8-K: Murphy Oil Q2 Production Soars, Eyes Exploration

Murphy Oil Corporation reported strong second-quarter 2025 operational results with production exceeding guidance, despite lower commodity prices, and reaffirmed full-year capital expenditure plans.

Summary

• Net income attributable to Murphy for the second quarter of 2025 was $22.3 million, or $0.16 per diluted share.
• Adjusted net income from continuing operations attributable to Murphy (Non-GAAP) was $38.5 million, or $0.27 per diluted share.
• Total production for the second quarter reached 189,677 BOEPD, exceeding the high-end of guidance (177,000 to 185,000 MBOEPD).
• Oil production for the quarter was 89,530 BOPD, also outperforming guidance.
• The company returned $46 million to shareholders through quarterly dividends in Q2 2025, contributing to a total of $193 million returned in the first half of 2025 ($100 million in share repurchases and $93 million in dividends).
• Approximately $550 million remains under the share repurchase authorization, with 142.7 million shares outstanding as of June 30, 2025.
• Liquidity stood at approximately $1.5 billion on June 30, 2025, comprising $1.15 billion undrawn under the senior unsecured credit facility and $380 million in cash and cash equivalents.
• Total debt as of June 30, 2025, was $1.48 billion, consisting of long-term, fixed-rate notes and $200 million drawn under the credit facility.
• Accrued capital expenditures (CAPEX) for Q2 2025 were $250.8 million.
• Lease operating expense was $11.80 per BOE, a 14.1% reduction from the first quarter.
• Full year 2025 CAPEX guidance was reaffirmed at the midpoint of the $1,135 million to $1,285 million range.
• Full year total company production is now trending at the midpoint of the 174,500 to 182,500 BOEPD guidance range.
• A small Eagle Ford Shale acquisition was closed for $23 million on July 1, 2025.
• A rig contract was signed for a three-well exploration program in Côte d'Ivoire.
• Realized oil prices averaged $64.31 per barrel in Q2 2025, an 11% decrease from Q1 2025.
• Realized natural gas prices averaged $1.88 per thousand cubic feet in Q2 2025, a 29.5% decrease from Q1 2025, with natural gas comprising 53% of the production mix.
• Onshore business produced approximately 118 MBOEPD (31% liquids), and offshore business produced approximately 72 MBOEPD (82% oil).
• The Lac Da Vang (Golden Camel) field development in Vietnam remains on schedule for first oil in the second half of 2026.

Sentiment

Score: 7

Explanation: Operational outperformance and cost reductions are strong positives, and the exploration program is exciting. However, the significant impact of lower commodity prices on net income and free cash flow is a notable negative. The company is managing what it can control well, but external market conditions are challenging.

Positives

• Second quarter production of 189,677 BOEPD exceeded the high-end of quarterly guidance (177,000 to 185,000 MBOEPD), demonstrating strong operational performance.
• Oil production of 89,530 BOPD also exceeded guidance, highlighting robust oil output.
• New onshore wells, particularly in the Eagle Ford Shale (EFS), delivered strong performance, with 24 operated wells and 10 gross non-operated wells brought online, and Karnes County wells averaging 2,123 BOEPD per well.
• Tupper Montney's 10 new wells showed excellent early performance, with 30-day initial production rates averaging 19.2 million cubic feet per day, ranking among the top 20 all-time Tupper high performers.
• Successful completion of Samurai #3 and Khaleesi #2 workovers in the Gulf of America added 3.7 MBOEPD to third-quarter production.
• The Lac Da Vang (Golden Camel) field development in Vietnam remains on schedule for first oil in the second half of 2026, achieving 2.5 million work hours with zero Lost Time Injuries.
• Operating expenses in Q2 2025 were $11.80 per BOE, a 14.1% reduction from Q1 2025, driven by higher production rates, lower EFS operating costs, and reduced offshore workover costs.
• Eagle Ford Shale operating costs decreased by $12 million (18%) in the first half of 2025 compared to the first half of 2024, with unit costs down 30%.
• The company maintains a strong balance sheet with approximately $1.5 billion of liquidity as of June 30, 2025.
• Returned $193 million to shareholders in the first half of 2025 through $100 million in share repurchases and $93 million in dividends, demonstrating commitment to shareholder returns.
• A highly accretive $23 million Eagle Ford Shale acquisition was completed, increasing working interest in an already owned and operated business.
• Onshore drilling and completions teams set new internal performance records, including a 26% increase in drilling Rate of Penetration (ROP) and a 20% reduction in spud-to-total depth timing in Catarina.
• Successfully drilled two long lateral U-turn wells in Tilden, reducing CAPEX by 33% with no reduction in oil recovery.
• Drilled the longest horizontal wells in Murphy history in Kaybob Duvernay.
• The Canadian natural gas business achieved realized prices averaging $1.65 per MCF, which was $0.44 per MCF higher than the AECO benchmark, due to diversification and fixed forward selling strategies.
• The first cargo of liquefied natural gas (LNG) leaving the LNG Canada facility is expected to provide 2 billion cubic feet per day of additional demand for Canadian gas, potentially leading to higher AECO prices.

Negatives

• Net income attributable to Murphy significantly decreased to $22.3 million in Q2 2025 from $73.0 million in Q1 2025, despite increased production.
• Realized oil prices were $64.31 per barrel in Q2 2025, an 11% decrease from Q1 2025, impacting revenue.
• Realized natural gas prices were $1.88 per MCF in Q2 2025, a 29.5% decrease from Q1 2025, significantly affecting profitability given natural gas comprises 53% of the production mix.
• Offshore Canada business delivered average production of 5.6 MBOEPD, which was 2.1 MBOEPD lower than quarterly guidance due to higher than anticipated downtime.
• Free cash flow (Non-GAAP) decreased significantly to $17.8 million in Q2 2025 from $174.4 million in Q2 2024.
• Net cash provided by continuing operations activities decreased to $358.1 million in Q2 2025 from $467.7 million in Q2 2024.
• Total revenues and other income decreased to $695.6 million in Q2 2025 from $802.8 million in Q2 2024.
• Operating income from continuing operations decreased to $92.2 million in Q2 2025 from $184.3 million in Q2 2024.

Risks

• Macro conditions in the oil and natural gas industry, including supply/demand levels and actions by major oil exporters, could impact commodity prices.
• Geopolitical concerns pose a risk to operations and market stability.
• Increased volatility or deterioration in the success rate of exploration programs or the ability to maintain production rates and replace reserves could negatively affect future performance.
• Reduced customer demand for products due to environmental, regulatory, technological, or other reasons could impact sales.
• Adverse foreign exchange movements could affect financial results.
• Political and regulatory instability in markets where business is conducted could disrupt operations.
• The impact on operations or market from health pandemics and related government responses remains a potential risk.
• Other natural hazards impacting operations or markets could cause disruptions.
• Any deterioration in business, markets, or prospects could negatively affect financial health.
• Failure to obtain necessary regulatory approvals could delay or prevent projects.
• Inability to service or refinance outstanding debt or access debt markets at acceptable prices could impact financial flexibility.
• 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, could affect financial performance.

Future Outlook

Full year 2025 total company production is now trending at the midpoint of the guidance range of 174,500 to 182,500 BOEPD. Full year 2025 CAPEX guidance of $1,135 million to $1,285 million is reaffirmed at the midpoint, with third quarter 2025 CAPEX expected to be $260 million, excluding acquisition costs. Significant exploration and appraisal catalysts are anticipated in the second half of 2025, including Cello #1 and Banjo #1 exploration wells in the Gulf of America (Q3 and Q4), and an appraisal well at the Hai Su Vang (Golden Sea Lion) oil discovery in Vietnam (Q3, results in Q4). The three-well Côte d'Ivoire exploration program is on schedule to commence in Q4 2025. The Lac Da Vang (Golden Camel) field development in Vietnam remains on schedule for first oil in the second half of 2026. Operating expenses in the second half of 2025 are expected to be in the $10 to $12 per BOE range, more in line with historical trends, as most offshore workover activity is complete. The company expects to use available adjusted Free Cash Flow for share repurchases rather than bond repayments, given current market conditions and the high potential exploration and appraisal program. The LNG Canada facility's operation is expected to result in higher AECO natural gas prices as production ramps up.

Management Comments

• "I am very pleased with our solid operational results in the second quarter which were achieved through strong new onshore well performance, continued Gulf of America workover progress, and field development execution at Lac Da Vang (Golden Camel)."
• "Its an exciting time at Murphy as we look ahead to significant exploration and appraisal catalysts in the second half of the year."
• "In addition, this quarter we have introduced a Quarterly Stockholder Update which provides deeper insights and leadership perspectives on our business."
• "These financial results reflect the extraordinary impact of commodity prices on our business and reinforce the importance of concentrating on the parts of our business we can control: production rates and costs, a solid balance sheet and a first rate exploration program followed by best-in-class oil field development skills."
• "I must admit that I am very proud of our onshore team who continues to deliver impressive operational and technical improvements despite a new well program that has limited shots on goal compared to shale-only industry peers."
• "We are confident that the discovery [Hai Su Vang] is significant and provides a highly profitable investment opportunity."
• "I'm confident that our talented and dedicated employees are capable of delivering shareholder value through our differentiated business model."

Industry Context

The company's diversified business model, encompassing both onshore and offshore production in the U.S. and internationally, along with a proven track record in offshore frontier exploration, serves as a key differentiator from pure-play U.S. shale companies. While the broader industry faces declining Eagle Ford Shale well performance, the company highlights its ability to enhance capital efficiency and improve well performance year over year, attributing this to a more deliberate development schedule and a robust inventory of tier-one well locations. The commencement of operations at the LNG Canada facility is a significant regional development for the Canadian natural gas market, expected to increase demand and AECO prices, which directly benefits the company's gassy onshore Canada business. The company's emphasis on its international frontier wildcat and Gulf of America nearfield exploration program further distinguishes its strategy from peers, focusing on high-impact, conventional opportunities.

Comparison to Industry Standards

• The company's diversified business model, including both onshore and offshore operations in the U.S. and internationally, is presented as a key differentiator compared to 'pure-play US shale companies' that typically focus on a single basin.
• In the Eagle Ford Shale (EFS), the company contrasts its performance with the industry trend, stating that 'While the industry is experiencing declining EFS well performance, in contrast, we continue to enhance capital efficiency by modifying completion designs and operating practices to deliver improved well performance year over year.' This suggests outperformance relative to EFS peers.
• The company's onshore team is noted for 'impressive operational and technical improvements despite a new well program that has limited shots on goal compared to shale-only industry peers,' indicating superior efficiency and effectiveness in its drilling program relative to some competitors.
• The international frontier wildcat and Gulf of America nearfield exploration program is explicitly called a 'key differentiator from our peers,' highlighting a strategic focus on high-impact, conventional opportunities that many U.S.-focused E&P companies do not pursue.
• The company's realized Canadian natural gas prices averaged $1.65 per MCF, which was $0.44 per MCF higher than the AECO benchmark, demonstrating effective diversification and fixed forward selling strategies compared to market benchmarks.
• The long-term debt target of $1.0 billion, representing a 1.0x debt to EBITDA ratio at approximately $45 per barrel WTI, provides a clear financial health benchmark relative to commodity price assumptions, indicating a conservative financial posture.

Stakeholder Impact

• Shareholders: Positive impact from continued return of capital ($46 million in Q2, $193 million in H1 2025) through dividends and share repurchases, and potential for future value creation from high-impact exploration and development. Negative impact from lower net income due to commodity prices.
• Employees: Positive impact from continued operational progress and strategic exploration programs, suggesting stable employment and potential for growth.
• Customers: No direct impact mentioned, as the company is an upstream producer.
• Suppliers: Continued capital expenditures ($250.8 million in Q2, $1.135-$1.285 billion full year guidance) indicate ongoing demand for services and equipment.
• Creditors: Strong liquidity ($1.5 billion) and commitment to a $1.0 billion long-term debt target (1.0x debt to EBITDA at $45 WTI) indicate a healthy financial position, though current FCF is being directed to buybacks rather than bond repayments.

Next Steps

• Host a conference call to discuss second quarter 2025 financial and operating results on August 7, 2025.
• Progress the Marmalard #3 workover with expected resumption of production in August.
• Drill the Cello #1 exploration well in the Gulf of America in the third quarter.
• Begin drilling a key appraisal well at the Hai Su Vang (Golden Sea Lion) oil discovery in Vietnam in the third quarter, with results expected in the fourth quarter.
• Drill the Banjo #1 exploration well in the Gulf of America in the fourth quarter.
• Commence the three-well Côte d'Ivoire exploration program in the fourth quarter.
• Installation of the LDV-A platforms jacket early in the fourth quarter.
• Achieve first oil from Lac Da Vang (Golden Camel) field development in the second half of 2026.
• Continue to use available adjusted Free Cash Flow for share repurchases.

Key Dates

Recommendation

The company demonstrated strong operational execution in the second quarter, exceeding production guidance and significantly reducing operating costs. Its strategic focus on high-impact exploration and development, coupled with a disciplined capital allocation plan that includes returning capital to shareholders, positions it well for long-term value creation. However, the substantial decline in net income and free cash flow due to lower commodity prices highlights a significant near-term headwind. While the underlying business performance is robust, the external market environment creates uncertainty, suggesting a 'hold' recommendation until there is clearer visibility on commodity price recovery or successful de-risking of the exploration portfolio.

Keywords

Oil and Gas, Exploration and Production, E&P, Energy, Upstream, Quarterly Results, Financial Performance, Production Guidance, Capital Expenditures, Share Repurchase, Dividends, Gulf of America, Eagle Ford Shale, Tupper Montney, Kaybob Duvernay, Vietnam, Côte d'Ivoire, LNG, Commodity Prices