Carlos Escalante

Carlos Escalante, on behalf of Doug Leggate from Wolfe Research, questioned Canadian Natural Resources' perspective on the necessity of further consolidation in the West Canada gas market, given weak AECO pricing and the ramp-up of LNG projects. He also asked about the contribution of Palliser or Endeavor assets to sequential oil production growth and their impact on the H1 2026 outlook.

Answer

Scott Stauth, President, acknowledged ongoing consolidation in the gas basin but stressed that increased egress opportunities and the full potential of LNG projects are paramount for the basin's overall health. He confirmed that both Duvernay and Palliser block assets are integral to future budgeting and capital allocation for light oil drilling.

Carlos Escalante, on behalf of Doug Leggate from Wolfe Research, questioned Canadian Natural Resources' perspective on the necessity for further consolidation within the West Canada gas market, given prevailing weak AECO pricing and the increasing ramp-up of LNG exports, and also inquired about the contribution of Palliser and Endeavor assets to sequential oil production growth and their role in the H1 2026 growth outlook.

Answer

President Scott Stauth acknowledged ongoing consolidation trends but underscored that enhanced egress opportunities, particularly through LNG projects, are paramount for fully realizing the basin's potential, more so than M&A activity. He confirmed that both Duvernay and Palliser assets, with their strong production growth and ongoing capital allocation for light oil wells, would be integral to the company's 2026 budgeting and growth plans.

Carlos Escalante asked if low AECO gas prices could lead to a reduction in the Montney program and requested a comparison of the Cote D'Ivoire and Vietnam exploration opportunities, referencing a nearby discovery by ENI.

Answer

President, CEO & Director Eric Hambly explained that the Montney program remains robust due to high capital efficiency, existing plant commitments, and price diversification. He contrasted the exploration plays by stating that Cote D'Ivoire has more favorable fiscal terms and a higher working interest, making a potential discovery there more financially significant for Murphy than one in Vietnam.

Carlos Andres E. Escalante asked for an apples-to-apples comparison of reservoir quality between the two recent Vietnam discoveries and questioned what would define success for the upcoming exploration program in Cote d'Ivoire.

Answer

President and CEO Eric Hambly explained the lower flow rate at the Lac Da Hong discovery was due to its thinner pay sand compared to Hai Su Vang; adjusted for thickness, productivity is similar. For Cote d'Ivoire, he outlined that success would involve testing sizable resource potential (mean of 150M to 440M barrels per prospect) with compelling well costs ($50-60M) and strong fiscal terms, with success opening up significant follow-on opportunities.

Carlos Escalante from Wolfe Research asked if Murphy's strategy for its Tupper Montney asset in Canada is changing given recent progress on Canadian LNG projects and strong winter gas demand. He also inquired about the development plan for the Hai Su Vang discovery in Vietnam, noting the fluvial geology could imply a need for more wells if the reservoirs are not well-connected.

Answer

President and CEO Eric Hambly explained that the Tupper Montney asset is at plant capacity, and any expansion would be a multi-year project. They are evaluating adding capital for more wells to maintain higher throughput but need a durable price signal first. Regarding Hai Su Vang, he clarified that the well found pay in two zones. The deeper, flow-tested zone is expected to be laterally extensive and form the core development. The shallower zone is expected to be less extensive and represents upside volume to be appraised over time.

Carlos Andres E. Escalante asked about Murphy's perspective on consolidation and M&A to mitigate share price volatility, and inquired about the persistent downtime at the non-operated Terra Nova asset and whether Murphy would consider operating it.

Answer

CEO Roger Jenkins and President and COO Eric Hambly emphasized the strength of their existing organic portfolio, which supports growth for decades without M&A. Hambly noted they continuously evaluate M&A, primarily in the offshore, but focus on low-cost entry into underexplored basins rather than acquiring recent discoveries. Regarding Terra Nova, Hambly expressed extreme disappointment with its 55% uptime versus the expected 75-80%, confirming it is highly unlikely Murphy would seek to operate the asset with its 18% working interest.

Carlos Escalante from Wolfe Research, LLC inquired about Gulfport's potential to participate in the growing trend of in-basin power contracting and whether the company would strategically prioritize volume growth or improved basis differentials from this new demand. He also asked for a detailed walkthrough of the preferred equity buyback scenario, assuming all holders opt for a cash repurchase.

Answer

EVP & CFO Michael Hodges responded that Gulfport is likely to participate in new power demand through intermediaries or aggregation strategies rather than as a direct anchor supplier. He clarified that the company would prioritize benefiting from rising in-basin prices and narrowing differentials over pursuing significant production growth. Regarding the preferreds, he explained a full cash buyback would be absorbed by the RBL, temporarily increasing leverage, which would then be paid down with strong projected free cash flow.

Carlos Andres E. Escalante asked for the guiding principle behind pivoting to dry gas Utica acreage from a Marcellus well, specifically the commodity price levels that trigger such a decision. He also questioned if the company's hedging philosophy changes with increased exposure to liquids.

Answer

President and CEO John Reinhart explained the decision is dynamic, but the current pivot is driven by a favorable macro outlook for natural gas in late 2025 and 2026, contrasted with potential volatility in oil prices. EVP and CFO Michael Hodges added that the hedging strategy remains consistent and strategic, enabled by a strong balance sheet. He noted their bullish gas view is reflected in their hedge positions and that the liquids component is not yet large enough to alter their overall gas-focused approach.

Carlos Escalante questioned if the production management strategy tested on the Lake VII pad would influence future Utica development. He also asked for clarification on the Marcellus development pace, noting the 2025 plan seems slower than what is implied by the company's stated multi-year inventory life for the asset.

Answer

EVP and COO Matthew Rucker confirmed that learnings from the Lake VII pad were encouraging and will lead to slight tweaks in their choke management strategy for new wells. EVP and CFO Michael Hodges clarified that the inventory life figure is a corporate-level metric, and the actual Marcellus development will be paced over several years due to capital allocation and midstream infrastructure build-out.

Carlos Escalante of Wolfe Research LLC asked about Magnolia's long-term strategy for balancing production growth and capital efficiency to optimize free cash flow, and also questioned the capital allocation strategy regarding the product mix in the Giddings asset.

Answer

CEO Christopher Stavros emphasized the company's "appraise, acquire, grow, and exploit" strategy in Giddings, which has driven capital efficiency, allowing for higher production with less spending. He stated the goal is to drill the best wells for the highest free cash flow. Regarding product mix, Stavros clarified that even gassier wells in Giddings are rich in liquids and oil, and the company focuses on strong returns across the entire field rather than targeting specific product types.

Carlos Escalante inquired about the future trend of free cash flow, asking for a framework on the 2026 growth versus capital efficiency trade-off. He also followed up on the product mix within the Giddings asset and how capital is allocated between oilier and gassier areas.

Answer

CEO Christopher Stavros explained that capital efficiencies are improving due to the company's "appraise, acquire, grow, and further exploit" strategy in the Giddings field. He highlighted that the goal is to drill the best wells with the least capital to maximize free cash flow, noting the company is now spending less capital for higher production growth than initially guided. Regarding product mix, Stavros stated that even gassier wells in Giddings have significant liquids and oil, and the company focuses on drilling good wells across the entire field rather than targeting specific product mixes, as returns are strong broadly.

Carlos Andres E. Escalante inquired about the characteristics of Magnolia's new high-performing wells in Giddings, their impact on development acreage, and the implications for the company's underlying sustaining capital.

Answer

President and CEO Christopher Stavros explained that while the specific location is competitive information, the new area expands their development acreage. He highlighted the wells' strong financial returns, shallow decline profiles, and low F&D costs. Stavros added that deferring a half-dozen completions into next year, combined with a stable service cost environment, provides capital flexibility for both the current year and the next.

An analyst on behalf of Carlos Escalante asked what the 2025 capital program implies for long-term sustaining capital and how close the company is to potentially dropping a rig.

Answer

President and CEO Christopher Stavros affirmed confidence in the $460-$490 million capital plan to achieve 5-7% production growth. He stated that dropping a rig is not under consideration at current commodity prices and would only be a possibility if oil prices fell below $60 per barrel, emphasizing the program's flexibility and stability.

On behalf of Carlos Escalante, an analyst asked about the capital accounting for the pulled-forward 4-well pad and whether the minimal capital uptick is a proxy for ongoing efficiency gains. A follow-up question sought more color on the drivers of the LOE reduction and the right go-forward number.

Answer

President and CEO Christopher Stavros clarified that the Q4 capital forecast includes approximately $10 million to $15 million for the drilling costs of the new pad. Regarding LOE, he reiterated that positive inroads were made in nearly every cost bucket, especially direct LOE, and that the Q3 level is a good proxy going forward, suggesting a range of $5.25 to $5.35 per BOE feels appropriate for 2025.

Carlos Escalante of Wolfe Research LLC inquired about the key learnings from the shallower Jennings step-out well in the Western Haynesville and its impact on capital costs. He also asked about the ramifications of the reduced 2025 turn-in-line (TIL) forecast on the company's long-term lease-holding strategy.

Answer

COO Daniel Harrison explained that the shallower Jennings well was their fastest and cheapest to date, and that future wells in that depth range could see costs drop below $2,000/foot by forgoing tubing. Chairman & CEO M. Jay Allison highlighted successful completion tweaks on other wells. Regarding the TIL forecast, both Daniel Harrison and President & CFO Roland Burns clarified that the change represents a minor timing shift of about a month and does not significantly impact their long-term development plan, which is more dependent on drilling speed improvements.

Carlos Escalante of Wolfe Research LLC asked about the key takeaways from drilling the shallower Jennings well in the Western Haynesville, its impact on capital costs, and the ramifications of reducing the 2025 turn-in-line count from 17 to 13 on the 2027 HBP target.

Answer

COO Daniel Harrison explained that the shallower Jennings well was the company's fastest and cheapest drilled to date, and that future similar wells could see costs drop below $2,000 per foot by forgoing tubing. CEO M. Jay Allison highlighted successful completion tweaks on other key wells. Regarding the reduced well count for 2025, both Harrison and President & CFO Roland Burns clarified it was due to minor timing shifts of a few weeks and the scheduling of pilot holes, not a significant delay impacting long-term development goals.

Carlos Escalante of Wolfe Research, LLC inquired about key learnings from the shallower Northwest step-out well in the Western Haynesville, its effect on capital costs, and the impact of reducing the 2025 turned-in-line (TIL) well count from 17 to 13 on the 2027 HBP target.

Answer

COO Daniel Harrison explained that the shallower well was the fastest and cheapest drilled to date, and future similar wells may not require tubing, further reducing costs. Chairman & CEO M. Jay Allison highlighted that tweaked completion designs on recent wells have yielded excellent results. Regarding the TIL reduction, both Harrison and President/CFO Roland Burns clarified it's due to minor timing shifts and pilot hole drilling, not a significant delay to the overall HBP plan, with faster drilling speeds offsetting some changes.

Carlos Escalante of Wolfe Research LLC inquired about the key learnings from the northwestern step-out well in the Western Haynesville, its impact on capital costs, and the ramifications of a lower 2025 well count on long-term development targets.

Answer

COO Daniel Harrison explained that the shallower Jennings well was drilled at a record pace of 37 days, resulting in significantly lower costs. He noted future wells in that area could be even cheaper as they won't require tubing. CEO M. Jay Allison highlighted that tweaked completion designs on other recent wells have yielded some of the best results to date. Regarding the 2027 development timeline, both Harrison and President/CFO Roland Burns clarified that the reduction in 2025 turn-in-lines is a minor timing shift of about a month and does not materially impact the long-term plan, especially as drilling speeds are increasing.

Carlos Escalante of Wolfe Research LLC inquired about the key learnings from the shallower Northwest step-out well in the Western Haynesville and its impact on costs. He also asked about the ramifications of reducing the 2025 well turn-in-line count for the Western Haynesville on the company's 2027 leasehold preservation targets.

Answer

COO Daniel Harrison explained that the shallower Jennings well was their fastest and cheapest drilled to date, and future similar wells could see costs drop below $2,000/ft by forgoing tubing. Chairman & CEO M. Jay Allison highlighted that tweaked completion designs on other recent wells have resulted in some of the best wells the company has ever drilled. Regarding the well count, Harrison and President and CFO Roland Burns clarified the change is not a significant impediment to 2027 goals, attributing it to minor timing shifts of a month or so rather than major delays.

Carlos Andres E. Escalante asked about the expected capital allocation in 2026 between wells drilled to hold by production (HBP) and delineation wells in the Western Haynesville. He also inquired if management is concerned about potential new Permian gas takeaway capacity.

Answer

President and CFO Roland Burns stated that for 2025 and 2026, the priority in the Western Haynesville remains drilling the ~70 wells required to hold leased acreage, with location choices driven by this and midstream availability. For the legacy Haynesville, drilling is more price-driven. Regarding the Permian, Burns acknowledged that its gas supply growth is expected and necessary to meet future LNG and power demand.

Carlos Andres E. Escalante of Wolfe Research inquired about the typical development plan for a Western Haynesville pad, including the number of wells and spacing, and asked for more detail on how completion cost savings would be achieved given the hotter, deeper environment.

Answer

COO Daniel Harrison stated it's too early to define optimal spacing but the company aims for two-well pads where possible, estimating 50-60% of wells will be on them in the near term. He believes there is more room for cost reduction on the drilling side than the completion side. CEO Miles Allison added that the goal for 2025 is to use new wells to delineate the entire footprint and fully derisk the play by the end of 2026.

Carlos Andres E. Escalante of Wolfe Research asked about the geographical distribution of the 64 new horseshoe well locations and how this translates to free cash flow generation. He also inquired if the Western Haynesville would present similar lease line challenges as the legacy Haynesville and what the expected average lateral length would be in the new play.

Answer

COO Daniel Harrison clarified that the 64 horseshoe locations are evenly distributed across the company's Haynesville acreage. He explained that the Western Haynesville in Texas has more flexible, abstract-based units, avoiding the rigid section-line constraints of Louisiana. He projected an average lateral length of approximately 10,000 feet for the Western Haynesville program, noting that geo-hazards are a bigger limiting factor than drilling temperatures.

Speaking for Doug Leggate, Carlos Andres E. Escalante asked at what point the company would consider mothballing its renewable diesel facilities given market risks. He also inquired about potential opportunities in the LPG market related to tariff discussions.

Answer

CEO Timothy Go responded that the company believes its renewable diesel assets have a competitive advantage and can operate at breakeven or slightly positive in current conditions, positioning them for an eventual market recovery. Regarding LPG, executive Steven Ledbetter stated that it is not a core part of their Midstream business or a current growth platform, resulting in minimal exposure to market dislocations or tariff impacts.