Carlos Escalante

Carlos Escalante inquired about the carryover effect of longer laterals on 2027 capital efficiency and the level of optionality Chord Energy has for other formations or stack pay development.

Answer

CEO Danny Brown, while not guiding for 2027, noted "nice tailwinds" for capital efficiency from the roll-in of tills from 2026 capital deployment, expecting further improvements. On other formations, Mr. Brown emphasized Chord's deep inventory of conservatively spaced, repeatable Middle Bakken program. He acknowledged awareness of the full column underneath their acreage and monitors other operators, but currently has a strong inventory without needing to pursue other formations.

Carlos Escalante asked about Chord Energy's optionality for other formations and stacked pay development, given the activity of peers in other basins.

Answer

CEO Danny Brown highlighted the deep inventory of conservatively spaced, repeatable Middle Bakken program. He acknowledged awareness of the full column underneath their acreage and monitors other operators but emphasized that their current inventory is robust, making other formations less of an immediate need.

Carlos Escalante inquired about Gulfport Energy's strategy regarding improving basis and potential future growth, contrasting it with peers' reluctance to grow. He also requested an update on the Hendershot and Yankee pads' type curve performance and any similarities observed in the Northern Marcellus position.

Answer

Michael Hodges, Executive Vice President and Chief Financial Officer, stated that Gulfport considers both index pricing and differentials, and while bullish on basis, a significant, longer-term structural shift in index price would be needed to alter their consistent free cash flow maximizing strategy. Matthew Rucker, Executive Vice President and Chief Operating Officer, confirmed the Hendershot and Yankee pads are in natural decline, mirroring the area's type curve, and are holding strong, supporting long-term plans. He added that Northern Marcellus acreage is expected to be on par, with current drilling focused on understanding liquid mix for midstream planning.

Carlos Escalante inquired about Gulfport Energy's game plan regarding growth with proactive, discretionary capital, especially given peers' reluctance to capitalize on improving basis. He also asked for an update on the tail-end performance of the Hendershot and Yankee pads and any observed similarities in the Northern Marcellus position.

Answer

EVP and CFO Michael Hodges stated that significant changes to Gulfport's development cadence would require a longer-term, more meaningful structural shift in index prices beyond current strip. He noted Gulfport's historical focus on flat/low single-digit growth to maximize free cash flow. EVP and COO Matthew Rucker confirmed the Hendershot and Yankee pads are in natural decline, mirroring the type curve and supporting long-term development. He expects similar acreage quality in Marcellus North, with a focus on well liquid mix to inform midstream contracts.

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 asked Dan Harrison about the Brown Trueheart BB well's slight underperformance in IP rate compared to other Western Haynesville wells, noting its proximity to a previously underperforming well. He inquired about potential rock quality or water handling issues in that specific area. Carlos Escalante then followed up, asking Jay Allison and Roland Burns for their views on the M&A market trend in the Haynesville, given high valuations for lower quality acreage, and if the acquisition of the second-largest operator compels Comstock to participate.

Answer

Dan Harrison, COO, explained that the Brown Trueheart BB well was drilled up-dip and made a lot of water during flowback, which made it difficult to achieve a high IP rate, though the down-dip well on the same pad IP'd higher. He clarified that the water is load water, not formation water, and that EURs are expected to be similar. Jay Allison, Chairman and CEO, added that drilling up-dip means fighting gravity. Jay Allison responded that Comstock believes it holds some of the most valuable gas globally due to its proximity to LNG facilities and data centers. He stated that Comstock's business plan is to showcase the potential of its Western Haynesville assets (50 Tcfe upside, 2,561 undedicated locations) through innovation and a strong balance sheet, rather than seeking inventory like other companies.

Carlos Escalante asked for insights into the performance of the Brown Trueheart BB well in the Western Haynesville, noting its slight underperformance compared to the broader group and its proximity to another underperforming well (Miles). He sought clarification on potential rock quality or water handling issues in that specific area. He also asked for Comstock's views on the M&A market trends in the Haynesville, especially after a competitor's acquisition, and if it prompts Comstock to participate.

Answer

Chief Operating Officer Dan Harrison attributed the Brown Trueheart BB well's lower initial production rate to high water production during flowback, noting it was an updip well on a two-well pad where the downdip well IP'd significantly higher. He clarified that the water is load water, not formation water, and expects it to decrease over time, leading to similar EURs. Chairman and CEO Jay Allison stated Comstock believes it sits on some of the most valuable gas globally due to its Western Haynesville inventory and proximity to LNG and data center demand. He emphasized the company's plan to develop its existing assets, de-risk the Western Haynesville, and maintain a strong balance sheet, rather than seeking M&A for inventory.

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.

Carlos Escalante inquired about the D&C cost savings year-over-year, specifically how much was due to Magnolia's 'industrial approach' (consistent rigs/crews) versus service deflation, and the potential for further efficiency gains. He also asked for an estimate of maintenance capital required to hold production flat.

Answer

Chris Stavros, Chairman, President, and CEO, attributed D&C cost gains to the 'industrial approach,' emphasizing the consistency and experience of rigs, crews, and equipment, which drives efficiencies and is expected to gradually improve. He estimated maintenance capital to hold production flat at 'around $400 million-ish, maybe a little less.' Brian Corales, Senior Vice President and Chief Financial Officer, added that capital spend has been stable over the last five years despite 50% production growth, driven by efficiencies.

Carlos Escalante asked about the drivers of year-over-year drilling and completion (D&C) cost savings, specifically the contribution from Magnolia's 'industrial approach' (consistent rigs and crews) versus service deflation, and the potential for further efficiency gains. He also sought an estimate for the company's maintenance capital required to hold production flat.

Answer

Chris Stavros, Chairman, President, and Chief Executive Officer, emphasized that the consistent use of the same rigs and crews over multiple years has led to a deep understanding of the field, drilling challenges, and capabilities, driving significant efficiencies. He estimated maintenance capital to hold production flat at approximately $400 million, or potentially less. Brian Corales, Senior Vice President and Chief Financial Officer, added that absolute capital spending has remained relatively stable over the past five years while production has increased by roughly 50%, reflecting these efficiencies.

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 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 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 asked for details on the exact failure mechanism of the Civette drilling and how it impacts the probability of success for the Caracal and Bubal prospects, given that Civette was testing a new geological concept. He also questioned if Murphy Oil would approach future targets differently. Escalante's follow-up question was about the Vietnam business's potential scale.

Answer

Eric Hambly (President and CEO) explained that at Civette, oil pay was found but not in commercial quantities, emphasizing that Caracal and Bubal are independent prospects unaffected by Civette's results. He stated that Murphy Oil is not being overly aggressive with current estimates for Hai Su Vang, projecting Lac Da Vang and Hai Su Vang combined could produce 30,000-50,000 net BOE per day in the early 2030s.

Carlos Escalante asked for details on the failure mechanism of the Civette drilling and its impact on the probability of success for the Caracal and Bubal prospects, noting that while the geology is distinct, the company was testing a new concept. He also questioned if the company was understating the potential scale of its Vietnam business, particularly Hai Su Vang, given its size relative to the Eagle Ford operations.

Answer

Eric Hambly, President and CEO, and Atif Riaz, VP, Investor Relations and Treasurer, explained that at Civette, oil pay was found in multiple reservoirs but not in commercial quantities. They emphasized that Caracal and Bubal are independent prospects, so Civette's results do not impact their probability of success. Regarding Vietnam, they stated that the company is not being overly aggressive with current estimates, as more appraisal work is needed for Hai Su Vang. They project that Lac Da Vang and Hai Su Vang combined could produce 30,000-50,000 net BOE per day in the early 2030s, acknowledging the phased development approach and Murphy's 40% working interest.

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, 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, 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.

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.