Shar Pourreza

Jeff framed batch-process load as upside beyond the base plan and pointed to ratepayer-protection alignment; answered the substance directly.

Nye confirmed ERCOT released $2.9B of South Dallas transmission projects, most in Oncor territory. Martin said tremendous progress on $10B bucket in last 90 days with Q2 update planned.

Martin confirmed quality is comparable and emphasized Texas as ground zero for AI infrastructure. Nye detailed the 102.22 GW RTP filing and noted it meets all SP6 requirements.

Jeff confirmed the $9B upside is entirely outside the plan and cited their track record of moving ~$9-10B from last year's $12B upside into the current base plan, plus the 2028 California GRC as another driver.

Jeff explained the lower 2027 California contribution reflects approved GRC attrition mechanics, but highlighted efficiency improvements, regulatory items in pursuit, and comfort with the guidance.

Jeff explained the 30% increase ($10-11B) is primarily driven by Permian plan acceleration to 2030, while the prior $12B upside category remains substantially similar, yielding a $55-60B total capital opportunity through 2030.

Jeff confirmed approximately 20% tax leakage remains the right estimate, acknowledging complexity from Mexican assets and international tax implications.

Jeff confirmed they expect to exceed the 7-9% long-term range within the current 5-year plan period.

Jeff acknowledged the guidance cut directly and had Karen walk through all key drivers including GRC, Oncor rate case timing, and gas prices.

Dore confirmed hyperscalers willing to take gas risk with fixed capacity payment plus variable gas component. Vistra well-positioned to help manage gas exposure. Also offering speed-to-market with existing sites.

Dore explained Meta deal is FOM-type, unaffected by colocation tariff changes. PJM colocation clarity would help Beaver Valley discussions. Pennsylvania remains a market hyperscalers focus on. Could do either colocation or FOM at Beaver Valley.

Burke confirmed 2027 outlook does not embed any new contracting upside. Has 70% hedge and open position for market upside. Wider range reflects multiple levers still to pull.

Burke pushed back on FOM trend narrative. All options remain on table, co-location, FOM, bridge power, new build. Each deal has unique customer characteristics. No options have come off the table.

Burke explained co-location still seen as speed advantage in some markets. Disagreed that FOM/BTM pricing is harmonizing, too few deals signed. Emphasized $2T hyperscaler CapEx through 2030.

Burke said SB6 could unlock Comanche Peak and many other deals including FOM. Session ends early June; expects announcements shortly thereafter once deal parameters become clearer.

Burke provided extensive color on deal complexity, colocation vs virtual PPA flavors, and regulatory dependencies in PJM and Texas. Acknowledged timing depends on regulatory clarity.

Burke directly stated forwards do not fully reflect expected load growth, especially in ERCOT. Said this colors long-term deal pricing discussions with hyperscalers.

Burke confirmed Comanche Peak is most attractive due to ample land and fastest execution timeline. Did not dismiss PJM sites but clearly prioritized Texas.

Trevor deferred enhanced disclosure to the third quarter plan rollout and restated the greater than 9% five-year growth rate without engaging the per-gigawatt EPS framing peers use.

Trevor confirmed AEP is analyzing a GenCo structure and pointed to an announced West Virginia project of about 1.2 gigs, but gave no timeline or financing detail.

Mihalik confirmed incremental 28GW is not in the $72B plan. Formal capital plan update at Q3 call, but may address the $5-8B incremental on Q1 or Q2 calls with financing details. Still 180+ GW in queue.

Mihalik emphasized 180GW backing the 56GW provides ample backfill. ESAs have take-or-pay and large load tariff protections. Fehrman added AEP's rural footprint has strong community support for economic development.

Fehrman acknowledged Microsoft delay but emphasized 500+ customers seeking 180GW of connections, 6GW of diversified industrial load, and ample backfill capacity.

Fehrman said securitization could reduce customer bill impact by almost 75%, decreasing rate increase to around 3.8%. Commission decision expected later this year.

Michalek detailed the FFO path: dip from Moody's deferred fuel recalculation, then recovery by 2026. $2.8B from transaction covers most equity needs, leaving manageable $2B with multiple levers.

Fehrman highlighted 4.7GW contracted for 2025 service, mostly concentrated in Ohio and Texas with nearly 1GW in Indiana. Continuing discussions on tariff settlements.

Maddipati said recontracting layers in through the back half of 2026 and into 2027, with limited merchant exposure left open to preserve predictable earnings into 2029, 2030 and beyond.

Maddipati did not address a drop-dead date or ramp terms, answering instead that multiple customers and multiple locations underpin confidence, with Rochow adding the tariff travels with the customer to other sites.

Garrick said stay-outs are possible and have been done before. Focused on passing affordability savings to customers through annual cases, not pushing a wave of rate increases.

Garrick explained Michigan has roughly 2,800 local units with multi-step approval processes. Both CMS and data centers are meeting with township and planning officials. Progress observed with officials doing proper due diligence on property tax, zoning, agricultural land, and water implications. Feels good about the direction.

Garrick confirmed yes. Rejji elaborated that all three components (distribution reliability, REP renewables, IRP capacity) will be dipped into for the next 5-year plan rolling out at Q4 call. Gas turbine procurement requires upfront spending.

Rejji cited three offsetting factors: difficulty of compounding off actuals at 7-8% annually, lack of decoupling or permanent storm deferral mechanism requiring weather contingency, and need to maintain affordability. Noted CMS was first to go to 6-8% in 2016 and would raise if sustainable.

Rejji said $1B hybrid covered much of parent needs, ~$700M remaining with all options on table. $1.1B utility FMBs still planned. No CapEx pull-forward contemplated.

Rejji said CE Way savings are recurring, targeted $50M last year, delivered $110M. Mix of recurring productivity plus one-time measures like liability management and cost deferrals.

Named the tailwinds (temp gen remarketing, demand charges) but gave no quantified funding bridge for incremental transmission CapEx.

Confirmed both assumptions, flagged $8M/mile as potentially conservative pending Q1 routing work, and pointed to accelerating cash tailwinds in 2027-2029.

Wells explained large load customers pay for interconnection modifications. Tailwinds are: ~$6M/month incremental demand charges per GW of industrial load (earnings + affordability), and indirectly, need for capacity replacement driving future transmission CapEx.

Wells noted CNP submitted ~4 GW to ERCOT (active construction), plus an 11 GW large load study. The 9 GW filing in coming weeks is incremental to what ERCOT reported. Transmission study refresh in H2 will identify new projects needed before end of decade.

Wells noted Houston is unique with disciplined queue approach, achieving reviews within 70 days. Firmly committed projects will follow current rules or Batch Zero. Expects to bring projects online in 2027-2028 timeframe.

Wells explained near-term connections use existing capacity (minimal CapEx), but will create incremental need for import capacity and intra-regional transmission ties, impacting CapEx towards tail end of decade into next.

Wells confirmed commitment to a comprehensive capital plan update later in the year, waiting for PUCT voltage standard decision expected by May before sizing transmission CapEx.

Foster confirmed 2025 equity needs are addressed. Future needs will use ATM, hybrid structures, and potential asset transactions. Funding at 50% debt/50% equity.

Joe defended the filing on reliability metrics and cost control (only 11% of the deficiency is O&M) and expressed confidence in a fair Connecticut hearing.

John addressed the decision as constructive, flagged disappointment on the deferred amount and carrying charge, and confirmed no retroactive carrying charges were in the plan.

Nolan clarified obligation is to GIP not Orsted. COD is the trigger, not first power. 60th turbine heading to lease area. Comfortable with current liability amount. First power expected within weeks. Emphasized unprecedented clarity on major overhangs: Revolution, Aquarion March decision, storm costs July decision.

Moreira confirmed common equity needs unchanged regardless of Aquarion outcome. Flexibility is in alternative financing. Still expects to issue junior subordinated debt with or without Aquarion. Storm securitization cash expected Q3 2027. With Aquarion closing, alternative financing pulled back and outer-year growth rate improves.

Moreira broke down the $160M into $107M GSEP roll-in (no customer impact), $10M PBR adjustment (approved), and $45M rate base roll (denied). Failed 3 of 18 performance metrics related to subjective customer surveys. Filed motion for reconsideration and intent to file rate case.

Decision released during earnings call. Moreira said it appears in line with plan and better than draft decision, but details still being reviewed. Will provide more information at EEI conference.

Moreira deflected specific FFO/debt target, stated plan keeps them above Moody's 13% downgrade threshold. Confirmed sizable storm costs recovery throughout forecast period.

Nolan stated indifference on commissioner count, emphasized wanting fair and transparent process. Noted governor nominations are pending with no hearing date set.

Answered directly, citing 16% and 38% reliability improvements and the need to recover reliability capital already deployed.

Tierney gave near-term available capacity of 100-200 MW for early queue positions and a $250 million per gigawatt investment rule of thumb.

Tierney met with Governor Shapiro last month. PA customer average interruption duration down 27 minutes since 2024. No surprises approach across all states.

Tierney confirmed turbine delivery on track for 2031 online date. Taylor said approval expected early Q4; rate base growth rises from ~10% to ~11% upon approval.

Tierney plans to pursue additional 1,200 MW dedicated to data center load, leveraging Siemens turbine relationships from first EPC project.

Taylor confirmed 10.4% base rate base growth, ~11.4% with WV generation. Won't put speculative items in plan but will update as approved.

Tierney acknowledged the audit findings with specific numbers and outlined planned response within 30 days.

Tierney directly addressed growth target, expressed confidence in upper end, and explained PA O&M is fully recovered in rates.

Lloyd cited 4 GW of signed capacity combined with multiple counterparty engagement and strong demand as basis for firming pipeline. GenCo model positioned as compelling competitive advantage.

Shawn explained earnings as net of total capacity cost and risk-adjusted return, whether through capacity purchases or asset construction. Both paths contribute to guided GenCo EPS.

Shawn confirmed active engagement with rating agencies. Risk management provisions similar to base business protection. 14-16% FFO/debt with 13% downgrade threshold provides adequate cushion.

Lloyd confirmed large investment-grade customer served front-of-meter. Would not name counterparty due to confidentiality. Described the transaction as a blueprint for subsequent customer negotiations.

Lloyd directly confirmed data center capital is fully incremental to both base and upside plans. Upside plan covers AMI, Pipeline Integrity, and Transmission only.

Clearly confirmed special contract can be filed and announced independently of Genco declination timeline. Genco provides flexibility but is not a prerequisite.

Lloyd declined to narrow beyond 2025 timeframe but confirmed optimism and well-progressing conversations. Would not commit to specific timing ahead of signed contracts.

Identified cash from operations outperformance as primary source, followed by junior subordinated notes and shortened regulatory lag. Confirmed no additional equity needed.

Womack confirmed conversations are happening but explicitly declined to characterize outcomes.

Womack ruled out Southern being the next AP1000 builder unusually plainly while committing to work with the administration on policy.

Womack confirmed recontracting conversations are underway and flagged pricing upside, without quantifying the opportunity.

CEO confirmed both recontracting conversations and hyperscaler discussions are underway at Southern Power, noting creditworthy counterparties and construction experience.

CEO clearly stated SO is not ready to commit to new nuclear but expressed enthusiasm for industry-wide AP1000 efforts and administration support.

Poroch confirmed SNG South System 4 expansion is on track, ~$3B total ($1.5B SO share), with great interest in contracting capacity through the pipe that runs through their backyard.

Poroch disclosed Southern Power won 2 PPAs in the Georgia RFP repriced at almost 3x current levels, providing a live data point for future recontracting opportunities in the early 2030s.

Womack declined to comment on speculative transactions but said they always consider who is the best owner of each asset. They like their current portfolio but will look around corners.

Blue confirmed no limit on state contracting volume, other New England states interested, and data center contracting possible with stakeholder support. Comprehensive answer.

Blue outlined three guiding principles (first-of-a-kind risk, cost overrun risk, balance sheet protection) but did not commit to any specific nuclear path or consortium participation.

McFarland explained 45Z reduction from 10c to 7c accounts for half the consensus delta. Tailwinds manifest most strongly towards back end of plan. Millstone RFP clarity expected back half of year. Motto is underpromise and overdeliver.

Blue confirmed forecasts based on years of meter-level experience, not load letters. Historical performance largely above minimums. Big picture driver is ability to deploy capital on behalf of customers driving long-term financial performance.

Blue emphasized robust bipartisan support across all levels of government, citing strategic value for AI, defense, and energy reliability. Stopping project would cause energy inflation.

Blue detailed 200 punch list items from regulatory inspection, primarily electrical system material condition and documentation. Over 4,000 inspections completed, 120 of 200 items closed. 200 people working around the clock.

Blue and Leopold provided comprehensive response on derisking status, tariff exposure limited to $2.5B remaining non-US spend, and $200M contingency buffer.

Partial: called capital an option and sized a gigawatt at $2 billion to $2.5 billion, but deferred the decision to the third quarter call.

Direct: confirmed construction on time and on budget, and said an alternative hyperscaler could take the site in a worst case.

Acknowledged timing shifting out. No capital in plan for replacement. Sees potential capital upside if non-renewal triggers new build.

Provided year-by-year growth color: 6.5-7% in 2026, 7-8% in 2027, ~8% in 2028-2030. Acknowledged some potential to accelerate but emphasized execution certainty.

Lauber noted all capacity plans unchanged post-DeepSeek, tariff discussions with large customers expected in next six months.

Confirmed all Cloverleaf load is incremental to the 1,800 MW already in the plan. Clear and unambiguous.

Lauber provided detailed update on acreage, 1 GW initial demand, positive city engagement. Direct and comprehensive.

Pushed for an out-of-cycle CAGR raise ahead of Q3; management reaffirmed 5-7% and top-half-from-2028 confidence but deferred any update to Q4.

Asked about a genco structure in Indiana; management said it has studied it, hasn't needed it, but may revisit as large loads are signed.

Brian committed to providing a more defined FFO-to-debt target range by the next February update cycle, citing improving credit profile and storm securitization clearing.

Harry pointed to IRP updates as the catalyst for CapEx revision. Brian noted February is the annual capital update cycle but would update sooner if warranted.

Brian confirmed top-half EPS growth opportunity in back end of plan driven by load acceleration, and said FFO-to-debt guidance above 14% will become more specific over time.

Harry confirmed no pullback from hyperscalers; DeepSeek anticipated and seen as potentially increasing AI demand. Near-term focus is cloud computing, generative AI comes later.

LaRossa explained that bills enabling nuclear and gas are in Trenton. An IRP would inform but not dictate outcomes. PSEG can help with IRP as it does for Long Island, but policymakers own the decisions.

Cregg indicated the CAGR reflects market fundamentals rather than PTC floor, and as market conditions evolve, the outlook will be updated accordingly.

LaRossa expressed confidence in working with any administration. Data center opportunities in NJ haven't slowed, with a TEAC meeting revealing additional Kenilworth load. Cregg deferred timing to post-election clarity.

LaRossa acknowledged current grid headroom but said topology changes depend on state policy decisions around generation type (gas, solar, batteries). Full details deferred to February roll-forward.

Management characterized FERC stance as positive directionally with urgency, noting colocation remains viable. Dan Cregg confirmed messaging is consistent with strong interest.

LaRossa clarified the 4,700 MW includes data centers plus large load and EV interconnections. Emphasized state economic development efforts are bearing fruit, separate from Artificial Island.

Andrew noted Q1 growth near top end of long-term range. Driven by extra-high load factor customer ramps and TSMC Fab 2 coming online. Will revisit as backlog converts to committed. Comfortable with 5-7% and 4-6% for now.

Andrew said rate case outcome, formula rate, and bilateral contracting could all narrow the gap. Subscription model upfront funding reduces external financing needs and improves cash flow conversion.

Ted confirmed 5-7% based only on high-confidence committed projects. Uncommitted queue, further TSMC expansion, or new projects would be incremental upside. Andrew added committed queue ramp extends into 2030s.

Andrew said rate case and formula rate are prerequisite to closing gap. As larger projects enter service and more consistent recovery is achieved, will provide more transparency on EPS trajectory.

Andrew said formula rate is key to converting lumpy earnings into evergreen growth. Will reassess base year and growth framework once rate case concludes and formula rate structure is understood.

Ted confirmed 4.5 GW committed (data centers + manufacturing). 20 GW uncommitted. Desert Sun Phase 2 subscription is Tranche 1; additional tranches planned as new generation and transmission capacity is developed.

Poppe reiterated the need for a durable, financeable framework but declined to detail how capital would be reallocated under a plan B.

CEO said minimum outcome needed to prevent additional shareholder costs and enable modeling tail risk. If minimum not met, entire plan on table. But encouraged by current progress.

CEO confirmed transmission CapEx already added to $73B plan. Making plan bigger deferred until after SB 254 Phase 2 resolution. Currently prioritizing making plan better for affordability.

CEO confirmed policymakers are engaged, pointed to Anne Patterson's new role as senior counsel to governor on wildfire issues as a signal of state recognition.

CEO explained transmission infrastructure is the key constraint, with no new generation needed for first 4 GW. Customer timing and PG&E timing matching well.

Sorgi said hearing was one day focused entirely on data center affordability (transmission issue, not directly relevant to distribution case). Actively engaged with parties on settlement, no hard deadline. Comfortable whether resolved through settlement or commission decision.

Sorgi explained no earnings impact: Mill Creek 6 has AFUDC through 2031 and plenty of time to refile. Mill Creek 2 being addressed in current rate case hearings. Commission likely felt CPCN wasn't proper venue for rate mechanisms.

Sorgi said open to agreement with IPPs but budget impasse and REGI are gating issues for any legislation. Expects committee debates to begin in early 2026.

Bergstein confirmed ATM is base case but will remain opportunistic and assess all options for most efficient cost of capital.

Sorgi gave a thorough explanation of why regulated utility model provides stability over competitive market's short price signal, confirmed PPL ready to build gen in PA if legislation passes.

Asked by an associate (Andrew) on for Shar Pourreza. Management confirmed sites are secured for the 2.2 GW under ESA with groundbreaking expected in Q2. Beyond those, projects at various stages of approvals.

Asked by an associate (Andrew) on for Shar Pourreza. Management confirmed they are not part of the nuclear consortium but are studying nuclear including SMRs, participating in Missouri state energy plan workshops, and looking for price and schedule certainty.

Lyons directly addressed positioning within range, noting load growth and rate base growth are back-end loaded in the 5-year plan.

Lyons confirmed capacity to serve 2 GW by 2032 and more beyond, citing acceleration of renewables, battery storage, and gas-fired generation.

Management confirmed nothing prevents bilateral deals now. Some clients want to proceed; others are pausing to see regulatory outcomes. Characterized it as a pause, not a full stop.

Management expects a mix of organic investments (>10% IRR including uprates) and share buybacks. Shane Smith explained the $0.50 upside sensitivity was illustrative based on deployment timing (development vs M&A).

Joe said nuclear vs gas pricing hard to compare given gas input price uncertainty and carbon risk. Nuclear offers firm 20-year pricing that customers find very attractive.

Joe expects deals completed before Q4 call. Front-of-meter focus continues with interconnection process as gating function. Cannot guarantee timing of other parties' approvals.

CEO gave extensive answer on Phase 2 timeline (abstracts Nov 3, papers Dec 12, report April 1). Noted all submissions will be public. Emphasized need for broader economy-wide reforms beyond just utility issues.

CEO reframed as customer cost issue. CFO noted company is in different position: no equity in forecast, measured approach to capitalization, and decades-long track record of increasing dividends.

Campbell said capital structure will be addressed in the rate case body after KCC decided it posed substantive issues; company is driving toward settlement.

Campbell confirmed agreements expected to finalize this year, with plan updates at Q3 and year-end calls, layering in impacts once customer announcements are made.