Scott Gruber

Management framed exploration as a multi-year energy security and reserve replacement trend rather than a one-quarter crude price reaction.

CEO walked through Middle East recovery, year-end digital and product sales, and data center as the Q4 bridge; CFO added the Middle East scenario math.

Emphasized domain depth and AI integration as durable differentiators, noting use cases in drilling automation and autonomous ESP production workflows.

Linked higher oil prices to increased discretionary tech spend, faster dataset purchases, and accelerated platform deployment decisions.

Stephane confirmed CapEx-to-revenue ratio staying at low end of 5-7% range. Production recovery and digital growth require less CapEx. Will increase if needed but expect it to come with increased cash flow.

Olivier confirmed international expansion beginning in Asia this year with modular manufacturing, plus Middle East in near future. US remains the hot market with the most exciting 2026-2027 pipeline.

Olivier confirmed plans to expand geographically (Asia pipeline agreed), diversify to more hyperscalers and collocators, broaden technology offering. Very low CapEx intensity.

Olivier described a growing OPEX-driven market that will outpace global CapEx, combining artificial lift, production chemicals, intervention, digital, and subsurface integration.

Stephane confirmed CapEx is at maintenance level (low end of 5-7% range), targeting >10% free cash flow margin. ChampionX will further reduce capital intensity.

Olivier affirmed 25% full-year EBITDA margin ambition excluding ChampionX and tariff escalation, acknowledging tariffs are a headwind to H2 expansion.

Olivier maintained mid-to-high-teens digital growth target, citing secular digital adoption trends decoupling from upstream CapEx.

Olivier described typical seasonal pattern with low Q1, Q2 rebound, and H2 higher activity with potential deepwater upside.

Olivier stated Russia revenue declined to 4% of global revenue, and SLB's voluntary measures align with new U.S. sanctions.

Miller endorsed above-normal incremental expectations for 2027-2028 as consistent with his own view and possible given technology wins and Middle East recovery.

Carre acknowledged contract wins elevated mobilization costs creating some margin headwinds but could not quantify the exact impact; Miller added North America pricing is improving under the hood.

Slocum explained Zeus deployment requires scale, runway, and recovery focus, conditions present in Argentina but not yet in most other international shale markets. Same capital discipline as U.S. deployment: first-contract cost recovery required.

Slocum confirmed fleets coming in now with more through year-end and into next year. Equipment moving from N.A. with good pricing and sustainable programs. Declined to quantify size or margins specifically.

Carre described power projects as long-term, low-risk contracts. Based on N.A. comparable, returns likely higher than current oilfield returns. Acknowledged it depends on country and competition.

Carre acknowledged many moving parts. Collections been great through 2025. Mexico collections improving. Too early for detailed 2026 FCF projection.

Miller gave emphatic one-word confirmation. Prior context noted technology investment cycles matured, iCruise, Zeus rollout largely complete, so less capital needed to maintain growth trajectory.

Miller noted idling occurred late Q3 with some continuing into Q4. Idled fleets will stay idle until margins recover. N.A. expected to be first market to snap back, fleets kept available.

Miller confirmed Zeus build is demand-driven and expects slowdown having achieved ~50% fleet target. CapEx expected at lower end going into 2026. Confirmed ~$40-45M per fleet ballpark.

Carre detailed three Q3 D&E margin drivers: software improvement, directional drilling strength, and mobilization cost elimination. Also noted Saudi headwinds and drilling/completion cycle shifts.

Miller positioned VoltaGrid as optionality without predetermined direction. Emphasized prudence and Halliburton's careful strategic approach. Declined to commit to specific path.

Carre explained CapEx as self-regulating via revenue percentage. Noted 2025 CapEx reflects 2024 orders so limited near-term flexibility. Tariff impact on CapEx cost also flagged.

Gruber probed Northern Delaware acreage blocking strategy. Sirgo explained acquisitions created foothold for trades and small deals focused on maximizing DSU size, wells per section, and lateral lengths.

Gruber asked about 2026 well cost trajectory and mix in Delaware. Deshazer confirmed continued cost compression from consistent rigs, frac fleets, longer laterals, and larger pad development.

Blake confirmed preference for operational consistency at $50 oil with lower service costs offsetting. Tom reframed discussion around completion crews not rigs, and Shane noted 50% reinvestment rate provides absorption headroom.

Blake Sirgo explained it involves cement design changes, casing designs, and set points specific to field location. Focus is on ensuring mechanical isolation everywhere, not a blanket redesign.

Tom Jorden avoided specific rig count guidance for 2026, focusing instead on the distinction between structural weakness and temporary disruption. Described their stance as conservative but hopeful they are overreacting.

Tom Jorden acknowledged workovers will take months as a large campaign to work through all affected wells, with multiple remediation approaches being tested.

Blake Sirgo outlined the plan to replicate Culberson economies of scale in Lee County, citing owned midstream assets, power optimization, and building a large contiguous block as foundations.

Tom Jorden emphasized pure returns-based allocation, noting Anadarko assets also have NGL optionality that can make returns competitive depending on pricing, so it remains a dynamic competition.

Direct. Named data centers and gas infrastructure as the near term cross sell, then space, geothermal and mining as underappreciated Chart adjacencies.

Ahmed broke down Q2 by segment. OFSE: Middle East down 20%+ sequentially, product sales hit harder by logistics. IET: modest conflict impact on GTE shipping, GTS overdue backlog benefit tempers usual 1Q-2Q step-up. Company EBITDA expected flat QoQ.

Lorenzo identified 2026 order drivers: power systems growth from $2.5B foundation, data center intake rising toward $3B target, gas infrastructure expansion, new energy targeting $2.4-2.6B, and LNG consistent with recent years. Non-LNG orders at 20%+ CAGR.

Ahmed detailed 14 dedicated work streams focused on systems, supply chain, commercial, and operations integration. Led by Jim Apostolides with 25 years of M&A integration experience. $325M cost synergies targeted. Close expected mid-2026.

Ahmed detailed OFSE margin drivers (rightsizing, removing duplication, price discipline). IET margins expanded 190bps despite 40bps tariff headwind. Business system in third year driving structural improvement. Both confirmed 20% targets.

Ahmed detailed limited U.S. import exposure (<5%), mitigation via centralized coordination hub, leveraging global supply chain, free trade agreements, duty drawback programs, and contractual pass-throughs.

Nancy cited three FCF conversion drivers: working capital efficiency (collections, inventory turns), tax rate optimization (cash and book rate declining), and structurally higher margins flowing through. Confident in 50% conversion path.

Trey Lowe said Devon has invested in data sets for a decade; Coterra's AI well-prediction models complement Devon's operational AI, with partnerships on specific applications but the core advantage being employee empowerment and speed of deployment (few wells to 1,000+ closed-loop gas lift).

Clay explained refracs now compete with new wells due to improved D&C costs; highlighted early EOR/surfactant projects with impressive returns accruing to LOE rather than capital side.

Clay clarified surfactants and AI investments are relatively small; billions of FCF are for dividends, buybacks, and debt repayment, board-level capital allocation decisions with new combined entity.

John explained $150M production optimization is essentially all production uplift so far; LOE improved 6% YoY but lags; expect ongoing reductions in 2026.

Clay declined specific TIL detail but pointed to 2025 current guide as starting point; no deflation assumed in 2026 preliminary.

Clay confirmed mid-380K bpd remains target; production wins accrue to lower capital not higher volumes.

CEO confirmed in 70+ WTI world, couple percentage points organic growth adds to NAV and long-term FCF. Macro conditions now supporting hitting organic growth accelerator.

CEO separated DUC noise from fundamentals: drilling records across all lateral lengths, $300/ft achieved (from $360), Barnett already under $400/ft. Better subsurface results driving long-term gains.

Jere outlined 2025 cash tax rate of 15-18% (down from 19-22%) with ~$200M one-time benefit, normalizing to 18-20% in 2026.

Kaes said they'd be comfortable down to high 100s-200 DUCs but prefer maintaining flexibility; drilling efficiency may prevent any net DUC drawdown by year-end.

Travis acknowledged geological headwinds are outpacing efficiency gains as the basin matures, with gains now measured in pennies vs dimes/quarters in prior years.