Paul Cheng

Paul Cheng asked about opportunities to further reduce D&C/well costs in legacy Midland operations (around $550/ft) and if Diamondback expects to offset inflation to drive this number down towards $500-$525 in the next 3-4 years.

Answer

COO Danny Wesson identified drilling efficiency (more consistent ultra-fast wells, reducing spud-to-TD time) and completion efficiency (continuous pumping, supply chain optimization) as key drivers. He noted these are many small wins. Danny Wesson stated that the $550/ft includes deeper, higher-cost zones like Wolfcamp D and Barnett, where material cost reductions are expected. For older zones, cost reduction will largely depend on activity and continued efficient execution to manage variable costs.

Paul Cheng asked about the biggest opportunities to further reduce D&C/well costs in the Midland Basin, which are already around $550/foot, focusing on whether improvements will come from drilling or completion. He followed up by asking if the $550/foot cost could be driven down to $500-$525 in the next three to four years, more than offsetting inflation.

Answer

COO Danny Wesson explained that drilling improvements will come from more consistent ultra-fast wells, reducing the average spud-to-TD time. On the completion side, continuous pumping and supply chain optimization (fuel, supporting services) will drive efficiency. He emphasized that these are many small wins that add up. Danny Wesson clarified that the $550/foot is a mix of all Midland Basin zones, including deeper, higher-cost areas like Wolfcamp D and Barnett. He believes material cost reductions are possible in these deeper zones as execution improves, and while inflation is a factor, their focus on better execution and supply chain efficiency aims to drive down variable costs.

Paul Cheng asked about the percentage of three-mile or longer wells in Diamondback Energy's 2025 program and how that might shift over the next several years. He also inquired about the company's awareness and potential deployment of proprietary lightweight proppant technology (mentioned by a larger customer) that could improve recovery rates by up to 30%. He followed up by asking if the percentage of three-mile plus wells could reach 50% over the next five years.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) stated 20-25% of the 2025 program consists of three-mile or longer laterals, with about 6% being 17,500 or 20,000 feet, noting efforts to improve results on longer laterals. He acknowledged the lightweight proppant technology and stated Diamondback's ability to test different technologies for front-end and tail-end recovery improvements, with results on slide eight speaking for themselves regarding maximizing returns and NPV per section. He responded to the 50% lateral length question with 'Never doubt us, but I think today it's harder to see,' expecting lateral lengths to be up next year and continuing to work on trades to keep them as long as possible, watching peers' creative approaches.

Paul Cheng asked about the percentage of three-mile or longer wells in the 2025 program and how that might shift over the next several years. He also inquired about Diamondback's assessment of a competitor's proprietary technology using lightweight proppant to improve recovery rates by up to 30%, asking if similar market solutions exist or if it's truly proprietary.

Answer

Kaes Van't Hof (CEO, Diamondback Energy) stated that three-mile or longer laterals make up 20-25% of the 2025 program, with about 6% being 17,500 or 20,000 feet. He expects this percentage to continue to grow, with the team exploring creative ways like U-turn and J-hook wells to push lateral length further. Regarding the competitor's technology, Kaes Van't Hof acknowledged the value of new technologies and affirmed Diamondback's own ability to test different approaches to improve recoveries, both on the front end and for depleting wells, emphasizing that their results (as shown on slide eight) speak for themselves in maximizing returns and NPV per section.

Paul Cheng of Scotiabank asked how Diamondback's business model will evolve given the scarcity of large M&A targets and inquired about the potential 2026 capex outlook.

Answer

CEO Kaes Van't Hof responded that patience will be key, and the focus will shift to exploring their existing asset base, including secondary zones, and smaller block-up trades while waiting for valuable opportunities. He confirmed the company remains focused on the Permian. For 2026, he estimated that maintaining current oil production would require about $900 million in capex per quarter, a figure that already includes anticipated tariff impacts.

Paul Cheng asked if Diamondback's business model needs to change from acquisition-led growth and look outside the Permian, and also questioned a drop in Q1 natural gas production.

Answer

President Kaes Van’t Hof asserted there is no need to leave the Permian, citing its superior inventory. He believes significant per-share growth is still achievable with the current assets. He explained the gas production dip was a temporary result of contract adjustments from fixed-fee to percent-of-proceeds (POP), which is expected to reverse.

Paul Cheng asked for an estimate of the CapEx savings from the DUC inventory drawdown in the current year's budget. He also inquired about the cadence of the well completion program, noting that production guidance seems conservative given the number of wells being brought online.

Answer

President Kaes Van't Hof estimated the DUC drawdown provides about $200 million in CapEx savings this year, based on a drilling cost of around $2.2-$2.4 million per well. Regarding cadence, he stated that while about 20 wells were pulled forward from last year, the program is not actively managed around calendar lines and that a run-rate of around 530 wells per year (including Double Eagle) is a good baseline.

Paul Cheng asked for specific examples of practices where Endeavor was outperforming Diamondback and if the potential savings could be quantified. He also questioned how the company balances its debt reduction target with its shareholder payout ratio, especially given the recent high payout.

Answer

Chairman and CEO Travis Stice cited Endeavor's superior drill-out experience as an immediate benefit. President and CFO Kaes Van't Hof emphasized that the largest, unquantifiable benefit is the ability to combine massive datasets to optimize completion designs. Regarding capital returns, he clarified that the high Q3 payout was an exception, driven by a unique opportunity to repurchase a large block of shares from the Stevens family, and the standard target remains around 50% of free cash flow.

Paul Cheng questioned the repeatability of Devon Energy's impressive Q4 Delaware results, including the impact of one-off items, new wells versus base operations, and the underlying base decline rate in the Delaware.

Answer

President and CEO Clay Gaspar attributed Q4 performance to cost structure efficiency and productivity, expecting the trend to continue. SVP of E&P Asset Management John Raines noted Q4 benefited from timing and outperformance of three new programs, alongside significant base production optimization. He stated the Delaware base decline rate is in the mid-30% range, unchanged year-over-year, with base wins showing up in reduced downtime (historically 7%, now projected inside 5%).

Paul Cheng asked about the impressive fourth-quarter Delaware results, specifically if the performance (fewer rigs, higher production) is repeatable or if there were one-off factors like well timing, and the contribution from new wells versus base operations. He then followed up by asking about the underlying base decline rate in the Delaware and if it has changed due to better base operations.

Answer

Clay Gaspar, President and CEO, highlighted the consistent quarter-over-quarter performance driven by a downdraft in cost structure and an updraft in productivity, expressing confidence in its extension into 2026. John Raines, SVP of E&P Asset Management, added that while timing helped, new wells outperformed expectations with a balanced mix across Wolfcamp B, Bone Spring, and Wolfcamp A. He noted that base production outperformed by about 5,000 bbls/day for the full year. Raines stated the base decline rate is in the mid-30% range and hasn't changed dramatically year-over-year, but downtime has significantly reduced from 7% historically to under 5% this year.

Paul Cheng from Scotiabank asked for color on what appears to be declining well productivity in the Bakken and requested an update on the activity cadence and production outlook for the Eagle Ford post-JV dissolution.

Answer

SVP John Raines clarified that the perceived Bakken productivity decline is due to a planned shift in activity from higher-quality legacy assets to the newly acquired Grayson asset, where performance is meeting expectations. For the Eagle Ford, he noted a production reset occurred as part of the JV dissolution, but Devon plans to bring ~55 more wells online this year and expects to grow production back to pre-split levels.

Paul Cheng from Scotiabank asked for color on what appears to be declining well productivity in the Bakken and questioned the activity cadence and production outlook for the Eagle Ford following the JV dissolution.

Answer

SVP John Raines addressed the Bakken question, explaining that the perceived productivity decline is due to a planned shift in activity from higher-quality legacy acreage to the newly acquired Grayson asset, where well performance is meeting expectations. For the Eagle Ford, he confirmed a production reset post-JV dissolution but noted plans to bring 55 more wells online this year, with the goal of growing production back to pre-split levels.

Paul Cheng from Scotiabank asked for color on well productivity trends in the Bakken and whether the asset has sufficient scale, and also inquired about the activity cadence and production outlook for the Eagle Ford after the JV dissolution.

Answer

SVP John Raines explained that the shift in Bakken well productivity is due to a change in activity from legacy acreage to the newly acquired Grayson asset, with performance meeting expectations. In the Eagle Ford, he confirmed a production reset post-JV dissolution, with plans to bring ~55 new wells online to grow production back to pre-split levels.

Paul Cheng asked how Devon's current technology adoption for business optimization differs from past efforts and peers, and also questioned why Delaware Basin production seemed light relative to the number of new wells brought online in Q1.

Answer

President and CEO Clay Gaspar introduced CTO Trey Lowe, who highlighted new technology initiatives, including using standardized sensor data with real-time AI models for well optimization and deploying a new internal AI platform that has boosted employee productivity by 15-30% on certain tasks. SVP, Asset Management John Raines explained the Delaware production was affected by lower working interests in Q1 wells, a back-end loaded completion schedule, and minor weather impacts, while affirming that underlying well productivity remains strong.

Paul Cheng of Scotiabank questioned how dissolving the BPX joint venture could suddenly unlock $2 million per well in savings and why a higher Delaware well count in 2025 doesn't translate to proportionally higher production guidance.

Answer

COO Clay Gaspar explained the JV savings come from direct operational control and side-by-side well comparisons. He clarified the Delaware production-per-well metric is impacted by a lower average working interest in 2025 (73%) versus 2024 (80%), not lower well productivity. CFO Jeff Ritenour added that 2025 capital spending will be front-loaded.

Paul Cheng asked if increased multi-zone development has led to noticeable changes in gas-oil ratios (GOR) or sour gas exposure. He also inquired about the company's inventory life in the Permian Basin under a $50 WTI and $3 gas price scenario.

Answer

Chief Operating Officer Clay Gaspar acknowledged that deeper zones are typically gassier but noted that some benches have proven to be surprisingly oily, with positive results. He confirmed sour gas is a known factor in specific areas and is managed with midstream partners. Regarding inventory, Gaspar reiterated a confident 10-year runway across all five basins, supported by third-party analysis, with a high degree of confidence in the first five years of that inventory.

Paul Cheng asked for clarification on whether the management change would lead to a strategic review or if it was business as usual, and if Tim Go's voluntary leave of absence was permanent, implying a search for a permanent CEO replacement. He also asked for a regional breakdown of the SRE impact on margins for the quarter.

Answer

Franklin Myers (Interim CEO, HF Sinclair) stated that it was 'business as usual' for the company and declined to comment further on Tim Go or other related matters, promising updates when available. Steve Ledbetter (EVP of Commercial, HF Sinclair) offered to take the question regarding the regional breakdown of SRE impact offline with Craig Biery.

Paul Cheng asked for clarification on whether the management change would lead to a strategic review or if it was business as usual, and if Tim Go's voluntary leave was temporary or permanent. He also inquired about the regional breakdown of the SRE impact on margins for the quarter.

Answer

Franklin Myers, Interim CEO, stated that it was 'business as usual' regarding any strategic review and that the company would continue with its existing plans. He reiterated that there were no further comments on Tim Go's situation, promising updates if additional information became available. Steve Ledbetter, EVP of Commercial, offered to take the question regarding the regional breakdown of SRE impact offline with Craig Biery.

Paul Cheng inquired if the first phase of the midstream expansion would primarily use equity barrels and be a definite 'go,' and asked for an update on the lubricants market and M&A conditions.

Answer

Steve Ledbetter, EVP of Commercial, confirmed a good portion of the first phase would be equity barrels and it's a fair assumption it's a 'go' due to sufficient anchor shipping, with an FID decision by mid-2026. Matt Joyce, SVP of Lubricants and Specialties, described a healthy lubricants market and continued exploration of bolt-on acquisitions. Tim Go, CEO, reiterated the strategy to grow the finished business and increase the trading multiple.

Paul Cheng inquired if the first phase of the midstream expansion would primarily use HF Sinclair's equity barrels, ensuring it's a 'go' regardless of open season outcomes, and asked about proposed tariffs. He also asked about the lubricants market outlook, M&A market conditions, and whether valuation multiples have changed.

Answer

Steve Ledbetter, EVP of Commercial, confirmed a good portion of Phase 1 would be equity barrels, making it a fair assumption that it's a 'go' with anticipated FID by mid-2026, but declined to comment on tariff structure. Tim Go, CEO, reiterated the project's quicker and more efficient cost/timing. Matt Joyce, SVP of Lubricants and Specialties, described a healthy lubricants market, returning to historic run rates, and continued exploration of M&A opportunities. Tim Go added that the strategy is to grow the finished business and reduce base oil length, but declined to comment on specific M&A valuations, differentiating HF Sinclair's North American industrial-focused business.

Paul Cheng questioned the decline in per-store sales volume in the marketing segment despite an increase in the number of stores. He also requested an update on the specific initiatives aimed at achieving the company's medium-term refining cost target of $7.25 per barrel.

Answer

EVP, Commercial Steven Ledbetter and CEO Timothy Go attributed the volume trend to a 'high grading' of the portfolio, where lower-performing sites are pruned and replaced with new, higher-margin locations, calling it a timing issue. On cost reduction, EVP, Refining Valerie Pompa and CEO Timothy Go highlighted reliability improvements, capital efficiency, and the implementation of digital programs for predictive maintenance as key drivers, emphasizing that the $7.25/bbl target addresses both cost reduction and improved reliability.

Paul Cheng questioned management's long-term view on the lubricants business and whether it is now considered a core part of the portfolio. He also asked if HF Sinclair could quantify its cost reduction initiatives, similar to programs announced by its peers.

Answer

CEO Timothy Go clarified that the lubricants business can be a core long-term holding, stating that previous commentary was related to the market not fully appreciating its value within HF Sinclair's stock. Regarding costs, Go and President of Refining Valerie Pompa declined to provide a specific dollar target but highlighted ongoing progress. They pointed to lower year-to-date refining OpEx, with a target of $7.25/bbl, as well as cost reductions in the lubricants, G&A, and midstream segments, emphasizing a focus on results over a single flagship program.

Paul Cheng asked about PBF Energy's 2026 OpEx expectations, specifically whether RBI benefits would offset inflation, higher natural gas prices, and increased throughput, and the sensitivity to natural gas price movements. He also questioned the significant sequential jump in West Coast margin capture from Q3 to Q4 2025, despite an industry margin decline, and what specific operational improvements contributed to this.

Answer

CFO Joe Marino confirmed that RBI savings are net of inflation and embedded in the 2026 guidance, noting that the guidance includes a higher natural gas price assumption compared to 2024. He stated that a $1 increase in natural gas price would equal a $100 million impact on costs. CEO Matt Lucey attributed the West Coast margin improvement to reliable, efficient operations and lower crude costs. He described California as a microcosm of PBF Energy's broader business, with a tight product market and loosening crude market, exacerbated by local refinery closures and the inability to export California crude.

Paul Cheng asked about PBF Energy's OpEx expectations for 2026, specifically whether the continued benefits from the RBI initiative would be sufficient to offset increases from higher throughput (due to Martinez restart), inflation, and higher natural gas prices compared to 2025. He also inquired about the current sensitivity of PBF's cost structure to a $1 move in natural gas prices. Additionally, Mr. Cheng sought to understand the significant sequential jump in West Coast margins from Q3 to Q4, given that industry margins declined and Martinez was still under repair, asking if there were any one-off benefits or specific operational improvements driving this capture increase.

Answer

CFO Joe Marino confirmed that the RBI savings are net of inflation and are embedded in the 2026 OpEx guidance. He noted that the guidance incorporates a higher natural gas price assumption compared to 2024, and normalizing for this would show the RBI savings. Mr. Marino stated that a $1 increase in natural gas price generally equates to a $100 million increase in PBF's cost structure. CEO Matt Lucey attributed the West Coast margin improvement to reliable, efficient operations and lower crude costs, emphasizing that California's market dynamics (tight product, loosening crude) are a microcosm of PBF's broader business, with no specific one-off benefits.

Paul Cheng asked for an outlook on refining OpEx considering the RBI program and questioned the rationale for the high run-rate target at the St. Bernard Renewables (SBR) plant, given market conditions.

Answer

President & CEO Matthew Lucey confirmed that the RBI savings would result in a net reduction to OpEx. Regarding SBR, Lucey explained that the plant is run to maximize profit, leveraging its locational advantages for feedstock and product optionality. He characterized the plant's current profitability as 'somewhat breakeven' due to rising feedstock costs and regulatory uncertainty.

Paul Cheng of Scotiabank asked about the security of the company's dividend in a potential economic downturn and requested guidance on Q2 refining operating costs, as well as the expected run-rate OpEx after the RBI program is fully implemented.

Answer

President and CEO Matthew Lucey characterized the dividend as a 'through-cycle' payment and expressed comfort with its current level. SVP Michael A. Bukowski noted the RBI program's savings target is based on 2023 OpEx and that the program will continue beyond 2025. Management declined to provide specific Q2 California OpEx guidance due to the complexities of the ongoing turnaround and insurance claims.

Paul Cheng of Scotiabank questioned the low Q1 throughput guidance for the East Coast, asked about the operational impact on the Toledo refinery if it replaced Canadian Syncrude with domestic light oil, and inquired about the insurance deductible for the Martinez incident.

Answer

President and CEO Matthew Lucey attributed the lower East Coast throughput guidance to throttling back in a weaker market, not structural issues. He explained that replacing Canadian crude at Toledo is not simple due to pipeline constraints and would negatively impact yields and throughput. He declined to specify the insurance deductible but reiterated it is manageable and coverage is proper.

Paul Cheng asked for an outlook on 2025 capital expenditures, including the minimum required spend in a challenging market, and also inquired about the crack spread environment needed for the company to be cash flow breakeven.

Answer

CFO Karen Davis indicated that while the 2025 CapEx budget is being finalized, a typical range is $750-$800 million, which includes discretionary growth projects and could be reduced if margins weaken. President and CEO Matthew Lucey addressed the breakeven question, stating it's too difficult to isolate a specific crack spread due to other variables like crude differentials and operating costs. He reiterated that in a mid-cycle environment, the business is expected to generate $300-$500 million in free cash flow.

Paul Cheng from Scotiabank asked how BP balances its objective of creating a simpler, streamlined operation with the formation of joint ventures (e.g., Angola, Norway, Castrol), which can introduce complexity.

Answer

Carol Howle, Interim CEO, explained that BP balances these objectives by prioritizing what creates the best value and most efficient execution, drawing on extensive experience with JVs to minimize complexity and improve safety. Kate Thomson, Chief Financial Officer, added that while simplicity is good, unique opportunities to create differential value through asset and partner marriages (like Aker BP and Azule) sometimes justify stepping into complexity, as seen with the Castrol transaction.

Paul Cheng from Scotiabank asked how BP balances its objective of creating a simpler and streamlined operation with the formation of joint ventures (e.g., Angola, Norway, Castrol), and how it manages the inherent complexity of JVs over time.

Answer

Carol Howle, Interim Chief Executive Officer, explained that JVs are balanced by assessing value creation, market opportunities, and efficient execution. She noted BP has learned from past JVs to reduce complexity and improve operations. Kate Thomson, Chief Financial Officer, added that while simplicity is good, unique opportunities can create differential value through asset and partner marriages (e.g., Aker BP, Azule), and the Castrol transaction was chosen for maximum value.

Paul Cheng inquired about the drivers behind BP's exploration success, including processes, personnel changes, repeatability, and whether more capital should be allocated to exploration given the improved success rate.

Answer

Murray Auchincloss (CEO, BP) attributed exploration success to an experienced team, advancements in technology (NVIDIA chips, supercomputing, AI for faster interpretation), and strong engagement with digital tools. While not guaranteeing repeatability, he emphasized maintaining 'quality through choice' by creating many opportunities and high-grading to the best ones. He stated that the current exploration spend of around EUR 600 million per year is appropriate to force quality and would not be pushed up despite recent success.

Paul Cheng asked about the underlying reasons for BP's successful exploration year, including processes and personnel changes, the repeatability of this success, and whether increased capital should be allocated to exploration given the higher success rate.

Answer

Murray Auchincloss (CEO, BP) credited the exploration success to an experienced team, advancements in technology like NVIDIA chips and AI, and the team's engagement with digital tools. He stressed maintaining "quality through choice" and keeping the exploration budget around $600 million annually to ensure capital discipline despite the strong year.

Paul Cheng from Scotiabank requested details on BPX production sources, particularly the Haynesville plan, and asked about the development timeline and cost recovery structure for the recent major discovery in Brazil.

Answer

EVP Gordon Birrell confirmed the Brazil discovery operates under a single cost recovery pool and expects a three or four-well appraisal program will be needed. CEO Murray Auchincloss added that recent BPX growth was driven by the Permian and Eagle Ford, with Haynesville activity being held relatively flat pending decisions on a 2026 ramp-up based on gas price hedging.

Paul Cheng from Scotiabank requested details on BPX production drivers between the Permian and Haynesville, and asked about the development timeline and cost recovery structure for the recent major discovery in Brazil.

Answer

EVP - Production & Operations Gordon Birrell confirmed the Brazil discovery operates under a single cost recovery pool and that a 3-4 well appraisal program will precede any FID decision. CEO Murray Auchincloss added that recent BPX growth came from the Permian and Eagle Ford, while a decision on ramping up Haynesville activity for 2026-27 will depend on gas prices and be made in the fall.

Paul Cheng from Scotiabank asked about the opportunities presented by new downhole co-mingling rules in the Gulf of Mexico and their potential scale. He also inquired about the decision-making process between reducing CapEx versus reducing buybacks in a more challenging commodity market.

Answer

Executive Katherine Thomson reiterated the company's capital allocation priorities: a resilient dividend first, followed by a strong balance sheet, then disciplined CapEx, with buybacks used to distribute surplus cash. She emphasized that the 30-40% of CFFO distribution is a target over time, not a quarterly rule. Executive Murray Auchincloss added that the new Gulf of Mexico rules are primarily relevant for the Paleogene, where developments like Cascade will come later in the decade.

Paul Cheng from Scotiabank asked which specific business areas were causing the 2025 EBITDA to track slightly below the initial target range.

Answer

CFO Katherine Thomson identified two main areas: suppressed bio margins in Europe due to mandate rollbacks and oversupply, and a slower-than-expected recovery from the trucking recession impacting the recently acquired TravelCenters of America (TA).

Paul Cheng asked about ConocoPhillips' capital allocation strategy post-2030, considering the maturing nature of shale oil and how the company plans to position itself for long-term growth.

Answer

Ryan Lance, Chairman and CEO, affirmed that ConocoPhillips has over two decades of low-cost supply inventory in the Lower 48, ensuring its shale business will not mature in 5 years. He noted that major project capital spend will roll off post-2030, while unconventional investments will continue to grow through efficiencies. The company sees broad investment optionality in Alaska, Canada, Equatorial Guinea, and Libya, positioning it for modest, organic growth well into the future, supported by constructive long-term demand growth.

Paul Cheng questioned ConocoPhillips' long-term capital allocation strategy and positioning beyond 2030, considering the perceived maturity of shale oil and the company's large scale.

Answer

Ryan Lance, Chairman and CEO of ConocoPhillips, countered the notion of shale oil maturity within their portfolio, stating they possess over two decades of low-cost supply inventory in the Lower 48. He explained that while major project capital spend will roll off by the end of the decade, unconventional investments will continue to grow through efficiency gains. He emphasized diverse global opportunities in Alaska, Canada, Equatorial Guinea, and Libya, providing optionality for modest growth post-2030, supported by a constructive long-term demand outlook.

Paul Cheng of Scotiabank asked for the long-term outlook for the Eagle Ford asset, given the expanded resource base and strong performance following the Marathon acquisition.

Answer

EVP Nick Olds highlighted the asset's strong Q2 performance, noting that legacy Marathon wells are performing at or above type curve. He emphasized that the combined entity now holds an industry-leading 15 years of Tier 1 inventory at current activity levels. While the optimal long-term production plateau is still being assessed, he indicated near-term production would likely settle modestly below the Q2 peak.

Paul Cheng questioned whether ConocoPhillips should more aggressively diversify away from the Lower 48 due to industry concerns about shale inventory maturity, and what asset types it might target.

Answer

Chairman and CEO Ryan Lance stated that the company's 'North Star' is low cost of supply, regardless of geography or commodity. While they value portfolio diversity, he noted the bar for inorganic acquisitions is very high given their existing deep, high-quality inventory. The primary focus remains on executing the current plan across their global asset base rather than pursuing diversification for its own sake.

Paul Cheng from Scotiabank inquired about the Tier 1 inventory running room in the acquired Marathon assets, particularly in the mature Eagle Ford and Bakken basins, and asked about the game plan for Equatorial Guinea.

Answer

CEO Ryan Lance addressed Equatorial Guinea, stating they are pleased with the cash flow and contracts, and have not changed Marathon's near-term plans, which include infill drilling. EVP Nick Olds discussed the inventory, confirming the quality is unchanged from the acquisition case, with 2,000 competitive well locations at a sub-$40/bbl cost of supply. Roughly half are in the Eagle Ford, with the rest split between Bakken and Delaware. He added that combining acreage is creating more opportunities for long laterals in the Bakken.

Paul Cheng asked about the expected plateau production rate for the Permian Basin and its timing, as well as the outlook for supply chain costs in 2025 compared to 2024.

Answer

Nick Olds, EVP of Lower 48, stated that with two decades of inventory, the Permian is not expected to plateau until into the second decade, with modest 4-5% growth continuing for 10 years. On costs, Chairman and CEO Ryan Lance described a mixed environment with some deflation (rigs, pumping) and inflation (labor, chemicals), but the overall feel for 2025 is 'somewhat similar' to 2024.

Paul Cheng asked about the attractiveness of new opportunity sets in Iraq, Libya, and Venezuela for Shell, and whether the opening of these countries raises concerns about oil market oversupply and its potential impact on Shell's capital allocation outlook.

Answer

CEO Wael Sawan stated that Shell anticipates continued growth in energy and oil demand through 2050, with 5% annual depletion requiring significant refilling. He expressed no concern about oversupply from these countries, as the world will need the production. Sawan highlighted Shell's strong position and ongoing discussions in Kuwait, Libya, Venezuela, and Iraq, emphasizing a selective approach based on risk-adjusted returns for capital deployment, maintaining a bullish and constructive long-term outlook on oil.

Paul Cheng asked about Shell's view on new opportunity sets in countries like Iraq, Libya, and Venezuela, and whether the potential opening of these markets raises concerns about oil market oversupply, impacting Shell's capital allocation outlook.

Answer

CEO Wael Sawan expressed a constructive long-term outlook for oil, citing continued energy demand growth and the need to refill 6 million bbl/day annually due to depletion. He acknowledged short-term supply length balanced by geopolitical risks. Sawan noted Shell's strong position and ongoing discussions in Iraq, Libya, and Venezuela, particularly on the gas side, but emphasized that investment decisions would depend on risk-adjusted return profiles and the ability to deploy capital effectively, without changing the bullish long-term oil fundamentals.

Paul Cheng questioned whether Shell's exploration program is appropriately sized to sustain liquids production or if it needs to be increased. He also asked how the trading business manages geopolitical uncertainty, such as unpredictable political tweets, and if this necessitates a lower-risk, lower-return approach.

Answer

CEO Wael Sawan stated the exploration program is 'right-sized' following a significant reset, with a refocused effort on basins with established track records like the Gulf of Mexico. CFO Sinead Gorman responded that managing uncertainty is where a high-quality trading team matters. She noted the team makes prudent calls quarter-by-quarter, as seen with crude in Q2, but the medium-term guidance for ROACE uplift from trading remains unchanged.

Paul Cheng questioned if Shell's exploration program is appropriately sized to sustain liquids production and asked how the trading business manages geopolitical risks from unpredictable political events.

Answer

CEO Wael Sawan affirmed the exploration program is "right-sized" following a reset, with a focus on advantaged basins and exciting wells planned. CFO Sinead Gorman stated that managing geopolitical risk is a core strength of their high-quality trading team, which makes prudent, quarter-by-quarter judgments, such as de-risking in crude this quarter.

Paul Cheng questioned if Shell's corporate culture is sufficiently transformed to handle a large acquisition and asked which would be prioritized for cuts in a sustained low oil price scenario: buybacks or CapEx.

Answer

CEO Wael Sawan stated that while the 'winning performance culture' has seen excellent progress, more work is needed before considering a sizable inorganic move. Executive Sinead Gorman explained that at $50 oil, Shell would continue buybacks and slightly pull back on CapEx. At $40, the dividend would be covered, and the focus would remain on maintaining buybacks for as long as possible, given their accretive value at a lower share price.

Paul Cheng of Scotiabank asked if Shell should reconsider its flat liquids production target in light of rising global oil demand. He also inquired about the operational status of the Monaca chemicals plant and potential for further improvements.

Answer

CEO Wael Sawan reiterated Shell's commitment to its value-over-volume strategy, maintaining a flat liquids production target through 2030 to focus on high-margin assets. He confirmed the Monaca chemicals plant has achieved stable production across all three polyethylene trains, with future improvements focused on high-grading the product slate and reducing costs.

Paul Cheng inquired if Phillips 66, with its improving refining operations, sees itself as a potential consolidator in the refining industry and what criteria it would use for acquisitions. He also asked if the company is maxing out its heavy oil processing capability in Q1 and if increased heavy oil processing impacts light product yield or overall throughput.

Answer

Mark Lashier, Chairman and CEO, acknowledged the improving refining performance, noting it's a result of a four-year strategic effort with more to come. He stated that M&A could play a role for the right value creation opportunities, particularly in the Mid-Continent or Gulf Coast, though such assets are rare. He confirmed that Phillips 66 is currently maxed out on heavy oil processing, which does impact clean product yield but is economically beneficial.

Paul Cheng asked if Phillips 66, with its improved refining operations, sees itself as a potential consolidator in the refining industry and what criteria it would use for acquisitions. He also inquired about the company's heavy oil processing capacity, its utilization in Q1, and the impact of increased heavy oil processing on light product yield and overall throughput.

Answer

Mark Lashier, Chairman and CEO, confirmed that Phillips 66 is currently maximizing heavy oil processing, acknowledging an impact on clean product yield that is economically beneficial. Regarding M&A, he stated that while such opportunities are rare, Phillips 66 would consider 'unicorn' acquisitions that add to its competitive advantage, particularly in the Mid-Continent or Gulf Coast, citing the WRB acquisition as an example of value creation.

Paul Cheng of Scotiabank questioned the operating strategy for renewable diesel given weak margins and asked about the long-term strategic fit of the marketing businesses in California and Europe.

Answer

EVP of Marketing & Commercial Brian Mandell confirmed that the Rodeo facility will likely run at reduced rates in Q3, depending on market conditions. Chairman & CEO Mark Lashier and Mandell explained the California strategy involves backfilling supply with imports, supported by state authorities. Regarding Europe, Lashier noted that while some assets are being divested, the Humber refinery in the UK remains a strong, strategic position for the company.

Paul Cheng asked for clarification on the integration benefits of the CPChem joint venture, given its separate management, and questioned whether the company should adopt a more conservative financial policy in light of potential macroeconomic volatility.

Answer

Mark Lashier, Chairman and CEO, explained that despite being a JV, there are significant operational synergies with CPChem, particularly at the highly integrated Sweeny complex, which avoids frictional costs. Kevin Mitchell, CFO, addressed the financial policy question by stating that the current framework is balanced and designed to work through cycles. He asserted that the company's $17 billion debt target is well-supported by the stable cash flows from the Midstream and Marketing businesses, making the policy robust even in a volatile environment.

Paul Cheng asked management to prioritize between the $17 billion debt reduction target and pursuing large, accretive bolt-on acquisitions. He also asked whether the company would begin recording benefits from the PTC for its RD business in Q1, given regulatory uncertainty.

Answer

CFO Kevin Mitchell clarified the debt reduction target is achievable given cash flow flexibility and asset sale proceeds, and that a large acquisition would be evaluated at the time. CEO Mark Lashier added that EBITDA growth targets are organic. On the PTC, Mitchell explained that due to significant uncertainty, the company is still evaluating whether to record any benefits in Q1 or wait for more clarity.

Paul Cheng of Scotiabank asked about the long-term cash balance target, the shareholder return policy, and the scope of the company's WTI hedging activities.

Answer

CFO Kevin Mitchell clarified the ideal cash balance is $2B-$3B and affirmed that a shareholder return of 50% or more of operating cash flow remains a reasonable objective. Brian Mandell of Marketing and Commercial explained that while they use WTI hedges in all regions, the accounting impact was most pronounced in the Central Corridor due to volumes and the price move.

Paul Cheng asked about Chevron's view on opportunities in Libya and Iraq, where competitors are making moves, and how Chevron's smaller LNG portfolio size fits into its long-term strategy compared to peers.

Answer

Chairman and CEO Mike Wirth acknowledged recent engagement in Libya and Iraq, noting improved fiscal terms and increased inbound inquiries. He stated Chevron seeks compelling value and will remain disciplined on capital, deploying resources to the highest return opportunities. Regarding LNG, he explained Chevron's strategy includes U.S. offtake without capital deployment and a selective approach to adding projects that deliver competitive returns.

Paul Cheng asked about Chevron's view on opportunities in Libya and Iraq, where competitors are making moves, and how Chevron's smaller LNG portfolio fits into its long-term strategy compared to peers.

Answer

Chairman and CEO Mike Wirth acknowledged recent engagement in Libya (MOU signed) and Iraq, noting that improved fiscal terms are making these resource-rich countries more competitive for investment. He emphasized discipline in capital allocation, seeking the highest returns. Regarding LNG, he explained Chevron's strategy includes US offtake without deploying capital, leveraging its gas position and credit, and only pursuing projects that deliver competitive returns.

Paul Cheng from Scotiabank asked about the future importance of exploration in Chevron's portfolio, given that 40% of production is now from U.S. shale, and questioned satisfaction with recent exploration results and any planned changes.

Answer

Chairman & CEO Michael Wirth acknowledged dissatisfaction with recent results but noted investment had been narrowed. Vice Chairman Mark Nelson added that while the philosophy of a balanced portfolio remains, they are 'opening the aperture.' He highlighted recent success in infrastructure-led exploration and a 20% increase in frontier acreage, with wells planned in Suriname, Namibia, and Egypt.

Paul Cheng requested an update on the Aphrodite gas project in Cyprus, including the timeline, next steps, and project scale, following a recent agreement with the government.

Answer

CEO Mike Wirth confirmed an agreed field development plan for Aphrodite, a legacy Noble Energy asset. The initial phase involves a floating production unit targeting about 800 million cubic feet of gas per day, flowing to Egypt. The project entered pre-FEED in Q1, with further commercial work needed before a final investment decision (FID).

Paul Cheng asked about Chevron's long-term growth opportunities beyond 2026, excluding the Hess acquisition, with a specific focus on the development pipeline in West Africa, including Nigeria and Angola.

Answer

CEO Mike Wirth outlined several post-2026 growth drivers, including major chemical projects, Eastern Mediterranean expansions, and potential in Argentina. He highlighted West Africa as having significant 'running room,' citing a recent discovery in Nigeria, gas projects in Angola, and untapped deepwater prospects.

Paul Cheng of Scotiabank noted the excellent turnaround performance at TCO and Gorgon and asked if this was a one-off success or the result of a repeatable process change that could yield future benefits.

Answer

CEO Mike Wirth and CFO Eimear Bonner confirmed it is the result of a repeatable process. Bonner detailed a standardized approach across upstream and downstream, focusing on rigorous scope management, digital planning tools, equipment-level benchmarking, and sharing expert resources. Wirth provided specific metrics, such as a 14% duration improvement for the Gorgon turnaround and a 23% improvement for TCO.

Paul Cheng inquired about ExxonMobil's base underlying decline rate for its upstream portfolio and the expected needed downtime/available uptime for its manufacturing operations (refining/chemical), seeking opportunities for improvement over the next five years.

Answer

CEO Darren Woods stated that ExxonMobil is at the beginning of unlocking the full potential of its transformation, with technology expected to continue offsetting depletion and driving production growth beyond 2030. He did not provide a specific base decline rate. For manufacturing, Woods highlighted the newly formed global operations organization, which builds on previous centralized support that improved maintenance costs, reliability, and safety. He anticipates continued improvements in reliability, availability, and uptime across the portfolio, leading to lower costs and better cycle management, with significant upside expected from these new organizations.

Paul Cheng asked about the base underlying decline rate for ExxonMobil's upstream portfolio, the expected downtime/available uptime in manufacturing operations, and the biggest opportunities for improvement over the next five years.

Answer

CEO Darren Woods stated that ExxonMobil is early in capturing the full potential of its transformation, continuously improving recovery and offsetting depletion through technology. He noted that the newly formed Global Operations organization will enhance reliability, availability, and uptime across Product Solutions manufacturing facilities, building on prior improvements in maintenance costs and safety. He anticipates significant upside across the entire portfolio from centralized organizations.

Paul Cheng asked if ExxonMobil's recent cost and headcount reductions, alongside numerous ongoing projects, indicate that the company is running up against its organizational capability, or if its ability to increase investment pace is limited only by opportunity set.

Answer

Darren Woods, Chairman and CEO, clarified that the reductions are part of a continuous transformation to improve effectiveness and efficiency, resulting in over $14 billion in structural cost reductions since 2019. He stated that the company is not at its organizational limit, and its ability to invest is primarily constrained by the high criteria for advantaged, resilient projects. He cited the successful delivery of 8 out of 10 key projects (totaling $50 billion gross capital) as proof of execution capability, further enhanced by tools like the Discovery six supercomputer. Kathryn Mikells, Senior Vice President and CFO, emphasized their unmatched track record in driving efficiencies.

Paul Cheng asked if ExxonMobil's recent cost and headcount reductions, combined with numerous ongoing projects, indicate that the company is running up against its organizational capability limits. He questioned if the ability to increase investment pace is limited by opportunity set or capability.

Answer

Darren Woods, Chairman and Chief Executive Officer, clarified that reductions are part of a continuous effort to improve effectiveness and efficiency, leading to over $14 billion in structural cost reductions since 2019. He stated that the company's capability is currently limited by the high criteria for advantaged projects, not by organizational capacity, citing the successful delivery of 10 major projects with $50 billion in gross capital.

Paul Cheng from Scotiabank inquired about the potential impact of AI and robotics on ExxonMobil's operations, asking where the biggest opportunities lie and how these technologies could provide a competitive advantage.

Answer

Chairman and CEO Darren Woods highlighted that ExxonMobil is well-positioned to leverage AI due to its centralized technology organization and a new corporate-wide ERP system that provides a consistent data architecture. He stated the initial focus is on improving effectiveness—such as finding oil cheaper and creating better products—rather than just cost efficiency. This approach, combined with a vast dataset, is expected to be a key differentiator.

Paul Cheng asked why ExxonMobil has a relatively small presence in the deepwater Gulf of Mexico and if a new administration's policies could change that.

Answer

CEO Darren Woods explained that their limited presence is a result of evaluating opportunities there against a global portfolio, with factors like development costs and challenging geology making it less competitive. He stated the company is location-agnostic and focuses strictly on finding advantaged barrels with low cost of supply and high returns. If new areas in the Gulf of Mexico meet these criteria, they will be considered.

Paul Cheng asked why ExxonMobil has a relatively small presence in the deepwater Gulf of Mexico compared to its size and success elsewhere, and if a new administration could change that.

Answer

CEO Darren Woods explained that the limited presence is a result of their disciplined evaluation process; opportunities in the Gulf of Mexico have historically not met their strict criteria for cost of supply and geology compared to other global prospects. He stated they are location-agnostic and will evaluate any newly opened areas against the same rigorous standards for advantaged returns.

Paul Cheng asked about Valero's exposure to the ongoing labor contract negotiations with the USW, specifically which refineries are under contract and the potential impact of a strike. He also inquired about whether Valero's refinery utilization rates have structurally shifted higher due to improved operations, and if there was any noticeable downtime from the recent winter storm.

Answer

R. Lane Riggs (Chairman, CEO and President, Valero Energy Corporation) declined to disclose specific unionized sites but noted Valero is less unionized than many competitors. Gary Simmons (EVP and COO, Valero Energy Corporation) acknowledged record mechanical availability but found it difficult to quantify a structural shift in maximum utilization, noting strong Q4 margins and moderate temperatures allowed higher utilization. He reported minimal material impact from the winter storm, mostly external interruptions rather than refinery unit issues.

Paul Cheng inquired whether new technologies like AI and robotics represent an evolution or a transformative shift in how Valero conducts business, not just in refining but also in back-office and commercial operations, similar to cost reductions seen in upstream counterparts.

Answer

Greg Bram, Vice President, Valero Energy Corporation, stated that Valero has been expanding the use of these techniques for efficiency for some time, viewing it as an ongoing evolution. He believes new technologies will create more opportunities for improvement, particularly given Valero's strong foundation of operational data. Lane Riggs, Chairman, CEO and President, added examples like robotics in tank cleaning and drones for inspection, noting efforts to consolidate control rooms for operator efficiency.

Paul Cheng of Scotiabank asked how an increase in Saudi medium sour crude supply would impact global distillate yields and whether it remains economic to export renewable diesel from DGD to Europe given U.S. tax incentives.

Answer

VP Greg Bram and CEO Lane Riggs explained that while more medium sour crude would increase global distillate supply, its value depends on whether it meets high-spec market requirements. SVP Eric Fisher stated that exporting renewable diesel remains attractive as markets like Europe prefer the low-CI feedstocks DGD uses, and the global market is still adjusting to new policies.

Paul Cheng of Scotiabank asked how an increase in medium sour crude from Saudi Arabia might impact global distillate yields. He also inquired about the current economics of exporting renewable diesel from the DGD facility to Europe, given recent policy changes like the PTC.

Answer

VP of Refining Services Greg Bram and CEO Lane Riggs acknowledged that more medium sour crude would increase distillate production, but its value depends on meeting high-spec market requirements. SVP Eric Fisher explained that exporting renewable diesel remains economic, as premium markets like Europe and Canada still demand low-CI feedstocks, but feedstock prices must adjust to new policies to fully reflect market dynamics.

Paul Cheng from Scotiabank asked about the timing of the last major turnaround at the Wilmington refinery and inquired about the production outlook for Sustainable Aviation Fuel (SAF) and plans for a second unit.

Answer

An executive confirmed a recent FCC unit turnaround but declined to comment on future plans. Eric Fisher, EVP of Commercial, explained that SAF is not yet in max production mode as some barrels are more economic as renewable diesel. He stated that more market development and policy certainty are needed before committing to a second SAF unit, as the PTC alone is insufficient.

Paul Cheng asked about the timing of the last major turnaround at the Wilmington refinery and inquired about the production expectations and economics for Sustainable Aviation Fuel (SAF) in the second quarter.

Answer

An executive confirmed a recent turnaround on the FCC unit at Wilmington but declined to comment on future turnaround plans. Eric Fisher, an executive, explained that SAF production is not yet in max mode as some barrels are more economic as renewable diesel for Europe. He stated that while interest in SAF is growing, the current PTC incentive is not adequate by itself to justify a new project, and the market needs to develop further before a second unit would be considered.

Paul Cheng asked how Valero will account for the new production tax credit (PTC) in Q1 results and the size of the Q4 inventory benefit in renewable diesel. He also inquired about opportunities to further reduce energy costs.

Answer

Lane Riggs, CEO, clarified that no provisional benefit for the PTC will be recorded in Q1 unless there is clear policy; financials are based on actuals. Eric Fisher, an executive, declined to quantify the inventory benefit. Greg Bram, an executive, stated that with low U.S. natural gas prices, there is little incentive for major energy-reduction capital projects in North America.

Paul Cheng of Scotiabank asked for the timeline of the next major capital outlay at the Benicia refinery that might force a strategic decision, and inquired about the drivers of the North Atlantic segment's strong margin capture.

Answer

CEO Lane Riggs confirmed that major capital outlays are key decision points but declined to provide a specific turnaround schedule, citing company policy. Executive Greg Bram attributed the strong North Atlantic performance to successful commercial team efforts and favorable crude costs, including access to advantageous Canadian grades for the Quebec refinery and favorable pricing relative to Dated Brent.

Paul Cheng inquired about the Hai Su Vang 2X stem test's 12,000 barrels per day flow rate, specifically whether it was equipment-constrained or a natural flow rate. He also asked about the flexible portion of Murphy Oil's 2026 CapEx and the company's ability to adjust spending if market conditions require.

Answer

Eric Hambly (President and CEO) clarified that the 12,000 barrels per day rate from the Hai Su Vang 2X well's primary reservoir was the natural flow rate, not facility-constrained, indicating high productivity. He detailed that 2026 CapEx flexibility is limited due to strategic investments in Lac Da Vang development, Côte d'Ivoire exploration, Hai Su Vang appraisal, and the Chinook development well. Hambly estimated a potential 10% reduction in 2026 CapEx, with significantly more flexibility (30-40% reduction) for 2027 if needed.

Paul Cheng inquired about the Hai Su Vang 2X stem test's 12,000 barrels per day flow rate, asking if it was equipment-constrained or a natural flow rate. He also asked what portion of the 2026 capital expenditure is considered flexible, given the company's readiness to adjust spending if market conditions require.

Answer

Eric Hambly, President and CEO, and Atif Riaz, VP, Investor Relations and Treasurer, clarified that the 12,000 bpd flow rate from the Hai Su Vang 2X well was a natural flow rate, not facility-constrained, indicating high reservoir productivity compared to the basin's typical 2,000 bpd. Regarding CapEx flexibility, they stated that significant investments in Lac Da Vang, Côte d'Ivoire exploration, Hai Su Vang appraisal, and the Chinook development well are largely committed due to their strong value creation. While 2026 flexibility is limited to about a 10% reduction, primarily in onshore activities weighted to the first half, greater flexibility (30-40% reduction) would be available for the 2027 capital program if needed.

Paul Cheng inquired about the potential U.S. cash tax impact from new legislation, whether strong Eagle Ford productivity would alter the asset's development pace, and if high well performance in the Tupper Montney is sustainable.

Answer

EVP & CFO Thomas Mireles estimated a future tax shield of $40-50 million annually from the new legislation. President, CEO & Director Eric Hambly stated the Eagle Ford strategy remains unchanged, prioritizing offshore investment. He also expressed confidence that the strong Montney well results are repeatable in the near-to-mid term due to geology and optimized designs.

Paul Cheng questioned the prudence of executing a $100 million share buyback in a free cash flow negative quarter, potentially funded by debt. He also asked for the rationale behind the seller's decision in the highly favorable BW Pioneer FPSO acquisition.

Answer

President and CEO Eric Hambly defended the buyback as an opportunistic move made when oil prices were higher and shares appeared undervalued, but stressed a commitment to protecting the balance sheet going forward. Regarding the FPSO, Hambly explained it was a win-win deal where the seller received needed cash and certainty, while also securing a contract to continue operating the vessel for Murphy.

Paul Cheng from Scotiabank asked for specifics on workover expenses for Q4 2024, Q1 2025, and Q2 2025. He also questioned the path to achieving the previously targeted production level of over 210,000-220,000 BOE/d by 2026-2027, given the current CapEx guidance and production outlook for individual assets.

Answer

President and CEO Eric Hambly framed the workover impact in terms of operating expenses, projecting an elevated $15-$16 per barrel in Q1, normalizing to a $10-$12 per barrel range for the rest of the year as production increases. He reaffirmed the company's path to exceeding 200,000 BOE/d, citing high-rate, high-ownership Gulf of Mexico wells coming online in 2026, a steady execution of subsea tieback projects, and the ramp-up of Lac Da Vang production from late 2026 through 2029.

Paul Cheng asked about the future pace of share buybacks, questioning if it would remain significantly above the 50% adjusted free cash flow minimum. He also asked if the high level of Gulf of Mexico workovers in 2024 was due to bad luck or a systemic issue.

Answer

CEO Roger Jenkins stated that while it's hard to predict, the company would consider repurchasing more than the 50% minimum if the stock remains undervalued in the low $30s, though paying out over 100% of free cash flow is not sustainable long-term. President and COO Eric Hambly attributed the high number of workovers in 2024 to being 'purely unlucky,' calling it a challenging and unusual year and not indicative of a systemic problem.

Paul Cheng sought clarification on Occidental's 2026 capital expenditure, specifically whether the $250 million redirection from Low Carbon Ventures (LCV) to Gulf of America and Oman implies zero LCV spending. He also asked about the expected production contribution from the $400 million QuickPayback onshore project in 2026 and if exploration would remain a less significant aspect of the program given increased onshore resource findings.

Answer

Sunil Mathew (SVP and CFO) clarified that LCV capital expenditure for 2026 would be approximately $100 million. Richard Jackson (SVP and COO) explained that the $400 million onshore investment aims to maintain flat activity year-over-year, with EOR capital being light and efficient. Ken Dillon (SVP and President, International Oil and Gas Operations) indicated that exploration efforts are shifting, with Oman's focus on step-out wells near existing facilities rather than large-scale exploration.

Paul Cheng asked if activity in Oman is currently constrained by capital and what the potential long-term scale of the Oman business could be once the balance sheet is strengthened.

Answer

President & CEO Vicki Hollub clarified that the primary constraints are the oversupplied oil market and the company's focus on debt reduction, not a lack of competitive projects. For the long term, capital allocation will follow a value proposition of dividends, debt reduction, and buybacks. SVP Kenneth Dillon added that efficiency gains and partnership opportunities in Oman could accelerate projects without tapping into company capital.

Paul Cheng of Scotiabank asked about the potential for cost-saving momentum to continue into 2026-2027 and whether Occidental plans to increase international activity given its view that U.S. production may peak sooner than expected.

Answer

CEO Vicki Hollub provided a detailed overview of the company's portfolio transformation over the last decade, shifting towards U.S. shale while retaining significant conventional resources. She highlighted growth potential in the Gulf of America, Algeria, and Oman, suggesting the company has a deep inventory of both shale and conventional resources to develop, which will be further enhanced by DAC-enabled EOR, extending development potential well beyond 15 years.

Paul Cheng requested clarification on whether the Permian oil cut is expected to be higher in 2025 and the drivers for this change. He followed up by asking for the percentage of the 2025 Permian program focused on secondary benches compared to 2024.

Answer

Richard Jackson, President, U.S. Onshore Resources and Carbon Management, confirmed the Permian oil cut is improving, tracking unconventional growth and the mix from the CrownRock assets. Sunil Mathew, SVP and CFO, added that growth from the Permian and Gulf of America will increase the total company oil cut to 52%. Jackson specified that secondary benches in the Delaware will comprise about 30% of the 2025 program, up from 25% in 2024, delivering better returns by leveraging existing facilities.

Paul Cheng from Scotiabank sought details on the drivers for the 2024 CapEx increase and the expected incremental capital from CrownRock in 2025. He also asked if the Q3 drop in the Permian oil cut was a one-off event.

Answer

Sunil Mathew, SVP and CFO, clarified that the 2024 incremental capital was for CrownRock operations post-acquisition and estimated the 2025 capital for those assets would be in the $900-$950 million range for a 5-rig program. Richard Jackson, President of U.S. Onshore, explained the lower oil cut was not a one-off but driven by a strategic increase in secondary bench development and overall unconventional production growth, with the back-half percentage being a good indicator for the near term.

Paul Cheng asked about the quantitative impact of inventory build on Marathon Petroleum's Q3 margin capture, seeking a dollar per barrel or percentage figure. He also questioned MPC's strategy regarding new pipeline proposals in California and whether the company plans to be an active and aggressive importer of refined products into the California market.

Answer

CFO John Quaid estimated the inventory build's impact on capture to be closer to 3-5%, driven by LPGs for blending and VGO ahead of FCC turnarounds. CCO Rick Hessling stated that a potential MidCon pipeline into California would be bullish for MPC due to their MidCon assets, but noted significant 'ifs' regarding its realization. He indicated that while MPC would evaluate waterborne trading opportunities, it would not be a primary focus, emphasizing optimizing their integrated West Coast and Pacific Northwest value chain.

Paul Cheng asked for quantification of the inventory build's impact on margin capture in Q3, either in dollar per barrel or percentage. He then followed up on California's new pipeline proposals and Marathon Petroleum's strategy regarding waterborne product imports into the California market.

Answer

CFO John Quaid estimated the inventory build's impact on capture to be closer to 3-5%, driven by LPG builds for blending season and VGO ahead of FCC turnarounds. CCO Rick Hessling stated that a pipeline from the Midcon to California would be positive for MPC, given its Midcon refining capacity, but noted significant 'ifs' regarding its feasibility and cost. He indicated that while MPC has a commercial advantage with its LA and Pacific Northwest assets, being a primary waterborne importer is not their current focus, though they would evaluate trading opportunities. CEO Maryann Mannen added that the Q3 capture change was largely market-driven volatility.

Paul Cheng asked about the opportunities for Marathon's system from pending California refinery closures and whether the current high turnaround expense represents a cycle peak.

Answer

CEO Maryann Mannen highlighted MPC's competitive West Coast position and recent investments. CCO Rick Hessling noted opportunities from advantaged local crudes and leveraging their integrated system to supply markets like Phoenix. Regarding expenses, CFO John Quaid suggested the current $1.4B turnaround cost might be a peak due to a post-COVID backlog and should normalize in coming years.

Paul Cheng asked how Marathon's 'wellhead-to-water' NGL strategy differs from peers and about the risks of a consensus-driven investment rush. He also questioned what internal initiatives are underway to improve the renewable diesel business's profitability and reliability following Q1 outages.

Answer

CEO Maryann Mannen differentiated their NGL strategy by highlighting their confidence in filling new fractionators with their own processed volumes, displacing third-party usage, and leveraging their commercial expertise. On renewable diesel, CFO John Quaid stated that operational issues from Q1 were addressed and the focus is on optimizing feedstock, leveraging the new pretreat unit, and taking action to realize 45Z tax credits, which were a headwind in Q1.

Paul Cheng questioned whether the projected $1.4 billion in annual turnaround costs represents a new normal for the company. He also sought to understand the drivers behind the strong margin capture in California, asking if there were any one-off items contributing to the performance.

Answer

CFO John Quaid explained that the $1.4 billion turnaround cost reflects the current cycle, which has been influenced by deferred work from the COVID era and changes in asset capacity, but stopped short of calling it a new normal run-rate. Regarding California's performance, Quaid and executive Rick Hessling credited strong operational execution and the company's fully integrated "refinery to retail" value chain, which they see as a key differentiator that allows them to capture value others cannot, rather than any specific one-off items.

Paul Cheng asked for a breakdown of the better-than-expected Q3 throughput, questioning how much was due to improved turnaround execution versus base operations and if the improvement is repeatable. He also inquired about the path to profitability for the Martinez renewable diesel business.

Answer

Executive Timothy Aydt attributed the strong turnaround performance to best-in-class, consistent processes across all facilities and the benefits of scale, noting outstanding safety results. CEO Maryann Mannen stated that while the Martinez facility ramp-up impacted West Coast profitability, it is expected to be profitable at its full nameplate capacity of ~48,000 bpd by year-end. CFO John Quaid added that the market will ultimately balance the BTC-to-PTC transition.

Paul Cheng from Scotiabank asked to frame EOG's ongoing cost-reduction efforts and their potential free cash flow impact. He also inquired about EOG's view on the longevity of U.S. shale inventory at current commodity prices.

Answer

CEO Ezra Yacob responded that cost reduction is a continuous process at EOG, with results evident in its strong dividend growth and balance sheet. He asserted that while the broader industry may struggle at current prices, EOG's scale and technology, including generative AI, will continue to lower breakevens and unlock resources, distinguishing it from peers.

Paul Cheng inquired about EOG's strategic preference between share buybacks and M&A during a market downturn, given the current landscape for quality assets. He also asked for the long-term (5-year) vision for the Trinidad asset and whether management desires a larger international presence in its portfolio.

Answer

CEO Ezra Yacob stated that buybacks and M&A are not mutually exclusive, citing the recent share repurchases and the Eagle Ford bolt-on as examples of executing on both. Regarding Trinidad, he highlighted the consistent investment and competitive returns driven by over 30 years of operational expertise in the region, without specifying a target for international portfolio growth.

Paul Cheng of Scotiabank questioned the organizational and equipment constraints for accelerating the gas program in Egypt. He also asked for the primary sources of potential upside to the company's $350 million cost savings target.

Answer

CEO John Christmann and President Stephen Riney confirmed they have the organizational capacity for the Egypt gas program, with the main constraint being in-field gathering infrastructure rather than processing capacity. For cost savings, CFO Ben Rodgers identified G&A simplification as a key upside driver. Riney added that significant opportunities remain in improving Capital efficiency in the Delaware Basin and, most notably, in reducing LOE through projects like water disposal and compression optimization.

Paul Cheng of Scotiabank inquired about capital allocation flexibility in Egypt between gas and oil based on commodity prices and asked what price environment would make Alpine High attractive again. He also asked at what oil price APA would implement more drastic capital cuts.

Answer

CEO John Christmann confirmed a clear shift toward more attractive gas development in Egypt as oil prices have softened. President and CFO Steve Riney noted that Alpine High drilling must compete economically based on Waha pricing, and a rig would be considered when returns are competitive with Permian oil. Regarding a floor for activity, Christmann suggested that a WTI price in the 'very low 50s' would prompt a review of the capital program, potentially leading to rig reductions.

Paul Cheng asked what operational or technological processes APA learned from Callon during the integration and which specific prospect was being targeted in the upcoming Alaska drilling program.

Answer

CEO John Christmann noted that while APA's supply chain has driven down well costs, they are closely analyzing Callon's technical data, particularly regarding well spacing. CFO Stephen Riney added this is an opportunity to re-evaluate their own development assumptions, which could yield future capital efficiency gains. John Christmann clarified the Alaska well will target the Saki prospect.

Paul Cheng from Scotiabank asked if the company's positive comments on the Anadarko basin suggest it could be an area of interest for M&A. He also inquired if there is a target percentage of gas volumes the company would like to have under power netback contracts.

Answer

CEO Thomas Jorden praised the Anadarko asset's productivity and profitability but declined to comment on M&A in any specific area. EVP of Operations Blake Sirgo stated there is no specific target for power contracts; instead, the company dynamically balances long-term sales that offer diversity and price enhancement against future growth plans.

Paul Cheng asked about the maximum potential production from the Marcellus given its inventory life, and requested guidance on the quarterly trend for well completions and CapEx.

Answer

Chairman, CEO and President Thomas Jorden reiterated that the company manages for returns, not production, and does not foresee a return to high growth rates of the past, though slow single-digit growth is possible. SVP of Operations Blake Sirgo declined to give specific quarterly guidance but noted Marcellus activity would have some lumpiness while Permian activity would be steady.

Paul Cheng asked for clarification on the flexibility of the new LNG sales contracts and whether the Matterhorn pipeline would be sufficient to normalize Waha gas prices.

Answer

An executive stated they could not provide specific details on the LNG contracts but reiterated they are direct netback sales deals. Blake Sirgo, SVP of Operations, commented that while the Matterhorn pipeline helps, it is not a final solution for Waha pricing, as continued gas production growth in the Permian will require further infrastructure development.

Paul Cheng from Scotiabank asked about the financial impact of building excess inventory during the Coffeyville turnaround and whether this strategy could be optimized in the future. He also requested a preliminary outlook for 2026 capital expenditures and turnaround spending.

Answer

CEO David Lamp explained that building inventory is a strategic choice to maintain operational flexibility against unforeseen events. CFO Dane Neumann quantified the negative impact on the Q2 capture rate at approximately 7% to 9% due to the timing of sales versus market conditions. Regarding 2026, Neumann stated that while official guidance is forthcoming, capital spending is not expected to be exceptional, and no major turnarounds are planned until 2027.

Paul Cheng from Scotiabank sought clarification on the surprisingly strong Q1 renewable diesel gross margin, given the loss of the Blenders Tax Credit (BTC), and asked about the company's current M&A strategy.

Answer

CFO Dane Neumann attributed the strong renewables margin to several factors, including a $0.14/gallon favorable hedge, a lift from higher RIN prices, and improved feedstock basis, but cautioned that some items were exceptional and may not represent a new baseline. CEO David Lamp added that improved yields also contributed. Regarding M&A, Mr. Lamp stated that while CVR continually evaluates opportunities, the bid-ask spread has been too wide, and described the company's approach as conservative and akin to being "bottom fishers."

Paul Cheng requested details on the 2025 capital expenditures, the timing and duration of the major turnaround at Coffeyville, and the minimum required spending for next year. He also asked about the possibility of converting the Wynnewood renewable diesel unit back to crude processing.

Answer

CEO David Lamp stated the major turnaround will begin in late February, last approximately 45 days, and span Q1 and Q2 2025. CFO Dane Neumann noted that 2025 CapEx guidance is still under review and will be shared later. Regarding the renewable diesel unit, Lamp explained that it will likely remain in its current service as it provides low-cost RINs and is currently more profitable on a per-barrel basis than refining.

Paul Cheng of Scotiabank asked how unpredictable political tweets impact the company's trading operations and inquired about the long-term strategy for European refining and chemicals, including the possibility of a total exit.

Answer

Patrick Pouyanné, Chairman & CEO, acknowledged that 'volatility around tweets is not tradable,' causing traders to be more cautious and short-term focused. On European refining, he stated the strategy is dynamic and depends on market evolution, such as the shift to EVs. The focus is on reinforcing first-quartile assets like Antwerp, while weaker assets may be converted to biorefineries or shut down, with energy security being an increasing factor in government discussions.

Paul Cheng asked for details on the timeline and next steps for the recently signed Egypt-Cyprus gas export agreement. He also inquired if a new U.S. Gulf of Mexico rule allowing downhole commingling presents an opportunity for the company.

Answer

CEO Patrick Pouyanné confirmed the Cyprus agreement was a critical step, enabling gas to be exported via an existing LNG plant in Damietta, Egypt. He stated this was a precondition for further investment and that the operator, Eni, is targeting an FID by 2026, with potential first gas by 2029. On the Gulf of Mexico rule, Pouyanné said it is a "good rule" that will help lower costs and increase production. He added that TotalEnergies is actively looking to increase its exploration activity in the U.S. Gulf with partners.

Paul Cheng of Scotiabank requested quantification of the seasonality impact on Integrated Power results and asked for an update on the company's activities in Namibia.

Answer

CFO Jean-Pierre Sbraire explained that the primary seasonal impact on Integrated Power was the very low utilization of European CCGT plants in summer (less than 10%) compared to winter (around 40%). CEO Patrick Pouyanné provided an update on Namibia, stating that appraisal is complete and the focus is now on creating an economic development scheme for the oil pool, which is complicated by the need to manage a large volume of associated gas. A clear path forward is expected by the end of 2025.

Paul Cheng from Scotiabank asked if the recent Lewis Energy deal was sufficient for the company's U.S. upstream gas needs and how the Talos Low Carbon Solutions acquisition impacts its carbon storage strategy.

Answer

CEO Patrick Pouyanné reiterated that the Lewis Energy deal is a first step and not sufficient to meet their ~1 Bcf/d target for U.S. equity gas. He explained the Talos acquisition complements their European CCS portfolio by providing access to well-located U.S. storage projects, primarily to store their own emissions with potential for third-party services.

Asked if OPAL is seeing the same tightening in the RNG dispensing market (higher RIN share for station owners) as competitors, inquired about the current split of value, and asked for details on the amount of Investment Tax Credits (ITC) remaining to be monetized and how they are calculated.

Answer

They confirmed the dispensing market is tightening as RNG supply outpaces station capacity, which increases the RIN share for dispensers. Their vertically integrated model insulates them from this shift. They declined to share specific RIN share percentages. Regarding ITCs, they have an ongoing program to monetize them as projects come online. The credits are typically 30-40% of a project's CapEx, and this will be a significant source of liquidity for future growth. They did not provide a specific dollar amount remaining.

Paul Cheng of Scotiabank asked if OPAL Fuels is observing a tightening in the dispensing market, leading to a higher share of RIN value for station operators, and inquired about the current split. He also asked for the value of remaining Investment Tax Credits (ITC) available for monetization.

Answer

Co-CEO Adam Comora confirmed that the dispensing market is tightening as RNG supply outpaces station capacity, which increases the RIN share for dispensers, but emphasized that OPAL's vertically integrated model insulates them from this dynamic. He declined to provide specific RIN share percentages. Interim CFO Scott Contino addressed the ITC question, stating that the company will monetize credits from three newly operational projects and that it will be an ongoing program, with credits typically representing 30-40% of project CapEx.

Paul Cheng requested quantification of the higher share of RINs the company is receiving and asked for a comparison of the business model, profitability, and expansion plans between the U.S. and Canadian markets.

Answer

Executive Robert Vreeland quantified that their net take on RINs has improved from about 3.5% last year to around 5% currently, though he noted market resistance to further increases. CEO Andrew Littlefair explained that the Canadian expansion is strategically timed with the arrival of the X15N engine, which is crucial for the terrain. He confirmed the business model is identical to the U.S., focusing on building a fueling network where strong economics are driven by a significant price spread between diesel and natural gas.

Paul Cheng asked for the 2025 CapEx outlook, details on cost reduction achievements, and whether customer destocking in the food ingredient business is nearing an end.

Answer

CFO Brad Phillips projected 2025 CapEx to be between $450 million and $500 million. CEO Randall C. Stuewe added that YTD CapEx was low at $259 million and that cost reductions are an ongoing part of the company culture. Chief Strategy Officer Bob Day stated that destocking may continue for another quarter but that long-term contracts have protected margins.

Asked about the quantitative impact of Q2 weather on production, whether the guidance accounts for an active hurricane season, and the biggest risk to achieving the full-year forecast.

Answer

The Q2 weather impact was approximately 47,000 MMBtu in the Houston region, with a similar impact expected in Q3. The company's guidance process incorporates historical and trending weather-related outages. They remain confident in the full-year guidance because planned well-field investments and optimizations are expected to provide an offsetting production lift.

Paul Cheng from Scotiabank asked for the specific MMBtu impact from Q2 weather events, whether the guidance accounts for an active hurricane season, and the biggest risk to achieving the full-year target.

Answer

CFO Kevin Van Asdalan quantified the Q2 weather impact at approximately 47,000 MMBtu and anticipated a similar impact in Q3. CEO Sean McClain explained that their budgeting process incorporates historical trends of increasing weather events and expressed confidence in the guidance due to planned well-field investments and optimizations that are expected to provide a positive lift.

Paul Cheng of Scotiabank asked for the quantified production impact from Q2 weather events, whether the full-year guidance incorporates expectations for an active hurricane season, and the biggest risk to achieving the 2024 targets.

Answer

CFO Kevin Van Asdalan quantified the Q2 weather impact at approximately 47,000 MMBtu and noted a similar impact was expected in Q3. CEO Sean McClain explained that their budgeting process incorporates historical trends of weather-related outages and that confidence in the guidance is supported by planned capital investments in the well-field to drive positive lift.

Paul Cheng of Scotiabank inquired about Montauk's process for deciding the volume of RINs to sell each quarter, asked for full-year operating expense guidance, and requested details on the production ramp-up cadence for the Pico facility.

Answer

Chief Legal Officer John Ciroli explained that RIN sales volumes are tied to the purchasing cadence of obligated parties, not market timing, with sales typically weighted towards the second half of the year. CFO Kevin Van Asdalan stated that the company does not provide guidance on operating expenses. In response to the Pico question, Mr. Van Asdalan discussed the commissioning schedule for the Montauk Ag Renewables facility, outlining a plan for seven reactor lines to come online through late 2025.

Inquired about whether accounting changes in Equatorial Guinea affect operational decision-making and how industry consolidation in their operating basins might impact the competitive and service cost landscape.

Answer

The accounting change in EG improves transparency but does not alter operational decision-making due to aligned equity across the value chain. Regarding consolidation, the company believes high-quality assets will ultimately be run by the best operators and they will continue to focus on a balanced approach to acquisitions.