Matt Portillo

Dan Turco was constructive on structural power, industrial, and LNG demand converging in Expand's backyard.

Mike agreed demand concentration near Haynesville creates supply pressure. Long-term 20-year contracts will need supply from other basins including Appalachia and Permian. Expand benefits from deeper inventory than most, able to go longer than competitors.

Mike described LNG as natural extension of Haynesville through Gillis delivery to international pricing (JKM, TTF). Dan explained they terminated the previous Delfin Vessel II agreement and took a larger position on Vessel I, integrating gas supply management. Pursuing long-term partnership with potential for additional vessels.

Josh noted 10 new industry rigs added to Haynesville but their economics are incomparable. Slide 30 shows Expand rig generates materially more production over two years versus industry average. Self-sourced sand enables higher proppant intensity that changes decline parameters rather than just IPs.

Mike highlighted gas-on-gas demand with end-use customers wanting proximity to wellhead. Dan Turco emphasized approximately 25 Bcf per day of US gas demand coming online with half from LNG in their backyard. Noted massive inbound interest with first time in 25 years seeing this level of demand for supply security.

Nick used the Lake Charles Methanol deal as a case study for how demand growth creates bundled supply opportunities. Dan Turco highlighted the Texas-Louisiana border constraint for Permian gas reaching Gulf Coast LNG demand, advantaging Haynesville-based suppliers with existing pipeline infrastructure.

Nick acknowledged mid-cycle view could go higher over time but said not quite there yet. Noted demand forecasts on Slide 9 are more conservative than market consensus, reflecting timing differences rather than magnitude. Emphasized demand growth does not stop in 2030 and volatility will persist.

Josh confirmed continued Utica activity with active leasing programs to shore up additional inventory alongside extending western Ohio Marcellus boundaries.

Nick outlined strong positioning with 2.5 Bcf/day capacity to Gillis, Delfin supply agreement, and focus on diversified revenue sources from LNG.

Nick provided a detailed explanation of the mid-cycle pricing framework and how it drives production targets, noting $3.50-$4 supports 7.5 Bcf/day.

Portillo asked about Northeast PA power demand outlook and infrastructure including Constitution pipeline. Young noted both announced and unannounced power development activity in PA, while Constitution remains challenged without committed buyers.

Portillo asked about microgrid deployment timing and scale. Deshazer described existing smaller microgrids inherited from acquisitions and plans to expand with 3 new microgrids targeting 50% power cost reduction.

Tom Jorden emphasized need for differentiated pricing structure for long-term commitments. Blake noted lots of movement in PA power space with right players coming to table, but deals must provide diversity or price enhancement.

Tom Jorden confirmed 1-2 more years of Dimock box development but declined to provide specific well counts. Highlighted community benefit of royalty owners finally participating.

Michael Deshazer quantified oil maintenance capital at $1.5-1.6 billion across Anadarko and Permian to hold 160K bpd flat over a 3-year period, excluding Marcellus which is disconnected from oil.

Tom Jorden explained returns competition is driven by oil/gas ratio and NGL pricing, noting at 15:1 or lower the horse race between all three basins becomes serious.

Tom Jorden declined to provide specific well count or upper/lower split, explaining they have approximately five pivot points modeled and the detail would not be productive to share.

Tom Jorden maintained mid-$3 threshold for Upper Marcellus, emphasizing not just current returns but resiliency against price declines. Cited Permian program generating returns above cost of capital even at $40 oil.

John said PRB program 100% Niobrara-focused with appraisal work; well costs declining from $15M toward $10M target.

Tom Hellman detailed drilling +19%, costs -15%, completions -8%; additional $600K/well savings through simul-frac and self-sourcing sand.

John Rains said Wolfcamp B goes from 10% to 30% of program; oil mix stays consistent around 47%.

Clay said Anadarko needs JV support to compete in portfolio; gas optionality exists for the future.

Jackson attributed outperformance to base production improvements via artificial lift analytics, continued subsurface design tweaks, and better uptime on processing facilities supporting both base and new well production.

Jackson highlighted Powder River Basin opportunity: drilling performance improved 25%+ vs last year. Capital can flex from DJ to Powder River without increase, optimizing Rockies portfolio allocation.

Jackson confirmed Permian oil cut expected to stabilize and increase in H2. Secondary benches reuse existing infrastructure delivering exceptional returns. Well placement optimized for oil recovery over water.

Jackson highlighted well placement optimization for oil over water, Western Midstream partnerships, water recycling technology advances in both Midland and Delaware (CrownRock synergy).

Jeff said 13% YoY productivity improvement is sustainable per-foot recovery increase driven by wellbore construction optimization and maximizing high-intensity frac surface area. Verde Pipeline provides 1 Bcf transport expandable to 1.5-1.75 Bcf with minimal compression investment. No additional egress needed.

Jeff said Delaware lateral length basically flat 2025 to 2026 after huge jump in 2025. Portfolio-wide 18% increase driven by 3-mile laterals in Delaware, 4+ miles in Eagle Ford including record 24,000-foot lateral, and 3+ miles in Utica. Always looking for bolt-ons and trades to extend.