David Arcaro

CEO described several-hundred-MW behind-the-meter primary power opportunity. Pipeline of similar projects identified across the country. Creative solution that could differentiate DTE as a provider for colocators nationally. CapEx update expected midyear.

CEO noted Commission Chair's comments support current ROE levels. ALJ in DTE's own case recommended 9.9% ROE. DTE expects flat ROE in its case and views 8.2% recommendation (for another utility) as not reasonable given borrowing costs.

CEO indicated intent to firm up terms before IRP filing pulled forward to Q3 next year, settling on key terms and ramp rates with hyperscalers in active negotiations.

CEO described behind-the-meter project as primary power using combustion turbines for a data center outside Michigan. Deal not yet fully closed but positioned as a new vertical for Vantage.

CFO confirmed strong position with warm July providing further upside; looking for opportunities to ensure great 2025 and help future years.

COO confirmed bill supports plan, safe harbored ITCs through 2029, battery storage ITCs through 2036, transferability maintained. Safe harboring insulates from FIAC exposure.

CFO detailed $230M transferability used in 2024, safe harbored through 2027, with tax equity structure and strong balance sheet as fallback options if transferability were at risk.

COO confirmed constructive order with no ROE/equity layer change, IRM extension, and positive commission tone on reliability progress.

COO quantified pipeline at 3 GW with up to 1 GW of existing excess capacity still available near-term.

Management noted PJM conversations progressing but inherently slower than Texas due to more complex regulatory and policy framework.

Brad Bentley noted strong Texas margins maintained competitively, slight East margin erosion managed closely with integrated value proposition.

Management cited accelerating hyperscaler CapEx announcements, NRG's unique commercial capabilities, and heightened interest as pricing drivers.

Rob Gaudette noted off-peak prices moving up from industrial/AI loads, but forward curves still below fair value awaiting load announcements.

Management confirmed the margin is well-protected over the contract duration but declined to disclose the specific hedging/indexing structure.

Management expressed confidence in portfolio completeness across generation, large load, data center, and retail segments.

Management declined to mark-to-market but emphasized strong accretion across a wide variety of market scenarios.

Rob Gaudette noted interconnection typically faster than turbine delivery in ERCOT, and some sites already have existing equipment.

Management reported seeing the opposite of hesitation, more inbound interest, and all hyperscalers reaffirming or expanding capital commitments.

Andres outlined multiple battery use cases: behind-the-meter at data centers, paired with solar for dispatchable energy, grid services, and even augmenting gas peakers. More than half of solar projects already include batteries.

Andres emphasized PPA signings are lumpy with fewer, larger projects. Focus is on quality and profitability rather than MW count, trending toward upper end of IRR guidance. Confident in hitting 4 GW for the year.

Ricardo emphasized no demand drop, citing faster time to power, 20-year price certainty, and cost competitiveness even without tax incentives vs any other electricity source.

Ricardo confirmed extremely strong demand with customers trying to lock in PPAs quickly before tax incentive phase-out. 4 GW of pipeline projects not yet contracted are attractive to customers.

Andres reported no demand pull-forward, continued strong data center demand driven by time-to-power advantage. New contracts include change-in-law provisions for tariff/policy shifts.

Andres confirmed intent to retain control of AGIC, noting it was set up 15-20 years ago, is a unicorn, has lowered insurance costs and improved reinsurer quality.

Steve indicated asset sales include coal exits, technology portfolio monetization, and partnership sell-downs, with a more conservative but confident execution view.

Andres framed it as harvesting the existing 50 GW pipeline rather than a strategic retreat, noting they will build fewer GW but maintain financial results.

Taylor confirmed 9.5-10% ROE target maintained through planning period, supported by regular rate case filings and formula rate investments.

Tierney committed to constructive engagement with Governor Sherrill on affordability while maintaining investment for reliability. Rates significantly below in-state peers.

Taylor quantified about $1B currently identified for transmission interconnection across contracted and active customers; noted wide range depending on location and size.

Tierney characterized incremental CapEx as firming confidence in 6-8% range rather than raising the growth rate.

Tierney confirmed upside likely from additional customer contracts, open window awards, and additional windows but won't include without line of sight.

Tierney noted lack of clarity in deregulated states but encouraged by governors' engagement in September technical conference.

Tierney pointed to models in NY, TX, and CA for adding generation without full reregulation, praised governors' leadership.

Tierney was direct that capacity pricing is harmful if not bringing new generation, committed to working with NJ commission on mitigation.

Burke expressed high confidence in the 2% to 4% O&M target, citing strategic sourcing and early AI adoption as areas of upside.

CEO said Cluster 26 engineering takes 6-8 months. Seeing interest beyond Bay Area in Central Valley. Major developer at EEI conference was unaware of California capacity. 33 GW added to grid since 2020.

CEO emphasized current 23% rate reduction for vulnerable customers has been achieved through O&M savings alone with limited large load contribution. Load growth impact in latter half of plan as path to flat.

CEO provided detailed SB 254 Phase 1 benefits before addressing Phase 2: disallowance cap moved to ignition date, no upfront contributions, contingent call only, credits against future disallowances, 25% funding rebalance.

CEO confirmed October 30 commission meeting agenda includes undergrounding recommendations. GRC includes bridging strategy of 300 miles/year if 10-year plan delayed. Hit 1,000 miles at 25% lower cost.

CEO defended undergrounding as permanent solution in highest risk areas with declining unit costs. Still intends to file 10-year undergrounding plan this year.

CEO reiterated opposition to shareholder contributions citing inverse condemnation and that increased cost of capital would harm customer affordability.

CFO noted Moody's utility upgrade was positive but parent still below IG. All financial metrics in line with IG. AB 1054 resolution is the key remaining catalyst.

LaRossa confirmed mature applications increased from 2,600 MW to approximately 2,800 MW out of the 11,500 MW total pipeline.

LaRossa pointed to flat O&M management, past mechanisms with the regulator (e.g., changing depreciable life of gas assets), and AMI rollout design. Emphasized the issue is quickly becoming a reliability problem requiring new supply.

LaRossa emphasized PSEG is pushing for state decisions on four dimensions: load forecasts, reliability targets, affordability goals, and environmental policy. BPU technical conference occurring same day.

Cregg confirmed continued interest across both New Jersey and Pennsylvania assets. Declined to provide specific timing, saying they will let timing speak for itself.

LaRossa outlined three-pronged approach: BPU deferral mechanisms, energy efficiency programs, and long-term generation supply legislation. Emphasized unique regulated utility sites with pipes and wires.

Cregg gave an unambiguous no, nuclear contracting does not depend on the FERC colocation proceeding, though resolution would be helpful.

LaRossa questioned whether a functioning PJM market still exists, expressing reliability concerns. Cregg noted the collar provides near-term stability while targets remain at PTC floor.

LaRossa directly refuted any slowdown by pointing to the 12x increase in large load inquiries in New Jersey alone.

CEO outlined generation pipeline: 10GW building now through end of decade, certified RFP for early 2030s, new 2-6GW RFP for 2032-2033. Alabama also active on RFPs.

CEO said company is well positioned with turbines identified for RFPs and strong labor relationships from Vogtle construction (10,000 workers at peak), but acknowledges market tightness.

Womack confirmed upside opportunities exist for the latter part of the decade, with advanced discussions ongoing with other large load companies.

Poroch said another all-source RFP could begin as early as 2026 per the IRP approval, targeting the early 2030s (perhaps 2032). Size and parameters still being assessed.

Tucker noted the detailed tariff framework was only finalized April 15 so reaction is early. Despite the rules being known, pipeline has grown over the past three months.

Womack expressed confidence in turbine access due to diversified supplier relationships and history with OEMs, while acknowledging heavy demand and reservation fees required.

Tucker said 17% FFO to debt achievable by middle to late part of 5-year plan, with 2025 expected to be flattish due to storm cost recovery lag.

Garrick confirmed the pipeline has advanced and grown, with both positive indicators of support for the data center tariff and Michigan's growth.

Garrick said the rate construct requires data centers to pay for all capacity, energy, transmission, and distribution on their own. Aligns with Microsoft's public commitment to protect residential customers. Contracts require MPSC approval. Data center can be online as early as 2028.

Garrick confirmed pipeline flipped from 65% manufacturing to 65% data centers after tax exemption, aided by challenges at other RTOs making MISO more attractive.

Garrick noted past storm tracker proposals lacked commission support. Now pursuing deferred accounting order for this historic storm, leveraging Liberty Audit best practice recommendations.

Garrick noted surplus from last IRP helps attract business, with the REP and upcoming IRP filing addressing incremental supply needs. Load comes on in stages.

Garrick acknowledged settlement is unlikely given timing but expressed confidence in constructive outcome through staff's constructive starting position.

Wells separated the $500M 765 kV line (already filed at ERCOT) from incremental transmission needs from accelerated large loads. Update on incremental transmission projects expected in second half of the year.

Foster confirmed CAMT benefit provides 60-70 bps near-term balance sheet improvement and unlocks ~$1B incremental CapEx without adding equity. Guidance just released the prior afternoon.

Wells detailed conservative approach: 75% haircut vs ERCOT's 33%. Of 1.5 GW data center assumption, already working on connecting ~1 GW. Of 2 GW hydrogen assumption, customers breaking ground on 1.5 GW.

Wells noted CNP substations are currently included in the statewide 765 kV proposal. Right of first refusal applies. Being conservative on timing since policy could change.

Data center demand accelerated from 8 GW to north of 11 GW in Houston alone. Indiana also seeing hyperscaler interest with vertically-integrated business and conversion capacity.

Wells explained 40 GW of interconnection requests received, some exploratory. 10 GW reflects realistic materialization through 2031, to be updated annually. Remaining 30 GW may come over time.

Blue cited Eli Lilly facility west of Richmond as example of meeting large non-data-center customer with aggressive timeline. Economic development team continues to see exciting possibilities outside data centers.

Blue confirmed biennial IRP cycle with annual updates in between.

Blue confirmed demand remains very high with continued focus on traditional cloud and inference workloads, customers planning well into the 2030s based on existing commitments.

Blue confirmed no new developments. Current 55% fixed-price contract runs through August 2029. Rhode Island legislative activity is encouraging but no timeline for action.

Ridge noted PJM's forecast is backward-looking and doesn't fully reflect Dominion's queue increases, with conversion rates approaching 100% from construction LOA to ESA stage.

Blue was emphatic that CVOW has all federal permits, is authorized by Virginia law, has bipartisan support, and stopping it would be the most inflationary action for Virginia energy.

Mike cited NorthPoint example at PECO where existing infrastructure enabled rapid connection. Calvin described centralized large account strategy with 25 largest customers meeting in Chicago.

Jeanne described two-step process: cluster study completion then TSA signing before moving to high probability column. 6GW studied awaiting TSA, 20GW actively being studied, 20GW awaiting next cluster.

Calvin gave clear affirmative on utility-owned generation, emphasizing portfolio approach and partnership with states. Jeanne cited cost of capital advantage and customer benefits.

Calvin noted data center activity across multiple jurisdictions beyond Illinois. Mike mentioned active cluster studies with results expected in Q3-Q4.

Jeanne provided detailed load ramp timeline. Calvin described centralized customer strategy organization and EEI-hosted meeting with 25 largest customers.

Calvin outlined proactive customer support measures including suspended disconnections, extended payment plans, community forums, and connecting customers to state/local assistance.

CEO confirmed continued data center and power generation inquiries with engineering teams investigating, but declined to provide specifics until contracts are signed. APT already serves some power gen facilities.

CEO confirmed affordability is an ongoing conversation with regulators but emphasized no negative feedback. Regulators understand the reliability investment need, reinforced by Winter Storm Fern. Natural gas bills remain the lowest utility bill in the household.

CFO described rate case filings as routine regulatory process focused on refreshing ROE, cap structure, and riders. Expects completion by end of spring.

CEO confirmed none of the eleven are power plants, described diverse industrial mix across eight states, and declined specifics on unsigned prospects.

Sideris confirmed accelerating interest, highlighting Charlotte area as emerging hub plus growing Florida and Southern Indiana demand. Cited vertically integrated model as competitive advantage.

Harry confirmed flexibility provisions are already in signed contracts, including ability to curtail load or use backup generation for about fifty hours per year. Data centers agree because it speeds power delivery.

Brian declined to pinpoint 2027 specifically but confirmed load growth step-up that year creates the opportunity for top-half earnings.

Harry cited 7GW+ advanced stage pipeline with broader pipeline at least double that. Lynn added that 50% of the pipeline to 2029 is now data centers.

CEO acknowledged reading various third-party estimates but noted they appear within the fund's envelope, though hard to aggregate as they cover different loss types.

CFO explained gross-up approach with offsetting receivables, no earnings impact. From regulatory capital and rating agency perspective, bases are covered.

CFO noted GRC provides flexibility to reprioritize capital. SVP Powell said risk models will be re-evaluated; rebuild areas likely to see more undergrounding. CEO noted rebuild projects check multiple boxes.

CEO discussed multiple potential levers including fund scaling, liability cap durability, but declined to specify preferred path. Noted Senate announced insurance reform package.

Pushed back on the peak-orders framing, citing 116 GW now rising to at least 125 GW by year-end and continued backlog growth over the next six quarters; answered directly.

Scott reported ~30-35 framework agreement conversations ongoing but none closed yet. Customers continue ordering by the drink instead, including large 2030 contracts in Q1. Expanded scope including Electrification in some discussions is elongating but productively enriching negotiations.

Strazik noted nuclear discussions progressing with U.S. administration, Sweden, and Poland but sequential in nature with longer close timelines than gas/grid. Hyperscaler conversations active for first-half-of-next-decade delivery. Pipeline growing but announcement timing uncertain.

Strazik emphasized 20+ year economics favor large frame gas turbines for baseload. Near-term surge drives smaller modular/aero applications as bridge power, transitioning to backup over medium term replacing legacy diesel gen sets. GEV positioned across both segments.

Bergstein and Sorgi indicated another Kentucky CPCN filing is increasingly likely this year, with battery coming first as quickest resource, plus potential Rye hydro and additional gas.

Sorgi expressed confidence that PPL is aligned with the governor's affordability goals given its sub-4% bill increase after a decade stay-out, and sees no need to alter stance in Pennsylvania.

Bergstein cited smart grid deployment, IT upgrades, and AI across O&M as levers. Some already in the 1% plan with more potential upside.

Bergstein confirmed growth accelerates starting 2027 after full rate case impacts, with 2027-2029 growth pretty linear. Not back-end loaded.

Data center campuses can be 1,000-5,000 acres with ~1 GW per 1,000 acres. Renewables and storage provide initial load interconnect with baseload gas following. Grid Alliance upgrades can free additional megawatts. Returns described as higher than ever seen in industry from supply-demand imbalance.

John confirmed 2029 program on track with tax and trade protections in contracts. 2030 still too early for most customer focus as demand concentrated in 2027-2029 timeframe. Mike emphasized demand picture unchanged despite changing tax law framework.

John pointed to 20-year track record with tax equity pre-IRA. Tax equity providers doubling interest in NextEra due to flight to quality. Transfer program allows picking best returns between transferability and tax equity. Data center demand unchanged with continued strong appetite for renewables.

2-3% focused on base $45B plan; no AD/CVD impact expected; OEM agreements give comfort on managing wind and solar tariff impacts.

Pipeline unchanged at 8,900 MW; no update to pipeline expected until Q3 per normal five-year sales cycle.

Mark acknowledged ongoing risk from European oil/gas companies (NatGrid, Enel, EDF) but noted project-specific terminations have resulted in customers rebooking. Sponsor-backed portfolios carry inherent risk but fundamentals remain strong with positive policy environment and growing load profile.