Phillip Jungwirth

Direct rejection of the deferral premise; reaffirmed CapEx guidance with quarter-to-quarter timing variance.

Declined the specific number, redirected to the hydroskimming incentive framework as the practical answer.

Randy explained Quebec runs 100% North American crude avoiding Dated Brent spikes. Pembroke margin environment looks favorable going forward.

Rich Walsh stated administration is fully aware export bans are counterproductive. U.S. is long crude and long refining production. No meaningful potential for export restrictions.

Gary noted EU moving away from Russian diesel, with those barrels redirecting to South America, and South American markets returning to US Gulf Coast as a result, being supportive of US Gulf Coast pricing.

Lane noted Venezuela changes have added uncertainty rather than clarity to the Citgo process, maintaining Valero's stance of staying out due to process uncertainty, while remaining interested if more certainty emerges.

Gary noted Mexican decline offset by Canadian ramp, Venezuelan barrels back in mix, plus Basra and Kirkuk for Q4. High sulfur fuel oil into cokers hasn't been economic.

Rich Walsh confirmed California discussions have produced no solutions, with Benicia closure plans moving forward as scheduled.

Gary noted lower EV penetration expected, but CAFE standards remain the bigger efficiency driver and aren't changing drastically.

Gary noted the U.K. is a net diesel importer so Lindsey's closure mainly impacts gasoline, with Pembroke positioned to fill the local supply void.

Knop said EQT probability-weighted each Appalachia project internally and arrives at high-single-digit Bcf/d of realistic demand growth.

Jeremy said distributed power returns are inferior to EQT's base business returns; EQT positions as partner and enabler to all developers rather than direct competitor or investor.

Toby emphasized the short bridge (20-mile pipe) from Ohio to deep Marcellus inventory; Jeremy confirmed Ohio/Clarington market as one of greatest opportunities with beachfront positioning.

Jeremy reported strong international interest in buying from a producer vs being short Henry Hub through traditional offtake; buyers increasingly recognize Haynesville is short inventory and Appalachian molecules are more durable.

Jeremy identified Gulf Coast salt storage as one of the greatest infrastructure investment opportunities globally; studying the space but cognizant that storage cash flows may get low multiples from investors.

Jeremy explained the market shifted from seller's to buyer's market after the LNG pause was released, with EQT getting better credit terms; they moved quickly to lock in this wave before next-cycle cost inflation.

Toby said MVP Boost results increase excitement for Southgate expansion potential; Jeremy confirmed Southgate is moving ahead as a project they are counting on.

Jeremy confirmed EQT expects to supply gas to the WV plant (FID expected H2 2025), with Toby adding that midstream integration is a key competitive edge in sourcing these deals.

Jeremy cautioned the open season is still active but indicated expectation that pipes will be underwritten by demand-pull shippers rather than supply-push producers, a shift from the past decade.

Kaes said operational and resource gains 100% contribute, using the doubling of the buyback ceiling since 2021 as evidence.

CEO clear: done selling Viper shares. Sold some as follow-on from drop-down stock receipt. Both companies will be well-positioned for M&A from balance sheet strength in months.

CEO cited specific examples of consolidated privates (Endeavor 2→15 rigs, Crown Rock 2→8, Double Eagle 1→6). Structural change: those rigs now in public hands. Private response limited to 20-30 rigs.

Al explained western/CBP wells have lower maturity and bottom-hole pressure leading to weaker performance vs basin-center wells with higher pressure and GOR. FANG focused on best resource quality.

Kaes said growth is highly macro dependent; still in yellow light with production as the input and CapEx as the variable. Organic growth will eventually enter the equation when the market calls for it.

Kaes acknowledged geology matters but said Diamondback's development style is differential even within similar geology, as Al confirmed operators differ in approach on similar rock.

Kaes said the industry has the capability to accelerate but capital will earn much higher returns at $70-80 oil, and will be spent off a smaller balance sheet and share count.

Kaes noted temporary technical factors limiting Viper buybacks due to pending public merger, but long-term cost of capital advantage is strong.

Travis argued high-grading has largely played out as zones are well-defined and everyone is already drilling their best stuff first.

Ezra declined specifics on commercial terms but explained the deals are tax-and-royalty concessions rather than PSCs, which he called more attractive.

Ezra confirmed Eagle Ford bolt-on was highly accretive with zero production, integrated immediately into infrastructure. Validated countercyclical M&A strategy but emphasized returns hurdle.

Keith confirmed consistent productivity with upside surprise in step-out areas. Staggered landing zone testing in northern Utica showing good results in thicker sections.

Ezra said current cost assumptions provide conservatism given track record. Near-term oil glut pushed to the right, maybe next couple of quarters. Global demand growing 1.0-1.2 MMbbl/d at ~1% CAGR. Three-year scenario contemplates Utica-led oil growth but can grow from multiple basins.

Jeff listed further upside: full rollout of EOG support services, in-basin self-sourced sand in Ohio by year-end, water infrastructure and maximizing reuse, additional automation and 24-hour control room monitoring, and leveraging scale for lower GP&T and better differentials through controlled in-field infrastructure.

Keith said 9 additional targets unlocked across Leonard, Bone Spring, and Wolfcamp over 5 years. Shallow targets now deliver comparable returns >55% at bottom cycle pricing. Team avoids one-size-fits-all approach.

Keith drew parallel: Eagle Ford achieving best economics ever after 15 years. Delaware earlier in that curve with well costs continuing to decline and high-intensity completions uplifting production 20%. Long runway for F&D improvement.

Marcel said they will keep pushing the M&C target higher, preferably capital-light, on top of LNG upside.

Dan described gas supply management as managing all upstream gas into the facility and capacity. Natural fit given Expand's footprint versus Delfin building that capability independently. Long-term partnership with potential to support additional vessels. Evaluating all projects on individual economic merit.

Mike said Expand is dominant in Northeast PA specifically, where competitive advantage is strongest for PJM power generation. In Southwest App, positioned competitively on western side versus competitors further east. Strategy is to focus on areas of greatest competitive advantage.

Dan explained Perryville benefits from Southeast utility demand as gas traditionally routed there is redirected to Gillis for LNG. Approximately 3 Bcf per day of new pipeline capacity pulling to Southeast. Key advantage is daily optionality to move molecules between both markets based on pricing.

Dan said NG3 currently approximately breakeven on capacity cost versus uplift but over time expects Gillis to become increasingly premium with LNG demand growth. Provides daily optionality between Gillis and Perryville markets.

Nick highlighted constructive environment with LNG demand growing faster than Haynesville supply additions. 2.5 Bcfe/day to Gillis plus Perryville capacity creates optimization opportunity.

Nick said Permian gas model assumes pipeline capacity gets filled. Material rig count pullback could change dynamics but specific plans not yet visible. Watching closely.

Management said all three regions are prioritized equally and described drone, digital-twin, and sensor tools.

Mike confirmed LAR new boilers and Intertie project complete, ready to run hard; Rick noted competitor closure happening faster than expected and PNW optionality to backfill San Francisco.

CEO cited strong wellhead-to-water position: Secretariat plant at 1.4 Bcf, fracs 1 and 2 in 2028-29 fully committed, NGL and LNG demand growth through 2030. MPLX takes no commodity risk.

Rick detailed GBR running discounted sweet crude, Garyville toggling sweet/sour economically; seeing more Iraqi barrel opportunities; Canadian heavy discount expected to widen.

Rick confirmed dock logistics as a significant deterrent and headwind for imports; fog, delays, incidents, and high freight rates all favor domestic producers like MPC over waterborne imports.

Dave outlined NGL integration with Gulf Coast refinery/petchem assets, natural gas takeaway via Whistler/Matterhorn/Blackcomb/Traverse, and LNG connectivity. Rick noted Utica condensate splitter opportunity.

Jim Wilkins noted CARB agencies more receptive to expediting permits and maintenance; CEO highlighted shift from punitive regulation to ensuring fuel supply security.