. This outperformance enabled us to keep the Tupper West plant full for five months, a new record for the company.
In Kaybob Duvernay, we brought online four new wells, delivering third quarter production of 5.0 MBOEPD and setting the record for the longest wells in Murphy history (16,290 feet average completed lateral length).
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In the Gulf of America, we completed the Khaleesi #2 workover in July and the Marmalard #3 workover in August as previously guided. With the workover program behind us, we saw strong performance in the quarter with total production from our Gulf of America assets of 62.4 MBOEPD, which was higher than guidance by 5.4 MBOEPD. This was helped by no storm downtime and exceptional uptime at our key operated facilities with Delta House at 100 percent, King's Quay at 99.9 percent, and Pioneer at 99.8 percent in the quarter. Additionally in the third quarter, we continued to progress preparations for Chinook #8, a high impact well expected to come online in the second half of 2026 with an expected gross initial production rate of 15 MBOEPD.
In Vietnam, we continue to execute our Lac Da Vang (Golden Camel) field development. Early in the fourth quarter, we installed the platform jacket for the LDV-A platform and spud our first development well ahead of schedule. The fabrication of the LDV-A platform’s topsides, the Floating Storage and Offloading (FSO) vessel’s hull and turret, pipelines, and flexible risers are progressing on schedule to allow us to achieve first oil in the fourth quarter of 2026. I am proud of our team's ability to execute large scale development projects efficiently and safely across continents.
PRODUCTION
As noted, third quarter production of 200.4 MBOEPD was 10.7 MBOEPD or 6 percent higher than the second quarter. This outperformance was primarily driven by higher than expected initial production rates from new Catarina wells, continued strong well performance from Tupper Montney and Karnes wells brought online in the second quarter, and outperformance in the Gulf of America helped by lower-than-expected storm downtime. We now expect full year 2025 production to be closer to the high end of our full year guidance range of 174.5 to 182.5 MBOEPD. This is reflective of strong execution across our teams from well planning, to drilling and completions, to production operations.
CAPITAL EXPENDITURES
Capital expenditures (CAPEX) for the third quarter were $164 million (excluding a small Eagle Ford Shale acquisition) and lower than our quarterly guidance of $260 million, primarily due to the timing of exploration and long-lead development activity. In the fourth quarter, we expect CAPEX to be in the range of $370 million to $390 million. We continue to be comfortable with our full year 2025 CAPEX guidance of $1,135 to $1,285 million, which includes the Pioneer FPSO (Floating Production, Storage, and Offloading vessel) purchase in the first quarter, but excludes the previously mentioned small Eagle Ford Shale acquisition.
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Murphy’s onshore drilling and completions team continues to leverage past learnings and automated physics-based models to set new internal and external performance records. In the Eagle Ford Shale, we delivered top-performing wells in Catarina history, across all operators, through CAPEX-neutral optimizations to completions design, landing zone, and flowback strategy. Our 2025 new Catarina wells have an average break-even oil price of $36 per barrel WTI, with some as low as $22 per barrel WTI.
OPERATING COSTS
As noted above, operating expenses in the third quarter averaged $9.39 per BOE, which is $2.41 per BOE, or 20 percent, lower than in the second quarter. This was primarily due to higher production rates, lower offshore workover costs, and higher production from assets with lower base operating costs.
As we previously mentioned, we have made great progress reducing operating costs in our Eagle Ford Shale asset through workforce optimization, lower repairs and maintenance expenses, lower rental equipment costs, and reduced water disposal costs. Operating costs for the asset in the third quarter of 2025 are down 36 percent compared to the third quarter of 2024. Given these ongoing savings in our Eagle Ford Shale asset, coupled with lower workovers in the Gulf of America, we expect operating expense to be $10 to $12 per BOE for fourth quarter of 2025.
EXPLORATION AND APPRAISAL DRILLING
Murphy’s active exploration program combined with our strong offshore execution capability, as demonstrated by our Lac Da Vang (Golden Camel) field development progress, are our key differentiators. Our ongoing exploration and appraisal activity exposes the company to transformative conventional volumes and will test for more than one billion BOEs in gross un-risked resource potential. As we progress through the fourth quarter, we anticipate results from two key wells: the Hai Su Vang-2X (Golden Sea Lion) appraisal well in Vietnam, which will help tighten and potentially increase the previously guided 170 MMBOE to 430 MMBOE range of recoverable resources, and the Civette exploration well in Côte d’Ivoire which will test mean to upward gross resource potential of 440 MMBOE to 1,000 MMBOE.
In Vietnam, we secured a rig in the third quarter, and spud Hai Su Vang-2X appraisal well in line with plan. I want to highlight that we were able to fast-track this appraisal well in eight months, which reflects our team's successful execution as well as our strong partnership with the Vietnamese government and local regulatory agencies and partners.
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Our three-well Côte d’Ivoire exploration program remains on schedule to commence in the fourth quarter. As previously noted, this exploration program allows Murphy to evaluate three separate prospects representing various play types and large mean un-risked resources, with relatively low well costs and strong fiscal terms. Furthermore, we have replaced the third planned exploration well, Kobus, with Bubale, which we believe has higher upside with lower risk and lower cost.
In the Gulf of America, the Cello #1 and Banjo #1 exploration wells will be drilled in the fourth quarter. These wells are part of our near-field exploration program and are relatively low risk, but also smaller in terms of targeted recoverable resources as compared to our international exploration prospects.
COMMODITY PRICING
In addition to the oil and natural gas price comments made above, I will highlight that our gassy onshore Canada business saw realized natural gas prices average USD$1.22 per MCF, which was USD$0.59 per MCF or 94 percent higher than the AECO benchmark due to our diversification and fixed forward selling strategies. We are expecting more constructive AECO prices during the winter months and overall long-term price improvement driven by additional demand for Canadian gas as LNG Canada export capacity ramps up.
Looking ahead, we remain cautious about oil prices and are expecting a subdued oil price environment in first half of 2026 with a modest rebound going into 2027. As we build our 2026 plan against the backdrop of ongoing oil price volatility, we believe our multi-basin portfolio with low breakevens and high-quality inventory positions us well to respond flexibly to a downcycle macro environment.
FINANCIAL PERFORMANCE, RETURN OF CAPITAL AND BALANCE SHEET
As previously communicated, our Capital Allocation Plan allocates a minimum of 50 percent of adjusted free cash flow1 to share buybacks and potential dividend increases, with the remainder allocated to the balance sheet. During the first three quarters of 2025, we distributed $139.8 million of dividends to shareholders. We also repurchased $100.0 million of stock or 3.6 million shares in the first quarter, reducing our shares outstanding to 142.7 million as of September 30, 2025, with $550.0 million remaining in our board-authorized share repurchase program.
We are favorably positioned with a strong balance sheet, with total debt and net debt at the end of the third quarter of $1.4 billion and $1.0 billion, respectively. We had $150 million drawn on our unsecured revolving credit facility at the end of the quarter, reflecting a $50 million decrease over the prior quarter.
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CLOSING
I am pleased with our solid operational results in the third quarter and our continued onshore operational excellence. I am confident that with our unique multi-basin portfolio, strong balance sheet, and talented and dedicated workforce, we are well positioned to capitalize on emerging opportunities and navigate market volatility to deliver sustained growth and shareholder value.
Thank you for your continued trust as a valued Murphy Oil Corporation stockholder.
Eric M. Hambly
President and Chief Executive Officer
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CONFERENCE CALL AND WEBCAST SCHEDULED FOR NOVEMBER 6, 2025
Murphy will host a conference call to discuss third quarter 2025 financial and operating results on Thursday, November 6, 2025, at 9:00 a.m. ET. The call can be accessed either via the Internet through the events calendar on the Murphy Oil Corporation Investor Relations website at http://ir.murphyoilcorp.com or via telephone by dialing toll free 1-800-717-1738, reservation number 40758. For additional information, please refer to the Third Quarter 2025 Earnings Presentation available under the News and Events section of the Investor Relations website.
FORWARD-LOOKING STATEMENTS
This letter contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the company’s future operating results or activities and returns or the company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain
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necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the US 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 “Risk Factors” in our most recent Annual Report on Form 10-K filed with the US Securities and Exchange Commission (SEC) 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 letter. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.
1 This letter contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation’s overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with US generally accepted accounting principles (GAAP) and should therefore be considered only as supplemental to such GAAP financial measures. Please see Exhibit 99.1 on Form 8-K filed on November 5, 2025, for reconciliations of the differences between the non-GAAP financial measures used in this letter and the most directly comparable GAAP financial measures.
2 In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this letter exclude the NCI, thereby representing only the amounts attributable to Murphy.
Investor Contacts: | ||
InvestorRelations@murphyoilcorp.com | ||
Atif Riaz, 281-675-9358 | ||
Beth Heller, 281-675-9363 | ||
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