HOUSTON–(BUSINESS WIRE)–Murphy Oil Corporation (NYSE: MUR):
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 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).
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.
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.
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.
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
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 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.
Contacts
Investor Contacts:
[email protected]
Atif Riaz, 281-675-9358
Beth Heller, 281-675-9363
