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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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.

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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.

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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.

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CEO Darren Woods stated that the limited presence in the Gulf of Mexico is a function of evaluating opportunities based on cost of supply, geology, and development costs. The company is agnostic to location and prioritizes opportunities that are on the low end of the cost curve and can generate advantaged returns. If new exploration areas open up and meet these strict criteria, they will evaluate them, but currently, other global opportunities have been more attractive.

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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.

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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."

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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