Stephen D'Ambrisi

Geisler said queue customers would be additive to the IRP and ownership could rise toward 50-50, but did not address the multiplier directly.

Cooper attributed the strength to a combination of data center ramp refinement, a broadening manufacturing ecosystem, and strong residential usage.

Geisler called it a fair directional assumption but noted energy intensity varies by fab and details are still being finalized with TSMC.

Ted explained sizing driven by available generation/transmission capacity (Desert Sun + interconnecting T). Process is repeatable: identify incremental infrastructure above organic needs, offer to queue, negotiate, then repeat with new capacity.

Andrew noted residential outperformance driven by declining rooftop solar offset. 2026 guidance driven by known large customer ramps including TSMC fabs. Long-term 5-7% confidence strong given sophisticated customer forecasting.

Andrew provided rule of thumb: 1% residential growth = $25M+ gross margin (clustered around peak), 1% extra-high load factor = $5-10M (90%+ load factor across all hours). Operating leverage benefits from both.

Andrew confirmed proportionate scaling over time. Near-term could be lumpier as strategic projects take longer to build. Exploring sectionalized energization for longer lines to reduce regulatory lag.

Andrew explained intra-year variability in large load customer ramp rates. Some customers testing vs ramping production. Long-term trajectory strong with raised 5%-7% guidance but year-to-year puts and takes exist.

Ted confirmed 2027 formula rate adjustment is the intent if case concludes in 2026. Designed as annual adjustment mechanism.

Andrew explained one-time procedural change in January to estimate unbilled revenues separately for extra high-load factor customers, creating a 1.9% offset. Underlying residential trends flat to slightly positive.

Frenzel cited Colorado upside from the Large Load Tariff, the RFP and the SPARK award but gave no bill-impact figure.

CFO said storage ITCs offset rate impacts in Minnesota and will be considered elsewhere, without committing to other states.

Van Abel gave a specific approval timeline of early 2027 and cited over $1 billion of customer benefits plus stakeholder and community support for the project.

Van Abel noted Xcel has published a 10-year plan before and will keep evaluating it, but declined to commit, offering only additional color beyond the 5-year plan.

CFO acknowledged 50+ bps structural lag but framed large load growth as opportunity to drive better returns between rate cases and potentially extend rate case filing intervals.

Tranche 1: ~1 GW approved including gas plant; Tranche 2: up to 1 GW company-owned solar+storage pending additional analysis; Tranche 3 timing unclear but likely H1; anything not approved shifts to follow-on IRP RFPs.

Sales impact primarily 2029-2030 and beyond due to ESA-to-energization timeline; extends capital investment and growth opportunities post-2030; holistic update at Q3.

~200bp delta between 11% rate base and 9% EPS growth typical at high-growth levels; no ROE compression expected.

Poroch validated the framing and volunteered a roughly $2 billion per gigawatt capital rule of thumb.

Womack described the sequencing but deferred specifics to future contract finalization and an updated load forecast.

CFO explained minimum bill as a call option on the network that recovers costs regardless of ramp rates, differentiating from variable pricing models.

CEO linked RFP sizing to load forecast updates from large load demand, highlighted repeat buyers and vertically integrated structure delivering results.

Womack emphasized Southern Power's risk profile won't change, requires long-term contracts with creditworthy counterparties. Currently evaluating 6 brownfield sites in the Southeast for potential new gas development.

Poroch provided a rule of thumb of around $20 to $25 a kilowatt month for recontracting rates, with opportunities rising through the portfolio as contracts come up for renewal.

Campbell confirmed at least one more ESA expected in 2026, said incremental load drives additional generation and meaningful capital, but did not quantify the exact amount.

Campbell called it a fair point and committed to providing more specificity as the pipeline converts, but gave no firm timeline for longer-term disclosure.

Buckler explained FFO improvement eliminates 2030 equity need but acknowledged upside ESAs could bring incremental capital requiring reevaluation.

Campbell declined specific customer count but said next ESAs would be similar in size to the 4 announced, with bulk of impact in 2030 and beyond.

Campbell clarified Kansas LLPS has a unanimous settlement with KCC decision expected same day; Missouri has a partial settlement with year-end decision expected.

Fontan said no new turbine/plant-island equipment added since Investor Day; ETR holds ~7.5 GW, the low end of its 10-17 GW opportunity, and continues to monitor.

Marsh said ETR is building over 1,000 miles of transmission and is working with MISO on southern load pockets, reshaping long-range transmission planning.

Kimberly explained the load ramp is back-loaded since CCCTs don't come online until 2030-2031, but minimum bills provide revenue during construction.

CFO clarified 2029 addition is biggest piece of delta, not alternate financing. Alternative financing aligns cash outflow with asset in-service timing. More detail at EEI. CEO noted all 19.5 GW projects targeting COD by 2032.

Partial: Microsoft has not disclosed acreage; management estimated southeastern Wisconsin could reach 4.5-5 gigawatts in total.

Deflected: said locations in both territories are being considered and declined to say more.

Expressed confidence in ability to replace Point Beach power by 2030 and 2033 but declined to share specifics on interconnect agreements or MISO queue positions.

Listed competitive advantages: location, transmission capability, cooler climate, no natural disasters. VLC tariff praised by customers for transparency.