Kalei Akamine

Toby said opportunities aren't overlooked but out of reach for smaller peers; EQT's scale allows meaningful LNG exposure while still being a small portion of a diversified portfolio.

Toby cited big in-basin plans: NextEra 10 GW in PA, Portsmouth 9+ GW in Ohio, WV 50x50 plan; Jeremy quantified 2-3 Bcf/d already partnered with potential for 8-10 Bcf/d additional egress and pull.

Jeremy detailed the Ohio opportunity: FT contracts rolling over, Utica inventory depleted by ~2030, positioning EQT to backfill volumes and capture premium pricing through Clarington infrastructure.

Toby noted the 2.1 Bcf/d record is weather-dependent; the more important signal is Station 165 pricing showing tremendous unmet demand that MVP Boost will address.

Jeremy confirmed 2026 production approximately flat to 2025, with Q4 guidance (adjusted for curtailments) as the run rate to extrapolate.

Toby described three tiers of opportunity capture: operational footprint, midstream footprint (3,000 miles), and commercial footprint (East of Mississippi), confirming Ohio conversations are active.

Toby framed growth as low single-digit to meet demand, emphasizing scale, investment-grade balance sheet, inventory durability, and existing flowing volumes as enabling factors.

Toby noted single-digit well cost improvements continuing, compression program halfway done delivering twice the budgeted uplift, plus Olympus integration providing additional optimization runway.

Toby confirmed conservative underwriting with well spacing and completion intensity tweaks as potential upside not yet factored into the acquisition economics.

Toby confirmed plans to integrate Olympus midstream into Equitrans network and leverage the combined system for in-basin demand opportunities.

Jeremy confirmed Southgate is on track and cited it as a tangible example of upstream-midstream integration synergy not counted in the formal synergy numbers.

Akamine questioned Marcellus inventory calculation methodology. Deshazer clarified 12-year inventory based on 3-year average well count and capital spend, not current year TILs, with cost improvements allowing more wells per dollar.

Akamine asked about Marcellus operating improvements since Cabot acquisition and M&A potential. Sirgo highlighted dramatic lateral length increases, well spacing optimization, and full cost value chain attack including converting all frac water from trucking to piping.

Shane Young framed debt paydown as facilitating a return to robust buyback program, consistent with long-term strategy. Acknowledged current price attractiveness and hinted buyback pace may pick up in H2.

Tom Jorden expressed enthusiasm for returning federal lease sales, noting they had been nearly absent for years. Expects competitive pricing but Coterra will participate aggressively.

Tom Jorden confirmed laterals were long enough to assess productivity, with some DSUs performing as expected. Reiterated with high confidence this is mechanical not reservoir or spacing related.

Shane Young confirmed opportunity set extends well through end of decade even in Wolfcamp-only scenario. Tom reaffirmed the three-year plan remains intact with changes discussed on the call.

Blake Sirgo explained higher unit costs driven by oily acquired assets with low GOR, plus mix shift toward more oil BOEs versus gas. Emphasized the higher-cost barrels come with superior margins.

Blake Sirgo declined to provide a specific exit rate but characterized the trajectory as consistent rightward growth driven by steady activity.

Kaes confirmed always looking to increase WI; position built through partnerships with lower WI but organic netting-up (swaps, trades, mineral purchases) will follow.

Kaes said the model doesn't show meaningful DUC build or draw; Q1-Q2 CapEx at lower end of quarterly range with potential for H2 reductions if Barnett costs and surfactant results trend favorably.

Kaes confirmed the Q4 CapEx range times four is the maintenance bogey for ~510K bbl/d, noting capital efficiency this year compares favorably to any year in FANG history.

Kaes said continuous pumping may reduce crew needs by half to one; drilling efficiencies resulted in more wells drilled than expected, keeping DUC backlog as a structural advantage.

Kaes explained the light 2026 hedge position is a function of expensive put premiums and declining hedge needs as balance sheet and share count shrink.

Danny confirmed 100-120 wells/year per crew is achievable and the team is working on pad configuration and water infrastructure to execute programmatically.

Kaes outlined multiple revenue streams: equity participation, gas supply contracts (fixed/collar/index), and power take-back, but noted terms still being negotiated.

John attributed Q4 drop to condition-based maintenance savings, microgrid energization, and new GP&T contract; Q1 uptick from weather and workover timing.

Clay confirmed participation in federal lease sales; existing infrastructure and efficiency machine gives competitive position.

John said Wolfcamp B mostly meeting/beating expectations; well productivity will be consistent forward; Delaware D&C at new 1,800 ft/day record.

Clay said they evaluate both buying and selling midstream assets objectively; Matterhorn proceeds go to balance sheet.

John said Wolfcamp B results consistent with expectations; oil cut varies geographically (higher north, gassier south).

Mike said Gulf Coast is where they can build and grow volumes to meet demand. Three-basin advantage provides unique commercial flexibility. Dan noted commitments are staged over five to fifteen year timeframes with new premium market sales added. Individual sales become assets with secondary optimization value.

Brittany said the pre-merger 15-20% LNG target is outdated given broader demand growth including power and industrial. Now agnostic to specific premium market type, seeking highest-return diversification. Will not be overly prescriptive on LNG percentage.

Josh noted Q1 benefited from lower planned maintenance and workover expenses. Absolute spending expected to increase with production but maintaining full-year guidance.

Nick confirmed Haynesville production flattens after Q2 with no growth until 2026. NG3 will be filled by redirecting volumes from interruptible transport, optimizing delivery points.

Ryan Lance confirmed capital-light efficiency-driven growth with no rig additions needed, production growth as an output of stable programs, and deep diverse inventory options.