Arun Jayaram

Sunil said the narrowing gas marketing spread would be largely offset by improved Permian upstream realizations; sulfur pricing volatile.

Richard cited a decade of CO2 EOR pilots and a more than 45% EUR uplift, with commercial projects online later in the decade.

Richard confirmed approximately 7% new well cost improvement driven by efficiencies rather than pricing. Kenneth added that Middle East supply chain performing well with vendors focused on market share. No inflation impact on CapEx range.

Richard emphasized clear macro conditions before adding reinvestment. Highlighted decline rate reduction toward sub-20% by end of decade reducing sustaining capital by hundreds of millions. Sunil provided $5.9B as starting point for 2027 sustaining capital.

Dillon described GOA 2.0 era: Horn Mountain declining from 20% to sub-10% by 2030 and below 5% subsequently. King Field to low single-digit decline. Portfolio average decline projected to decrease to 12% with potential below 7% as additional waterfloods come online.

Jackson walked through: $400M lower US unconventional (70% from well cost improvements), $100M lower exploration, offset by $200M increase in mid-cycle projects (GoA waterfloods, international, unconventional EOR). $250M lower LCV from STRATOS winddown. Structural savings from wells per pad increasing from 3-4 to 4-6 and simul-frac scaling from 10% to near 40%.

Dillon detailed two FID waterflood projects: King Field dump flood online Q2 2026, Horn Mountain injectors drilling Q1 2027 with response late summer 2027. GoA declines potentially from 20% to 10% by 2030 and 7% by 2035. Returns 40-50%.

Jackson detailed Midland Basin pilot with wells online since mid-2015: 45% uplift after 5 CO2 injection cycles, modeled 60-100% uplift with continued cycles. Recovery factors increasing from 8-12% to 15-20%. Three commercial projects and 30 development-ready across Delaware and Midland.

Dillon outlined water floods for flat low-cost steady barrels, Eastern GOM capacity increases, standout central GOM wells, and subsurface engineering plus geo science driving production ramp-up.

Mathew confirmed allocation and explained book vs cash tax impact: adjusted effective rate unchanged, but deferred tax expense increases from bonus depreciation and R&D expense acceleration.

Dillon detailed Block 53: 640M barrels produced to date, 3,500 wells, 50% drilling cost/ft reduction over 3 years. North Oman discovery with 250M+ BOE resources, both wells online in under 13 weeks.

Hollub emphasized value-based approach without specifying asset types. Noted Permian demand persists across cycles and long-term oil supply tightness from underexploration.

Ken Dillon provided detailed breakdown: 16K BOE/day from turnarounds, 18-22K from drilling, 4-7K from production engineering, targeting 141-150K BOE/day range.

Hollub confirmed similar terms with about 23 wells planned but provided limited financial detail on the JV economics.

CEO detailed portfolio completion in trees, manifolds and umbilicals, subsea processing momentum, and alliances for life of field solutions.

CEO said market position was maintained or reinforced across the region and more awards are expected in coming weeks and months.

Declined to speak on behalf of customers but outlined a phased recovery sequence: intervention first, production recovery next, then capacity expansion.

Stephane clarified the decline was driven by exploration data amortization mix, noted Q1 is always lowest for Digital, and confirmed full-year EBITDA margin target of at least 35%.

Olivier detailed Venezuela capacity: 10 production sets, rigs ready to mobilize, ~80 nationals in-country, 1,000+ Venezuelan employees, ~2,000 alumni. Historically >$1B revenue. Conditional on licensing and payments.

Olivier confirmed $1B quarterly run rate target by year-end. Doubling manufacturing capacity this year, going international, adding new customers. Will look to complement organic capability with inorganic options.

Olivier explained digital operations mechanically outpaces core because every service/equipment gets digital enhancement. Combined with secular AI transformation trends.

Olivier cited NA efficiency gains, basin economics, and consolidation limiting upside. International has deepwater FID pipeline, gas security, oil capacity expansion, and aging basin needs.

Olivier detailed Q3: slightly higher sequentially (ChampionX offset by Palliser loss, U.S. decline, Ecuador disruption). Q4: high-single-digit uptick vs Q3 from full ChampionX and year-end sales.

Olivier confirmed global upstream decline with NA more affected. Inflection beyond 2025 driven by deepwater FIDs, gas supply acceleration, and production recovery focus.

Stephane declined to provide full-year EBITDA guidance due to tariff uncertainty, but confirmed Q2 margin expansion of 50-100bp and H2 margin expansion with growth.

Olivier detailed CCS (Capturi technology, 4 active projects), geothermal pilots, lithium DLE pilots, and data center manufacturing/cooling as key growth vectors.

Stephane confirmed low-carbon and data center activities are growing faster than Core but did not provide a specific growth target.

Olivier confirmed flat revenue outlook and EBITDA at or above 2024, excluding ChampionX.

Clay framed asset evaluation through value to Devon (inventory/capital efficiency), market value, and strategic fit to the Permian-centric core, but declined specifics.

Clay outlined review criteria (capital efficiency, inventory depth, FCF, fit) but explicitly declined to commit to specific outcomes or timeline, saying they do not want to box themselves into preconceptions.

Jeff explained Q1 benefited from deferred-to-current tax flip; full year ~10% but back-half quarters higher due to commodity prices and capital efficiency generating more pretax income.

Clay said directionally similar allocation but declined specifics pending merger close; that will be first order of business.

Trey explained Devon invested due to technical overlap (horizontal drilling, fracking); Fervo driving well costs down with Devon's technical support.

John said Grayson integration roughly complete with bidirectional lessons; Rockies led in artificial lift failure reduction and workover efficiency.

John detailed smart gas lift (3-5% uplift, now in full deployment), workover optimization (2,000+ bpd net gain), and 25% failure rate reduction in Rockies.

John confirmed no A-zone productivity impact from B co-development; optimized landings/spacings over 2 years of appraisal; real win is avoiding future depletion.

Jeff confirmed bulk of commercial savings contracts effective November/December 2025 with full-year 2026 benefit.

Clay acknowledged more midstream monetization possible but declined specifics; signaled holistic evaluation underway.

Jeff clarified NGL contract renegotiations in Delaware are material; shows up in both GP&T costs and realizations.

Clay credited D&C efficiency gains and well timing but cautioned against extrapolating the Q4 run rate.

Jeff outlined $2.5B debt reduction target while maintaining $200-300M/quarter buybacks, with upside potential.

Knop attributed EQT's win rate on power deals to the integrated platform, team quality, balance sheet, and customer-first structuring like CPV's electricity-linked pricing.

Toby said Iran reinforces U.S. supply reliability; international offtake agreements more likely timed to 2028-2029 closer to capacity availability. Jeremy noted existing offtakers buying at Henry Hub +115% are insulated.

Jeremy reported Homer City construction progressing with steel going up, Shippingport also advancing on offtake; Southeast power plants expected online between 2029-2031 following Transco expansion.

Jeremy outlined first $450-500M to dividend, next ~$500M+ to growth, emphasizing infrastructure as prerequisites for sustainable upstream growth; value creation beyond just drilling more wells.

Toby confirmed 2026 compression projects will bring systems to steady-state pressure, with future compression shifting to maintenance CapEx rather than growth bucket.

Toby contrasted MVP (60% producer-backed) with MVP Boost (100% utility-backed), framing the shift as clear evidence of a demand-pull environment.

Jeremy declined to give specific numbers but said full-cycle returns on midstream plus upstream demand unlock make the holistic return very attractive; opportunity set continues to grow.

Jeremy framed the PJM price cap as the market working, with EQT's integrated platform providing the cheapest solution for customers needing new generation.

Jeremy targeted year-end 2028 for full rate on both facilities, coinciding with Transco expansion, MVP Boost, and Southgate all coming online in the same period.

Toby framed data center deals as uplift to local gas sales with approximately 2 Bcf/day already flowing in-basin that can be redirected to firm supply arrangements.

Jeremy confirmed roughly half of the $600M tailwind is contractually locked in from utility deals, the other half from forward curve in-basin dynamics.

Jeremy detailed EQT's unique positioning for data center deals citing investment grade rating, net zero credentials, production scale, and integrated platform as unmatched advantages.

Management indicated upstream maintenance CapEx intensity trending down per Slide 8, with potential upside from bespoke midstream growth projects.

Gave concrete drilling-cost progress on Barnett and framed the path to competitive returns; direct.

CEO maintained spacing discipline, each well must generate 40% IRR at $60 oil. Barnett getting more attention on PV basis; 2 incremental rigs focused on JV area obligations.

$10B net debt target accelerated to couple months away. Plan to call $750M of 2026 maturities in Q4. Larger liability management exercise in 2027 targeting pre-2030 maturities.

Kaes disclosed 60-well test in H2 2025, ~$0.5M per job done during ESP pulls. Average ~100 bbl/d uplift with some multi-hundred bbl/d results. Described as 'B 1.0' comparable to 2014-era Wolfcamp B fracs.

Al confirmed ~50% EUR uplift translates to ~75 BO/ft for Barnett vs ~50 BO/ft for core zones. Kaes noted returns competitive at $800/ft with significantly larger PV per well.

Danny explained continuous pumping achieves 20% more lateral footage per day; not yet modeling material cost savings but expects them to flow through as operations mature.

Jere detailed the CPV gas supply agreement (indexed to ERCOT, operational 2029), Waha exposure declining from 70%+ to 40% by YE 2026 via Blackcomb and other commitments.

Kaes positioned Diamondback as the natural consolidator given execution track record, noting Endeavor integration was seamless despite nearly doubling the company.

Kaes reported $250M done with binding documents being worked on for both EPIC pipeline stake and EDS water system to Deep Blue.

Kaes acknowledged $900M/quarter as a logical baseline for flat production but hopes the market recovers to support 500K+ bbl/d.

Travis outlined 25-30% of FCF to debt reduction and 70-75% to buybacks and base dividend, with variable dividend suspended at current prices.

Travis confirmed well productivity will match recent banner years, with a true run rate of ~525-540 wells per year including Double Eagle.

Kaes outlined equity method investments, the EDS water business, and Delaware Basin non-op as the main monetization candidates.

Slocum attributed share gains to a tight, non-overbuilt market plus Halliburton's value proposition and technology as the differentiator over the last 12 months.

Slocum provided comprehensive regional tour: LatAm leading (Caribbean, Argentina YPF award, Brazil deepwater), Norway strong with rig adds coming, West Africa sizable programs in Namibia and Nigeria, Asia Pac resilient. Full-year mid-high single digit growth ex-ME confirmed.

Slocum acknowledged gas-diesel arbitrage as an opportunity but pivoted to emphasize Zeus IQ's subsurface value as the real differentiator, recovery improvement matters more than fuel economics.

Carre confirmed ~$4B EBITDA is within their range of outcomes for 2026. H2 expected better than H1 with margin progression through the year. Direct validation of Street estimates.

Miller focused response on Zeus IQ's unique sand placement measurement and control capabilities rather than addressing competitor technologies directly. Framed as building block for improving recovery.

Miller described unprecedented AI power demand. Explained HAL invests in project economics alongside VoltaGrid, leveraging boots on ground in 70 countries, manufacturing capability, and customer relationships.

Miller attributed N.A. upside to less white space than expected, reflecting strength of customer programs. Cited new Zeus fleet deployments and Zeus IQ demand as positive for 2026 positioning.

Miller confirmed well-positioned but declined to comment on Jafurah specifics. Noted UAE work starting Q4 as technology showcase for Zeus IQ. Emphasized disciplined approach centered on returns.

Miller confirmed periodic portfolio review. Highlighted ESP lift as most attractive business. Noted willingness to exit businesses not showing accretive returns. Did not confirm specific chemical divestiture plans.

Miller provided specific regional progression: Europe/Africa biggest jump in Q3, Middle East growth engines contributing, Latin America stout uplift in Q4 from contract startups. Constructive non-OPEC outlook.

Carre clarified Optime acquisition and VoltaGrid ownership increase. Operating cash outflow driven by incentive payouts, tax payments, and cash portion of restructuring charge. Clear and specific.

Carre explained Auto Frac's precision control and Sensori's sand verification capability. Miller confirmed it's priced standalone but explicitly declined to share pricing details.

Miller directly dismissed white space concerns. Cited FIDs in pipeline for 2025-2027. Positioned offshore as important component of international growth.