Michael Sullivan

Harris confirmed the fast ramp is on track, citing equipment deliveries, aerial imagery, and DTE team presence on the construction site.

Harris declined to generalize, saying terms vary by ramp, and pointed to renewables and storage near-term with a dispatchable resource later per the IRP.

CEO confirmed Trading remains core but all non-utility businesses examined annually for shareholder value opportunities. No change imminent.

CFO emphasized deals are bespoke in capital timing. Google has heavy renewables/storage plus baseload. Late-stage pipeline includes some at similar scale to Google. Each deal structured differently based on resource mix needs.

CFO explained Q1 trading timing was expected and similar shaping occurred in 2023/2024. Contracted positions will flow back through year. Some tailwinds from 1-3 year hedged contracts continuing from 2025. Highly confident in full-year high-end guidance.

CEO confirmed MISO queue positions and turbine deposits secured for Monroe replacement and potential data center load. IRP filing in Q3 will determine resource mix. CCS-capable CCGT needed for 24/7 dispatchable resource once Monroe retires.

CFO noted some 1-3 year structured/hedged contracts carry favorability into 2026 providing tailwinds, but guidance remains at $50-60M. Strong 2025 performance ($114M) allowed flexibility leverage across the company.

CFO confirmed ~40% equity funding ratio for incremental capital, varying by year based on timing of cash flows and tax credits.

CEO confirmed CCGT investment extends beyond 5-year plan into 2031.

CFO stated 15% provides adequate cushion over rating agency thresholds (13-14%); working with agencies to ensure comfort with financing plan and strong cash flows.

CFO explained 2029 expense pull-forwards provide carryover flexibility into 2030 even after 45Z expiration, maintaining high-end positioning.

CEO noted potential Section 111D rescission would improve gas plant economics; coal plants ultimately must retire due to age but may get some near-term flexibility.

CEO confirmed battery storage in plan but not yet purchased, providing flexibility. Reiterated 80-85% of spend on services with 1-2% worst-case tariff impact.

CFO provided a clear quantification of rate base CAGR at approximately 8%.

CFO explained Vantage YoY decline due to 2024 Ford project ITCs ($50M+) not repeating, with new project ITCs expected in 2026-2027.

Direct: acknowledged a candidate moratorium proposal and community filings, and countered with $100 million of customer savings and water-use facts.

Direct: reaffirmed the ATM and raised the cash-return-versus-AFUDC lever, while saying nothing is off the table.

Lauber acknowledged Illinois is historically hard to settle but happy with rider settlement progress. Expects annual rate case cadence as pipe retirement ramps.

Lauber said coal units being evaluated for natural gas conversion following EPA rules. Units 7 and 8 pushed out to ensure reliability during new capacity build.

Confirmed data center customers pay corporate allocations, which spreads common costs across larger rate base. More benefit visible as assets enter service in 2028-2030.

Too early to discuss Illinois rate case settlement. Reaffirmed 7-8% long-term growth rate absorbs the settlement headwind. Incremental $1B from hyperscaler growth offsets impact.

Liu confirmed billions of dollars of capacity remaining for junior subs under both S&P and Moody's frameworks.

Roughly 3% from equity dilution per Liu. Bespoke VLC assets at 14% of rate base by 2030.

First mention of combined cycle potential. Oak Creek coal units can't extend further; same interconnect needed for new CTs. Power of Future converting to gas.

Liu explained accounting entry taken for storm damage to Texas solar. Pursuing insurance recovery and capacity restoration.

Confirmed Vantage will be in 5-year plan update. Also seeing strong residential growth with 4,000 housing starts in 2 counties.

Liu explained lower tax rate would benefit customers through lower bills, modestly impact holding company tax shield, but increase rate base long-term.

Detailed breakdown: distribution domestically sourced, generation 50-60% labor. Solar panels and batteries are highest tariff exposure. Would notify regulators of cost increases.

Liu confirmed 4.5-5% sales growth target on track for late 2026, with LC&I already growing 1.9% and 11 of 16 sectors positive.

Described dual track: ROFR legislation in H1 2025 or competitive bids also in H1. ROFR benefits both ATC and Wisconsin customers.

Maddipati declined to name specific levers, noting it is early for 2027 and that the range will be updated through the normal planning process later this year and into early next.

Maddipati confirmed the $2 billion renewables and $1 billion distribution reliability opportunities sit outside the current plan and said the balance sheet flexibility from the NorthStar repositioning means equity would not necessarily be taken up to fund them.

Rejji said load ramps start materializing around 2028 with material ramp in the next decade. Additional CapEx likely enters the next 5-year plan, but premature to say it would immediately increase EPS growth range. Job one is converting the opportunities.

Garrick said DIG-to-utility transfer was attempted in the last IRP but affiliate transaction hurdles were too large. Current IRP will propose approximately 1.5 GW of net natural gas to replace Campbell 3 and 4 peaking units. IRP includes REP-approved renewables, batteries, and a growth scenario for data center interest.

Garrick remains open to settlement but comfortable going full distance given constructive outcomes. Annual rate cases keep increases small and in line with inflation. Open to longer cycles with the right construct but nothing serious in discussions yet.

Garrick said CMS has 140 years of community relationships and helps steer data centers to pro-investment areas. Moratoriums are short (30-180 days) and still allow progress. Cited Mason, Michigan lifting its moratorium ahead of schedule with new zoning for data centers.

Rejji confirmed the ~$0.40 equity per CapEx dollar sensitivity remains the working assumption. Downward pressure possible from tax credit monetization, strong cash flow from forward test year, PPA earnings at 9%, and hybrid capacity. Data center tariff provisions focused on protecting incumbent customers, not reducing equity needs.

Garrick confirmed Q2 data center at late 2029/early 2030 for first electrons with ramp thereafter. The other 2 final-stage data centers are earlier in the 5-year window, and CMS can deliver from supply and infrastructure perspective.

Rejji outlined offsets: $2-3B hybrid capacity, additional equity capacity, PPA financial compensation mechanism shifting from owned to contracted renewables. $700M+ transfers still in plan.

Rejji confirmed additional liability management capacity remains, plus $3B of hybrid capacity under S&P's 15% threshold. Tools include tax planning, O&M, CE Way.

Rejji bridged from 35-40 cents equity per dollar of CapEx, yielding ~$500M equity in 2025 stepping down in outer years as tax credit transfers ramp to $700M aggregate.

Ralph declined to disclose the rate case size, saying the intent was only to signal alignment with the state's EO1 timing.

LaRossa noted affordability remains the key legislative topic, with possible resource adequacy solutions also under discussion. Monitoring for any introduced legislation.

Cregg explained BGS provides stability for utility bills; broader market pricing depends on load growth vs supply, expects tighter market ahead.

Cregg provided high-level hedging approach, near-fully hedged for prompt year, cascading off in out years, without specific percentages.

Cregg explained PSEG has been growing 6-7.5% off an increasingly higher base for several years, which implies higher absolute dollar growth even if the percentage CAGR appears stable.

Cregg said the mix could shift modestly if power prices rise but no major change expected. LaRossa added that the PTC floor functions like a regulated return, so nuclear risk profile is quasi-regulated even below the threshold.

LaRossa firmly ruled out return to merchant generation. Without legislative change, PSEG is left with the PJM process, which has not attracted new baseload generation in New Jersey.

Cregg said the main benefit was preserving existing PTC protections. Bonus depreciation applies only to the unregulated piece with limited capital, providing modest help.

LaRossa said political leaders asking questions is expected after such a spike. Cregg added they are not aware of anything problematic but the investigation is reasonable.

LaRossa acknowledged 5-6 year turbine lead times, emphasizing that decisions need to be made now. Current law prohibits PSEG from building generation; legislative change is the prerequisite.

LaRossa outlined three paths: rate-based generation, incenting competitive generation, or importing via new wires. PSEG positioned to participate in all three scenarios.

Bruce said the base case funds the project on balance sheet, extending the 3x leverage target to 2029; a partner could free capacity to increase buybacks.

Gaudette confirmed need for deal closure in 2026 for 2029 COD but declined specifics. Identified infrastructure interconnections and gas infrastructure as remaining work items rather than economics.

Chung said they were opportunistic on buybacks when stock was undervalued. Plan remains $1 billion but would deploy extra cash flow toward repurchases if available.

Bruce Chung outlined: $750M organic growth plan (50% Smart Home, 50% C&I/retail), all 3 TEF plants, 445MW data center deals. 80/20 organic vs buyback split.

Rob Gaudette noted engineers assessing both the 1GW uprate plus additional 25-50MW incremental clips across other assets for the RBA.

Management plans standalone NRG update at Q3, with combined LS Power update expected at year-end or Q1 call after close.

Rob Gaudette explained the deal involves edge-type modular data centers that ramp in smaller increments versus hyperscaler 100MW clips.

Management expects 80/20 to hold for next 3 years but acknowledged capital allocation may evolve in the 2027-2029 ramp period.

Management indicated GEV/Kiewit builds at $1,500-2,000/kW market rate, expecting to significantly exceed posted hurdle rates.

Steve outlined two-track Ohio strategy: existing rate case settlement expected near-term with new rates Q1 2026, plus filing under new 3-year forward structure later this year for rates in 2027.

Andres disclosed 650 MW was with Meta and all 1.6 GW was data center customers. Skewed towards solar plus batteries overall. Declined to provide specific project locations.

Andres confirmed AES will build gas if customers request it, noting 10 GW of gas currently in operation, but will react to customer requirements rather than proactively pushing gas.

Steve reported $3.4B of $3.5B target achieved. Remaining $500M through 2027 from Vietnam sale, smaller thermal portfolio sales, operating renewable partnerships, and potential technology portfolio.

Andres reported constructive Hill meetings. Expects reconciliation before August recess with pragmatic outcome. Safe Harbor seen as critical to maintaining credibility of US programs.

Steve confirmed refis are nearly fully hedged with no additional interest exposure. Maturities in July and January will be addressed 3-6 months in advance.

Steve confirmed 2026 will hit the CAGR trendline with low-teens EBITDA growth, driven by accelerated cost restructuring. 2025 growth muted by Brazil exit and Warrior Run headwinds.

Steve quantified that roughly a third of the $750M coal EBITDA (~$250M) may continue beyond 2027, a meaningful change from the prior full-exit plan.