Paul Fremont

Direct: explained collateral ramps with expenditures and steps to net book value once the VLC tariff service begins.

Direct: stated full collateral is already secured at the current rating, so a downgrade adds no incremental requirement.

Direct: reaffirmed comfort with the year-end timing while sizing prospects at 400 to 500 megawatts.

Partial: would not estimate duration but argued the outcome does not change the current posting requirement.

Lauber noted opportunity for 10-year PTC repowering via safe-harbored materials plus recontracting upside as renewable capacity value has increased since original contracts.

Lauber said considering all options including renewables, CTs, and possibly a combined cycle; decision part of annual generation planning process.

Lauber said no direct discussions but communities are generally seeing property tax and other benefits. Called Oak Creek a great site needing very little transmission.

Current 500 MW is not the Caledonia replacement, that land was purchased prior. Microsoft still seeking additional land to replace Caledonia site.

Effectively confirmed that at ~$120/MWh PPA pricing, new-build generation likely makes economic sense. Sees upside potential but needs to complete formal analysis.

Retired coal sites already repurposed for economic development. Looking at other locations with focus on natural gas pipeline access.

Replacement would be dispatchable gas plus potentially renewables using all-of-above approach. Contracts to 2030/2033 provide ample time.

Microsoft still looking for replacement site in SE Wisconsin. WEC doesn't have available land but noted potential upside for load growth.

Liu confirmed $4.8-5.2B is pure common equity. Junior subs are incremental within the $4B of equity content split equally between common and hybrid.

Lauber drives by site regularly, sees activity on all 1,300+ acres. Microsoft hasn't specifically discussed pause but site activity is ongoing.

Could not speak to other Microsoft sites but noted pilot programs for zero water designs in 2026.

Liu confirmed current 5-year CT contracts are secured. Lauber noted GE likely ramping supply for longer-term needs.

Robert reaffirmed the Iowa retail electric stay-out through 2029 and said adding several hundred more megawatts of data centers could extend it beyond 2029.

Barton declined to quantify developers. Described pipeline as mix of hyperscalers and developers with active negotiations, completed/ongoing transmission studies, and land control. Not all in Iowa but distribution is fluid.

Durian confirmed 2025 actual EPS as the base for 7%+ growth, updated annually. State-level rate base details available in previously disclosed supplemental materials.

Durian explained combined-cycle pushed beyond plan horizon in favor of faster simple-cycle. Additional Iowa wind via advanced rate-making proposal. Total CapEx unchanged.

Durian cited equity dilution (consistent with peers) plus conservative interest rate assumptions for debt refinancing as key differentiators.

Durian confirmed settlement window before September 9 hearing. Intervenor testimony scheduled for August 12.

Barton confirmed 750+ MW as fair estimate for QTS Madison data center opportunity.

Durian said WPL files every two years but doesn't have to increase rates. Targeting flat base rates for five years similar to Iowa through growth and cost reduction.

Durian confirmed flexibility with ATM, hybrids, and junior subordinated debt all under consideration.

Barton confirmed all-of-the-above approach including gas generation alongside renewables.

Barton explained Wisconsin's biennial forward-looking rate construct already accommodates growth without needing Iowa-style ICR.

CFO confirmed uprate conversations are late-stage and expected to be contracted before construction completes. CEO emphasized no merchant risk philosophy.

CEO said Southern Power is contracted in the mid-90s percent, with contracts extending through mid-2030s and some early recontracting opportunities emerging.

Womack said upgrades could begin as soon as 2029. Poroch confirmed these are upside opportunities not in the base plan, and the Southern Power business model of fully contracted assets won't change.

Poroch confirmed regulatory review required, with two proceedings beginning between Alabama and Georgia expected to run through 2026 with conclusion likely in 2027.

Poroch explained: contracted = signed agreement, committed = final phase negotiating Ts and Cs before signing. Advanced discussions represent approximately 12 gigawatts across the system.

Poroch said the 8% annual sales growth target is for 2029, with the company growing into that level over the planning horizon.

Womack flatly ruled out Southern Company involvement in Summer restart, saying it's not in their wheelhouse and would need significant risk mitigation.

Tucker said no current plans to spin off Southern Power, noting they're glad they kept it when others divested. Selling would be dilutive. They love it as portfolio complement.

CEO and CFO confirmed renewables and storage fall within 5-year plan. CCGT site prep and purchases begin within plan but extend beyond. Capital plan update expected at EEI following September MPSC approval.

CFO confirmed year-to-date trading above $50-60M range with some longer-term contract favorability possibly flowing into 2026, but guidance still forecasts $50-60M range.

CFO confirmed junior subordinated debt is incremental to the $500-600M annual equity issuances, deployed strategically within the plan.

CEO quoted ~$2,500/kW initial estimate pending RFP finalization. Turbines for Monroe replacement already in queue. Additional CCGT for data centers would take 3-4 years for 1 GW+; shorter for smaller turbines.

COO indicated good indicator by Q3 with final deal by year-end, currently focused on solidifying storage contract to understand build-out requirements.

COO expressed confidence that decade-old safe harbor language won't be reversed; DTE made purchases well in advance of law changes to insulate position.

CFO confirmed Ford project ITC was slightly over $50 million in 2024.

Campbell described peak demand extending well into the 2030s with 800-1,000 MW of additional expansion potential; pipeline discussions focused on 2030+ time frame.

Buckler confirmed 5-year ramp is reasonable, with LLPS structure embedding a 5-year ramp provision and 10-12 year peak provision.

Campbell described strong cancellation protections including full remaining minimum bill liability plus benefit of retaining built infrastructure.

Caisley confirmed $60-70/MWh standard industrial rate, with LLPS customers paying 15-20% premium on the demand charge.

Buckler didn't give a specific lag number but said PISA, CWIP, and unprecedented load growth should help close the gap to authorized ROE.

Campbell confirmed IRP already includes generation for finalizing-agreements customers, with long-lead equipment secured, and year-end update to reflect full plan.

Campbell declined to break out individual customer sizes but noted 3 customers averaging 500-700 MW each.

Lloyd and Michael both confirmed Schahfer is NIPSCO regulated asset, not a GenCo asset. Not part of the pool, not contracted to the pool. Cost recovery through FERC process for retail customers only.

Shawn confirmed GenCo will become its own reporting segment as it becomes material. Expected in 2026 fiscal results. Exact timing and disclosure format not yet disclosed but encouraged analysts to start building models.

Lloyd explicitly stated no return-sharing with IURC. Customer flowback mechanism of $1B+ replaces any traditional earnings sharing concept. Clear and definitive.

Shawn confirmed spending split between utility and GenCo but for guidance purposes segmented into GenCo. Would not break out generation vs transmission/distribution within $7B. Competitive information.

Confirmed broad manufacturing expansion across territory: cold storage, food manufacturing, biopharmaceutical, recycling, EV battery, plastics. Multiple states seeing activity.