Scott Hanold

Mike stressed Expand is not a midstream company and prefers the capital-light commercial route to premium markets.

Mike framed it as timing-driven: LNG first (facilities under construction, FIDs done), industrial second (big projects but FIDs not yet seen), power third (everywhere but generation equipment timing uncertain). International markets more optimistic about LNG demand than domestic consensus.

Dan differentiated supply-side (long-term SPAs at cost of liquefaction, available now) from sales-side (relationship-driven, long-term contracts). Short-term spot strip priced to perfection on Gulf Coast, but they are building for the long term with portfolio approach to contract types and tenures.

Mike said partnerships preferred over outright midstream acquisition. LCM deal has a Momentum-type component. Need to get to end-use customers through partnerships rather than buying gathering systems.

Brittany confirmed OBDD benefit driving low cash taxes. Expects stair-step increases in cash tax rate over the next few years to become full cash taxpayer closer to 2030.

Josh said 75,000 net acres is about the right size given overall inventory depth. Some opportunity to build incrementally but nothing material. Selected area has much less structural complexity compared to steeply dipping beds further west in East Texas.

Josh declined to detail specific completion recipe but highlighted self-sourced sand as biggest differentiator, lower cost, controlled supply, enables higher proppant loading. Historically third-party sand suppliers struggled to keep up with increasing completion efficiency.

Nick outlined multiple contract structures under consideration including direct sales, partnerships, and tolling. Dan Turco emphasized three pillars: accessing premium markets, structuring for lower cash flow volatility while retaining upside, and building portfolio-level integration and optionality.

Nick emphasized no urgency, looking at domestic and international sales in various forms. Key focus on risk-reward, protecting downside while participating in upside. Conversations ongoing across different areas and time frames.

Chris Ayres noted strong investor reception for both mechanisms. Variable dividends provide embedded TSR through cycle; buybacks drive per-share accretion. Expect combination going forward.

Nick separated capital decisions (based on mid-cycle) from production decisions (based on near-term market). In a weak near-term/strong long-term scenario, would continue spending but curtail production.

Josh detailed 60-65% Haynesville weighting, 45% lower/rest upper in NE. Both Bossier and Haynesville offer strong returns with similar productivity.

Nick emphasized flexibility to hold back TILs or curtail volumes, noting the company proved this capability in 2024 and would also adjust capital allocation if macro conditions change.

Ezra flagged egress as the key challenge in Canada while noting a robust Lower 48 opportunity set and renaissance in Alaska.

Jeff noted Cheniere deal terms hard to replicate but team continues looking for unique ways to price gas internationally. Emphasized scale and balance sheet as negotiating advantages.

Ezra said special dividends remain in toolkit but shifted preference toward buybacks over past three years. On going above 70%, noted desire to build cash for countercyclical investment.

Ezra said primary target performance is relatively consistent. Acknowledged the development strategy shift heading into 2025 could have been better communicated externally. Additional zones unlocked by extreme cost reductions coming off 2023 industry highs.

Ezra said U.S. electricity demand grew ~2% in 2025 with prices up 6.5%, forecast 1-3% CAGR. South Texas (Dorado) offers open space, water, gas, fiber, and storm protection for data centers. Still early on multi-decade contract negotiations with construction timelines pushing right.

Ezra said energy weighting at ~3% of S&P 500 represents large dislocation. Balance sheet supports higher return levels than 70% minimum. Building cash not a priority. Opportunities to return close to 100%.

Jeff credited magnitude of full integration: drilling efficiency enabling rig reduction from 5 to 4, high-intensity completion design implemented at scale, 1,100 wells moved to EOG proprietary applications, 80% on artificial lift optimizers delivering production uplift.

Jeff said costs per well are low after acquiring and cheapening the IP. Enables geomechanical property calculation, fault/fracture identification, and equipment failure detection. Over 50 wells deployed so far with long runway for portfolio expansion.

Jeff listed: shared infrastructure and consolidated facilities, EOG motors and mud cutters, in-basin sand sourcing, water recycling, longer laterals from expanded footprint, production optimizer deployment already underway.

Ezra maintained focus on investing at the right pace rather than chasing gas prices. LNG nameplate up 2.5 Bcf/d YoY. Dorado breakeven at $1.40 but won't outrun pace of learnings.

Jeff confirmed no 2025 tariff impact due to proactive inventory management. Confident in low-single-digit well cost reduction for 2025 from efficiency gains. Too early to guide beyond 2025 given tariff uncertainty.

Danny credited improved local gas marketing and reduced flaring; Al added Barnett targeting as a forward driver.

CEO said situation is fluid, taking quarter-by-quarter. Still have things in back pocket to grow further. 520,000+ boe/d oil is new baseline.

CEO and COO jointly answered, better wells from completion optimization plus lower downtime from automation/ML. Perforating strategies, rate design, sand loadings driving uplift.

Kaes said majority of revisions are price-driven; the rest are PUD reshuffling as acquired inventory (Double Eagle, Endeavor) gets reprioritized. 70% PDP, 30% PUD, averaging 3-year PUD booking.

Kaes noted Permian consolidation has reduced the number of actionable deals; basin champions are emerging. FANG still monitors every deal but is pivoting toward organic resource expansion.

Kaes said Delaware gets less attention in 2026; Midland zone mix continues to evolve with Barnett and Woodford tests increasing, with a full asset update planned for next year.

Kaes said Deep Blue's third-party business is creating value; potential monetization or restructuring at some point, plus tangential opportunities in water-for-power.

Danny highlighted 4-5 day wells becoming more consistent vs 8-day average, completion speeds pushing 4,000 ft/day, with 15-20% further gains possible from continuous pumping.

Kaes explained the NGL jump came from Energy Transfer-operated WTG plants resolving power issues in Martin County, with flaring down 75-100 bps.

Kaes outlined plan to bring back a fifth crew and level at 485K bbl/d in Q4, with DUC backlog providing flexibility for 2026 production depending on prices.

Travis argued Permian base decline and reduced capital investment will lead to U.S. production declines, especially since efficiency gains are now incremental.

O'Brien reaffirmed the 45% full-year payout (implying a second-half step-up), declined to guide buyback timing, and defended peer-leading distributions.

Andy provided detailed supply-demand framework, Ryan discussed floor price implications. Comprehensive response covering physical supply disruption, refinery impacts, and long-term equilibrium.

Andy O'Brien emphasized very strong starting cash position ($7.4B), $2B net debt reduction. 45% of CFO distribution works across price ranges. Balance sheet exists to bridge quarters if needed, and no real concerns about funding distributions.

Andy O'Brien guided 53% total company oil mix for 2026 (including Surmont higher royalties), 50% for Lower 48 driven by Delaware Basin growth with higher gas content.

Ryan Lance described choppy near-term macro with OPEC+ 2.5M bbl unwinding offset by 5-year-low inventories, constructive long-term with 1M bbl/d demand growth continuing.

Ryan Lance said $60 is close to mid-cycle planning price, would consider scope changes in sustained low 50s but not overreacting to short-term volatility.

Andy O'Brien detailed Surmont exposure with about half sold into US, noted Montney gas not sold into US, and diversified portfolio mitigates via Bakken/ANS differentials.

Christmann said steady diet of delineation and appraisal testing is the nature of the basin and will continue indefinitely. Currently flowing back a 4-well Barnett test with more Barnett drilling later this year. Multiple spacing tests in both basins planned.

Christmann said data room open with significant industry interest. Looking to farm down with potential announcement forthcoming. Drilling likely in 2027, small chance it could be late 2026.

Christmann clarified 3 of 12 rigs (not 8) are on gas. Program exceeding all internal expectations. Longer-term growth dictated by exploration success. Have processing capacity that may need additional piping. Year-over-year gas growth continuing.

Christmann confirmed overlap with Barnett/Woodford plays. Planning Q1 2026 inventory update. Core development inventory extends well into early 2030s. Rodgers added that capital efficiency gains are forcing complete re-examination of all inventory including Callon acreage.

Christmann explained they started with one gas rig in November, plan to shift 2-3 rigs to gas this year. Good existing infrastructure backbone in the Western Desert but may need new infrastructure depending on exploration success.

Christmann described steady diet of zone testing. Riney provided detailed walkthrough of the rig drop from 11 to 8 rigs and the resulting production trajectory from 140K peak to 128K exit rate.

Jeff confirmed no framework change; incremental FCF from tax savings and optimization accrues to balance sheet, accelerating debt reduction.

John attributed Anadarko growth to Dow JV well IDs plus Q1 weather recovery; consistent rig activity.

Jeff confirmed no change to $200-300M/quarter buyback range; framework unchanged despite lower equity prices.

Clay said Devon is on 'high alert' but not yet at action threshold; forward curve at ~$60 still passes investment test.

Clay confirmed nearly a decade of Williston inventory including Grayson, with costs coming down and productivity improving.

Clay described it as a win-win with natural accretion, citing $2M+ per well savings already being demonstrated.