Anthony Crowdell

New CFO Aaron Moss took question. Filed March for $3B+ program replacing 20-year-old smart meters. Half in current capital forecast, half beyond 2030. Intervenor comments expected summer, decision follows.

CEO noted need for both large volume and stability in claim types before extrapolating exposure. Referenced lessons from TKM and Woolsey where new facts and variety of claims made estimation very difficult.

CFO confirmed write-off only occurs with refinancing. Additional options available now from TKM/Woolsey securitization success. Evaluating broad range of cost-efficient alternatives.

CEO indicated general Sacramento view is current fund covers current fires, expansion covers future fires. CFO reinforced fund has $22B capacity plus $1B self-insurance.

CEO emphasized prudency provisions as the most important element of AB 1054 that endures. Acknowledged risk-sharing is the direction but final evaluation depends on full package details.

CEO declined to share specifics, noting legislators are newer and still learning. Focus is on educating policymakers about implications for customer costs via credit ratings and cost of debt.

CEO confirmed CPUC has full discretion for partial prudency findings, noting prior SDG&E case showed binary approach was a mistake. Commission has explicitly recognized this discretion.

John reaffirmed the 100bps-above-threshold target and said an incremental $880M refund, if required, would be funded in a balanced manner.

John said the MISO facts differ and its rate impact was only a couple of basis points versus a much larger New England impact, and he is awaiting a court ruling on the stay.

Nolan said storm costs now top priority after Yankee and Aquarion. Currently a Q2-Q3 2026 event for PURA decision. Hoping new PURA can accelerate. Interest cost savings an additional motivation for speedy resolution.

Nolan reported 52 of 65 turbines installed per Orsted. Onshore substation work nearly finished with back-feed power expected very soon. Schedule brought in by 4-5 months versus original. Orsted targeting H2 2026 but management hopes for improvement.

Moreira disclosed PSNH distribution rate base at approximately $2.1B state-regulated, with FERC-regulated transmission at approximately $1.7-1.8B. FERC tariff based on actual equity ratio for all of New England.

GSEP cap lowered from 3% to 2.5% for NSTAR Gas and EGMA. Nolan said it is manageable and regulators still support investment, suggesting non-pipe alternatives.

Nolan confirmed securitization, public benefit and storm cost recovery are addressed in SB 15/16. PURA prudence review of storm costs underway and going well.

CFO noted statute of limitations passed for property claims, $60M delta between accrual and finalized settlements, and continued quarterly updates.

CFO declined to provide specific timing but noted forward ATM contracts push settlement out a couple of years, providing flexibility.

6-8% designed for sustainability beyond current 5-year plan, balancing affordability. 'Plus' represents current elevated growth period.

CFO confirmed $10B+ pipeline is on top of current 9% EPS growth forecast.

Management confirmed plaintiff theory used term 'unidentified flying object'; noted Xcel had no down power lines.

Comanche unit retirement on track for year-end; Colorado Power Pathway provides reliability replacement for retiring unit.

Speed to market remains top priority for data centers; oil and gas customers also showing strong growth with electrification needs.

Cregg confirmed uprate capital is included in plan. For license extension, NRC feedback expected within five years but construction work likely extends beyond.

Cregg clarified the pause applies to regulations changed by the prior administration in months before the election, a 90-day freeze from inauguration (~January 12). No material impact on PSEG's labor, benefits, or rate riders.

LaRossa confirmed both candidates understand the distinction between supply and delivery costs. Emphasized the need for an integrated resource plan to address the root cause.

LaRossa affirmed both segments can win simultaneously, pointing to financing benefits, state influence, and union alignment as advantages of the combined structure.

LaRossa confirmed FRR is among multiple paths NJ could pursue, noting the state currently relies on BGS from the deregulation era and PJM market.

LaRossa confirmed NJ is a net power importer at peak, with PJM having only about 2% margin above target. As load grows, the resource adequacy question intensifies.

Karen tied the outlook to closing the SI transaction, deconsolidating $9 billion of debt, and SI project milestones, expecting changes early next year; direct.

Jeff confirmed no bridge financing needed for the base plan, with the $2.2B available in the 2032-2033 timeframe, and noted potential for capital recycling at SI to accelerate returns.

Jeff clarified the difference is simply Sempra's 80.25% proportionate ownership of Oncor's $10 billion opportunity, which equals approximately $8 billion at the Sempra level.

Jeff confirmed the target of 90%+ regulated earnings mix with correspondingly lower SI ownership, to be achieved within the five-year plan.

Jeff acknowledged the lack of transparency and said they're open to providing more visibility, potentially including longer-term EPS guidance.

Jeff highlighted multiple upside opportunities not in the plan: FERC ROE improvement, cost of capital mechanism, CenterPoint's equity layer precedent, and Oncor rate case.

Campbell said both states are attractive with similar LLPS tariffs; customer choice comes down to land prospects and local community fit rather than a state preference.

Campbell described the 250 bps spread as a steady rule of thumb, offset over time by steadily increasing load growth even as investment and financing lag earnings.

Buckler confirmed 14% FFO-to-debt for 2025 despite headwinds, with robust equity issuance plan and dividend moderation supporting balance sheet.

Campbell confirmed only actively building customers (not the third) are in the 4-6% EPS growth target.

Campbell said the spread should be within peer company range and will be addressed in the year-end update.

Poroch said the company sees qualitative and quantitative factors improving and will continue proactive, disciplined equity execution. The 16% downgrade threshold provides the floor they're working above.

Poroch said they expect to share clarity in February as contracts come to fruition in the latter part of the planning horizon, but didn't commit to specific 2027 guidance.

Tucker explained their conservative nature: growth is accelerating in back half of decade, but as a large company they need momentum to be sustained before changing the long-term outlook.

Tucker confirmed the 5-7% growth rate is based off 2024 guidance midpoint, not actual results, to exclude one-time items from the baseline.

Tucker indicated possible July update on incremental capital, with fourth quarter remaining the official refresh. The magnitude and pace of opportunities could accelerate disclosure.

Harry said data centers will reduce costs for existing customers over time through fixed cost spreading. Constructive discussions with regulators on tariff structures and ESA provisions.

Harry acknowledged affordability is on everyone's mind alongside housing, healthcare, and food costs. Duke's tools include $500M+ nuclear PTCs, one-utility merger, and rates below national average.

Harry said Florida was chosen as a premium asset that attracted significant interest and delivered premium valuation.

Brian affirmed 100bps Moody's cushion is sufficient given Duke's scale and diversity. Operating cash flow accelerating, with load growth step-up in 2027-2029 driving top-half earnings opportunity.

CEO confirmed 4.5 GW incremental to Slide 14 projects. Some additional units between Slide 14 and the 4.5 GW addition within overall 19.5 GW.

CEO acknowledged real skilled craft labor challenges and increasing costs for combined cycle projects. Working through issues with EPCs but projects not immune to cost pressures.

CEO candid that no single risk-sharing approach has emerged as frontrunner. Still exploring state, federal, customer, vendor, and sovereign fund options.

CFO confirmed credit metrics would still exceed agency thresholds even without transferability. Safe harboring and tax equity partnerships provide additional mitigation.

Ted confirmed special rate agreement filings this year will show initial conversion. IRP will also reveal organic growth beyond just the 20 GW queue over 10-15 years.

Ted said general acceptance of cost reality. No excess grid capacity means all new construction pricing. Demand interest unchanged despite meaningfully higher prices than years ago. Both tariff and subscription must cover full cost of service.

Ted confirmed goal is both: longer visibility (matching peers at 5-year mark) AND more linear trajectory. Will develop new disclosures once rate case concludes and formula rate structure is understood.

Andrew confirmed high 14% FFO-to-debt at year-end. Aspiration is 100bp cushion above 14% Moody's threshold. Regulatory lag pressures metric in 2026 but formula rate should improve numerator over time.

Andres explained powered-land product is providing both the data center site development and energy, versus a standard PPA which is just energy over a contract period. AES owns the land and builds with an attached PPA.

Steve confirmed 3-year guidance horizon extending to 2028 at the February call, maintaining consistent framework rather than extending to 5 years.

Ricardo called the bill net positive: ESP replaced by 3-year forward-looking rate case with annual true-up eliminating regulatory lag. OVEC impact estimated at $0-10M depending on capacity prices. Distribution rate case filing expected by year-end.

Maddipati said DIG throws off significant cash flow with minimal incremental capex, offsets parent financing, and is a core capacity and energy asset CMS knows well, so a sale would require significant value.

Rejji confirmed data center conversion would put upward pressure on both CapEx ($2B-$5B per GW) and equity needs. Growth drives additional rate base expansion requiring incremental financing across equity, debt, and other instruments.

Rejji said electric decoupling is not on the table, noting it is actually not permitted under Michigan legislation. Gas decoupling is embedded in the pending gas rate case filed in mid-December.

Jeanne confirmed 40% equity financing rule for incremental capital.

Jeanne confirmed Q4 refresh timing based on cluster study results, ComEd grid plan filing in 2026, and BGE next filing. Transmission historically up 30% in plan updates.

Calvin described quantum computing campus as additional upside not yet built into projections, with requests already coming from others wanting to be near the campus.

Growth welcome but adds complexity from timing of in-service, load ramp, and turbine procurement. Key focus on execution.

Confirmed combination of gas and renewables. Expected purchaser announcement in coming months, details for fall CapEx update.

Attributed residential growth to weather normalization from record warm Q1 2024. Good customer growth but no fundamental read-through.

Moehn repeated the 13% S&P downgrade threshold, confirmed AEE is tracking well above at 17%+, closer to upgrade.

Moehn confirmed critical components are secured and procurement steps already taken despite industry-wide supply chain pressures.

Fehrman noted T&D RTOs responsible for generation adequacy. PJM has reliability backstop auction, ERCOT has SB6. For VIUs, AEP has secured over 10GW of gas-fired generation. Focused on proper cost allocation to protect residential customers.

Fehrman confirmed AEP is participating in the ERCOT batch study and views it as positive. Does not see significant hindrance to their interconnection plans.

David Bowler declined to disclose the California rate increase amount. The cost of capital proceeding was deferred to filing in 2026 for January 2027 effective date.

David Bowler confirmed equity timing is driven by balance sheet needs, not CapEx timing specifically.

Barton quantified mature opportunity threshold at 85% probability of closing. Acknowledged double-counting risk across utility sector.

Durian explained stronger FFO-to-debt allows lower equity; weaker metrics push to higher end to maintain credit ratings.

Brian said pursuing gas on all fronts: new build, market acquisitions, and greenfield. Value must make sense with near-term contracting opportunity. Don't want to go spec long merchant generation. Turning over every rock.