Andrew Weisel

Andrew Weisel questioned whether the identified nuclear uprate opportunities (433 MW with Meta, 200 MW with Comanche) essentially cover the full potential for existing plant uprates. He also asked about the impact of ERCOT's batching process on Permian Power One and Two, TEF funding, and data center contracts, and sought clarification on the flexibility and mechanics of Vistra's 10b5-1 share repurchase program.

Answer

Kris Moldovan, Executive Vice President and Chief Financial Officer, Vistra, confirmed that the 433 MW with Meta and the potential 200 MW at Comanche Peak largely cover the existing plant uprate opportunities. He stated that Permian Power One and Two are high-return projects, unaffected by the ERCOT batching process (which is a load interconnection process), and Vistra remains in the TEF process, believing it doesn't prohibit locking in revenue. Regarding share repurchases, Mr. Moldovan explained that the 10b5-1 program is structured to accelerate repurchases during market price pressure, as demonstrated in January and February, and is optimized during open windows.

Andrew Weisel from Scotiabank asked if the identified nuclear uprate potential of approximately 600 MW (400+ with Meta, 200 with Comanche) covers the full opportunity. He also inquired about the impact of the ERCOT batching process on Permian Power One and Two, TEF funding, and data center contracts, and sought clarification on the flexibility, pace, and timing of Vistra's 10b5-1 share repurchase program.

Answer

Kris Moldovan, EVP and CFO, Vistra, confirmed that the 600 MW covers the uprate potential for existing plants, with new nuclear being a separate opportunity. Stacey Doré, Chief Strategy and Sustainability Officer and Executive Vice President of Public Affairs, Vistra, clarified that the ERCOT batching process, a load interconnection process, does not affect the Permian TEF units, which are high-return projects with ongoing TEF process participation and potential for revenue locking. Moldovan explained that the 10b5-1 program is structured to accelerate repurchases during market dislocation, as seen in January and February, and is continuously optimized.

Andrew Weisel asked about the impact of ERCOT's batching proposal on the pace of signing data center contracts, and whether the targeted 1 GW announcement for 2026 is included in the current guidance or represents upside.

Answer

President Robert Gaudette stated that ERCOT's batching work is a positive step that will accelerate the interconnection process for large loads, making it more efficient than previous serial processes. CEO Larry Coben clarified that the target of "at least or a minimum of one gigawatt" for 2026 is not included in the current guidance or the long-term outlook, representing potential upside.

Andrew Weisel asked about the potential impact of ERCOT's batching proposal on the pace of signing contracts for new generation, specifically whether it would slow down or accelerate the process. He also sought clarification on whether the target of announcing 1 GW of new contracts in 2026 is already included in the current financial guidance or represents potential upside.

Answer

President Robert Gaudette stated that ERCOT's batching work is beneficial for the market, representing a thoughtful approach that will accelerate the interconnection process for large loads compared to previous serial processes. CEO Larry Coben clarified that the target of at least 1 GW of new contract announcements for 2026 is not included in the current guidance or the roll-forward outlook, indicating it represents potential upside.

Andrew Weisel from Scotia Bank asked about the planned moderation of share buybacks to $1 billion next year, whether this is a temporary or long-term run rate, and how it relates to the LS Power acquisition and TEF CapEx. He also inquired about the timing and format of updated financial guidance post-LS Power close and the potential value or strategic thinking regarding the Gladstone asset in Australia.

Answer

Bruce Chung, EVP and CFO, clarified that the $1 billion annual buyback target is consistent with prior guidance until deleveraging is complete, with updates expected post-LS Power close. He stated that the timing of updated financial communication would depend on the LS Power closing date relative to the Q4 earnings report. Brad Bentley, EVP, commented that any value from the Gladstone asset sale would be nominal, primarily serving to simplify NRG's portfolio and streamline operations.

Andrew Weisel asked about the moderation of share buybacks to $1 billion in 2026, the timing of the LS Power financial update, and the potential value of the Gladstone asset sale in Australia.

Answer

Bruce Chung, CFO, confirmed the $1 billion buyback is consistent with prior commitments until deleveraging is complete. He stated the timing of the LS Power financial update (8K/press release vs. 4Q earnings) will depend on the closing date. Regarding Gladstone, he noted any value would be nominal, primarily serving to simplify the portfolio.

Andrew Weisel sought clarification on whether turbine reservations for gas and safe harbor credits for renewables/storage cover only the 3 GW of contracted projects or also the 2-4 GW of upside opportunities. He also asked about the reasons behind the modest shifts in CapEx timing between 2026, 2027, 2028, and 2029, and requested clarification on changes to the 50% projected demand increase statistic, specifically regarding base year and target year adjustments.

Answer

Lisa Barton, President and CEO, confirmed that the turbine reservations and safe harbor credits cover the 3 GW of contracted projects, and Alliant Energy is actively working on generation for the 2-4 GW in negotiations. Robert Durian, Executive Vice President and CFO, described the CapEx timing shifts as modest refinements due to ongoing contract completion. Regarding the demand statistic, Mr. Durian stated that changes in base and target years are mostly refinements and rounding issues, with a slight delay (less than a year) in the ramp due to the QTS relocation, not a significant change in the overall demand outlook.

Andrew Weisel asked for clarification on whether the turbine reservations for gas and safe harbor credits for renewables/storage cover only the 3 GW of projects with ESAs or also some of the 2-4 GW of upside opportunities. He also inquired about the reasons behind the modest timing changes in CapEx, with some spending moving up from 2027 to 2026 and some pushed back from 2028 to 2029. Lastly, he sought clarification on the updated messaging regarding future demand, specifically the 50% increase, noting a change in the base year (2025 vs 2024) and target year (2031 vs 2030), asking if this implies a slightly later and smaller demand increase.

Answer

Lisa Barton (CEO, Alliant Energy) confirmed that the turbine reservations and safe harbor credits refer to the 3 GW of projects with ESAs, and that generation for the 2-4 GW in active negotiations is also being worked on, referencing a recent RFP. Robert Durian (EVP and CFO, Alliant Energy) stated that the CapEx timing changes are modest refinements, with no single year moving more than about $100 million, and not indicative of anything more significant. Regarding the demand messaging, he explained that most numbers are refinements and rounding issues, with a slight delay of less than a year in the QTS ramp due to relocation, but no significant change in the overall message of future demand.

Andrew Weisel of Scotiabank inquired why the data center demand chart was unchanged despite the $10 billion QTS investment announcement. He also asked about the potential need for new generation, such as CCGTs, to support this load and questioned the company's strategy for its wind projects if it is unable to secure safe harbor tax credits.

Answer

President and CEO Lisa Barton explained that the $10 billion QTS project in Cedar Rapids was already included in the plan, while the QTS Madison project resides in the 'mature opportunities' category and will drive future CapEx updates. Executive VP and CFO Robert Durian confirmed that new load growth will primarily require new generation, with an update coming in Q3. Regarding safe harbor, Durian stated they would pivot to other technologies if needed, and Barton emphasized that affordability analysis is integral to their resource planning.

Andrew Weisel from Scotiabank sought more details on the $1.4 billion equity plan, asking about the potential use of an ATM versus a block trade and the timing of issuance. He also asked for a breakdown of the $600 million increase in the CapEx plan by asset type and technology.

Answer

Executive Robert Durian detailed that the $1.4 billion equity need would be met by ~$100 million from the direct plan and $1.3 billion from flexible instruments like an ATM or a forward transaction. The current plan assumes ratable issuance from 2026-2028, but timing is flexible. He specified that the largest driver of the CapEx increase was for new natural gas generation to support peak demand from data center customers.

Andrew Weisel sought to clarify if the Big Cedar site was fully booked, asked about confidence in serving future data center demand, and questioned how proposed Iowa legislation on Integrated Resource Planning (IRP) and advanced ratemaking would impact the company's flexibility.

Answer

President and CEO Lisa Barton initially confirmed Big Cedar was fully booked but later corrected herself, stating there is still 'a little bit of room.' She affirmed the company is positioning itself to attract significant economic development. Barton viewed the IRP legislation as neutral to flexibility, as they can file plans anytime. EVP and CFO Robert Durian added that the advanced ratemaking legislation expands eligibility to more technologies and lowers the threshold to 40 MW, providing greater flexibility to meet new customer demand.

Andrew Weisel of Scotiabank questioned the reasons for the 2024 guidance reduction, asking if it was solely due to weather. He also inquired if the updated CapEx plan includes assumptions for other economic development deals beyond the announced Phase I and pressed for reasons why the EPS growth outlook isn't higher than 6% given the significant load and CapEx increases.

Answer

CFO Robert Durian confirmed the 2024 guidance change was largely due to being able to offset about 75% of significant negative temperature impacts, not a full offset. He clarified that any economic development beyond the announced Phase I data centers represents upside to the current plan. Both Robert Durian and CEO Lisa Barton attributed the 6% growth outlook to a conservative approach based on timing and a commitment to not get ahead of the story until new deals are fully secured.

Andrew Weisel inquired about the potential to accelerate dividend growth, which he noted as new commentary, asking for more details on the rationale, what the company would be looking for, and the expected timing of such a change.

Answer

CFO David P. Poroch stated that the dividend is an integral part of their value proposition. He mentioned that, in conjunction with the board, they would aim to grow earnings into the dividend rate and revisit the pace of dividend growth around a 60% payout ratio window, though this is 'out on the horizon.'

Andrew Weisel asked for elaboration on the potential to accelerate dividend growth, noting it as new commentary, and sought details on the rationale, what the company would be looking for, and the timing of such a change.

Answer

David P. Poroch, CFO, stated that the dividend is integral to the value proposition and, in conjunction with the board, the company would look to grow earnings into the dividend rate. He mentioned revisiting the dividend payout ratio around the 60% window in the future, emphasizing its importance to the long-term value proposition.

Andrew Weisel from Scotiabank questioned the company's confidence in counterparties' ability to deliver combined cycle PPA capacity by 2028, given industry constraints. He also asked about the durability of the new demand forecast, considering the need for an interim IRP update in 2023.

Answer

CFO Dan Tucker clarified that the near-term combined cycle PPAs are for existing capacity that is becoming available in the market, not new builds, mitigating execution risk. David Poroch, SVP & incoming CFO, explained that the Georgia PSC regulatory structure is orderly and flexible, allowing for future IRP updates if warranted by changing circumstances, ensuring they can adapt to sustained load growth.

Andrew Weisel questioned the sequential slowdown in electricity demand trends, particularly the deceleration in data center growth from 17% to 11% year-over-year. He also sought clarification on the size and growth of the total large load pipeline.

Answer

Chief Financial Officer Dan Tucker explained that there was nothing systemic to read into the quarterly numbers, citing base effects for data center growth (growing off a higher base) and timing-related industrial outages. He clarified that the 52 GW pipeline figure is for Georgia alone, and the total consolidated pipeline across all territories is 'over 50 GW' and did grow quarter-over-quarter. He cautioned against focusing too much on the headline number due to its speculative nature.

Andrew Weisel inquired about the modest decrease in total electric throughput in Q4 2025, despite positive residential and C&I trends, asking if there was any noise in the data. He also asked for clarification on the drivers behind the approximately $300 million reduction in gas spending within the updated CapEx plan.

Answer

Christopher Foster, EVP and CFO, attributed the electric volumes to a weighting towards commercial and industrial growth, with 7% industrial growth across 2025, and expressed confidence in long-term growth driven by new jobs from large investments like Eli Lilly and data center ecosystems. Jason P. Wells, Chair, President, and CEO, explained that the gas spending reduction was due to pulling forward some integrity management work into 2025, allowing for flexibility in outer years, and is not indicative of a long-term trend.

Andrew Weisel inquired about the Q4 electric volumes, noting a modest decrease in total throughput despite residential growth and positive C&I trends, and sought clarification on the CapEx update, specifically the increase for the 765 kV line and the reduction in gas spending.

Answer

Christopher Foster, EVP and CFO, explained that Q4 volumes reflect a weighting towards commercial and industrial growth, with strong industrial growth seen across 2025, and expressed confidence in long-term trends. Jason P. Wells, Chair, President, and CEO, clarified that the CapEx increase was primarily for the 765 kV line, while the gas spending reduction was due to flexibility gained from pulling forward integrity management work into 2025, not a long-term trend.

Andrew Weisel from Scotiabank requested more details on the Houston Downtown project's timing and magnitude, asked for sizing on how much additional CapEx could be added this year without equity, and sought specifics on the use of the $500 million CapEx increase.

Answer

CEO Jason Wells explained the Houston Downtown project is gaining clarity, with work beginning now and the bulk of spending occurring over the next five to six years. He declined to quantify the limit for equity-free CapEx increases but suggested it was more than the $500 million just announced. EVP & CFO Christopher Foster specified the $500 million increase is dominated by electric transmission work, with some system resiliency and Texas Gas investments.

Andrew Weisel from Scotiabank asked for the reason behind the increased confidence in the Houston Downtown project, the potential size of future CapEx increases that could be funded without equity, and the specific use of the $500 million CapEx increase announced today.

Answer

CEO Jason Wells explained that the Houston project is gaining clarity due to city commitments, with CenterPoint's work being front-loaded over the next 5-6 years. He noted future CapEx increases without equity could be an order of magnitude larger than the current $500 million. CFO Chris Foster specified the $500 million increase is primarily for electric transmission work, system resiliency, and some Texas Gas investments.

Andrew Weisel from Scotiabank asked for a customer breakdown of the new 7 GW in the interconnection queue and for commentary on FFO to debt progress and discussions with rating agencies about removing the negative watch.

Answer

CEO Jason Wells detailed the 7 GW increase as nearly 6 GW from data centers and 1 GW from manufacturing and industrial demand. CFO Christopher Foster stated they are making good progress on the FFO to debt metric and that rating agencies are focused on the Hurricane Beryl cost recovery process, with progress on that filing being key to moving off the negative outlook.

Andrew Weisel asked about the states experiencing the most data center activity and whether the latest additions would fall within the five-year plan or ramp up in the early 2030s. He also inquired about FirstEnergy's priorities for Ohio regulations and execution in 2026 and beyond, and if the state's regulatory environment would be quieter after 2025's busy year.

Answer

Brian Tierney (CEO and President) identified Maryland (Frederick area) as having the most current data center activity, followed by Pennsylvania and Ohio. He noted significant activity between now and 2030/2031, with a substantial amount of load by 2035. For Ohio, he stated that 2025 resolved legacy issues, allowing a focus on 'business as usual.' Priorities include filing a three-year rate case soon to align with new legislation, anticipating continued support for wires investment, and constructive dialogue with the commission and interveners.

Andrew Weisel inquired about data center activity, asking where FirstEnergy is seeing the most activity (which state) and whether the latest additions would fall within the current five-year plan or ramp up in the early 2030s. He also asked about FirstEnergy's priorities for 2026 and the next few years in Ohio, both on the regulatory and execution sides, and if the state's regulatory environment is expected to be quieter after a busy 2025.

Answer

Brian Tierney, CEO and President, indicated significant data center activity in Maryland, particularly around Frederick, followed by Pennsylvania and Ohio. He noted that activity is expected between now and 2030-2031, with a substantial amount of load by 2035. For Ohio, Mr. Tierney stated that legacy issues are now behind the company, and it's 'business as usual' going forward. He confirmed plans to file a three-year rate case soon, anticipating constructive dialogue and continued support for wires investment and improved reliability from the commission and interveners.

Andrew Weisel asked about FirstEnergy's CapEx update, specifically whether the company anticipates reallocating spending from other segments or if its balance sheet and labor force can accommodate a potentially sizable overall increase without limiting factors. He also inquired about broader trends and the outlook for industrial customers outside of the specific data center ramping mentioned.

Answer

Brian Tierney, Chair, President, and CEO, stated that FirstEnergy does not foresee reallocating spending from one jurisdiction to another, expecting increases across all areas, with plans tailored to specific jurisdictional needs. Jon Taylor, Senior Vice President and Chief Financial Officer, noted a slight rebound in fabricated metals and steel manufacturing. He reiterated expectations for meaningful industrial load increases, primarily from data centers, starting in Q4 2025 and accelerating into 2026, potentially reaching mid-single digits by Q2 and significantly higher by Q4 next year.

Andrew Weisel asked if FirstEnergy anticipates reallocating spending from other segments or businesses to accommodate the very meaningful upside in transmission CapEx and West Virginia generation, or if the balance sheet and labor force can handle a sizable overall increase. He also inquired about broader industrial load trends and outlook outside of specific data center ramping.

Answer

Brian Tierney, Chair, President, and CEO, stated that FirstEnergy does not foresee reallocating funds from one jurisdiction to another, but rather expects increases across all jurisdictions, as plans are tailored to specific needs and opportunities. Jon Taylor, Senior Vice President and Chief Financial Officer, noted a rebound in fabricated metals and steel manufacturing. He anticipates meaningful increases in industrial load, primarily from data centers, reaching mid-single digits by Q2 and potentially higher by Q4 of next year.

Andrew Weisel asked for the current level of data center demand, details on the significant ramp-up shown for 2026, and the expected timing for the next comprehensive CapEx plan update.

Answer

SVP & CFO K. Jon Taylor reported that active data center load is currently around 400 megawatts, with significant growth interest in Ohio, Maryland, West Virginia, and now Pennsylvania. He stated that the next long-term CapEx plan update will likely be provided with the fourth-quarter earnings call to incorporate results from the current PJM open window.

Andrew Weisel questioned the timing interplay between the Ohio settlement talks and the pending legislation, asked about industrial sales trends, and sought clarification on whether the new PJM transmission investments were incremental to the plan.

Answer

Brian Tierney, Chair, President and CEO, stated that the Ohio legislation and the base rate case are on parallel but independent timelines. Jon Taylor, SVP and CFO, attributed the recent industrial sales decline primarily to the steel sector. Brian Tierney clarified that the Valley Link investment is not in the CapEx plan as it's handled via the equity method, but the other $300 million in PJM projects are included in the plan.

Andrew Weisel asked for details on weak weather-adjusted sales trends, particularly in the commercial segment. He also questioned the dividend outlook, noting the payout ratio on rebased core earnings is slightly above the target range.

Answer

Executive K. Taylor attributed residential sales weakness in Pennsylvania to energy efficiency programs and noted some industrial softness was due to temporary steel customer outages, clarifying that data centers are in the industrial class. Executive Brian Tierney stated that while the dividend payout is slightly high, the board is comfortable with the level for 2024 and 2025 and expects dividend growth to generally track core earnings growth.

Andrew Weisel asked for the specific drivers of the 2024 CapEx increase and whether it represented a pull-forward from future years. He also inquired about the expected timing for clarity on the PJM transmission project awards.

Answer

Executive Jon Taylor attributed the CapEx increase to storm restoration costs, reliability work in Pennsylvania, and incremental transmission opportunities, noting the overall $26 billion five-year plan remains intact. He stated the company will have a 'good sense' of the PJM project outcomes by the Q4 call, ahead of the final PJM board approval expected in February.

Andrew Weisel of Scotiabank sought clarification on the retail sales growth forecast on page 5, noting an increase in CAGRs but a decrease in bar chart numbers, asking if this was due to rolling forward the starting point. He also asked about the Meta contracts, specifically addressing perceived pushback or confusion around contract terms, reconciling Meta's 4-year subcontracts with Blue Owl versus Entergy's 15-year structure, and identifying the ultimate guarantor.

Answer

Kimberly Fontan, EVP and CFO, confirmed that the change in bar chart numbers was relative to the roll forward of the year and that the step-up from 2027 to 2029 reflects large customers continuing to ramp and adjustments to probability weightings. Regarding Meta contracts, Fontan clarified that Entergy has a 15-year electric service agreement (ESA) with a Meta subsidiary, backstopped by Meta's parent company, which includes termination fees and minimum bills. She explained that Meta's transaction with Blue Owl for structuring their capital is separate and distinct from Entergy's ESA. Fontan explicitly stated that the ultimate guarantor on Entergy's ESA is Meta's parent company.

Andrew Weisel requested clarification on the retail sales growth forecast on page 5, specifically if the change in CAGRs and bar chart numbers was due to rolling forward the starting point from 2024 to 2025, and if the 2028-2029 forecast increased by 2 TWh. He also asked for an explanation of the Meta contracts, addressing perceived confusion around 4-year subcontracts versus a 15-year structure, and identifying the ultimate guarantor.

Answer

Kimberly Fontan, EVP and CFO, confirmed the roll-forward of the year and noted the step-up in sales from 2027 to 2029 as large customers ramp up, offering to provide specific terawatt numbers. She clarified that Entergy has a 15-year electric service agreement (ESA) with a Meta subsidiary, backstopped by Meta's parent company, which includes termination fees and minimum bills. The 4-year terms Andrew referenced pertain to Meta's separate capital structuring transaction with Blue Owl, distinct from Entergy's ESA. Ms. Fontan confirmed Meta's parent is the ultimate guarantor on Entergy's ESA.

Andrew Weisel inquired about the potential for large data centers to build their own onsite power generation, asking about Entergy's discussions with them regarding self-generating versus purchasing power from utilities. He also requested a preview of the upcoming Arkansas rate case filing, specifically concerning customer bill impacts and Google's role.

Answer

Drew Marsh, Chair and CEO, explained that Entergy often builds generation very close to customer sites to manage transmission costs, providing similar benefits to onsite generation from a grid perspective. He noted that data center customers typically prefer to invest their capital elsewhere, making Entergy's utility-provided generation a competitive and preferred option. Regarding the Arkansas rate case, Drew Marsh, Chair and CEO, stated that the team is still working on the filing and could not provide an update, but he expects the benefits from large new customers like Google to positively impact existing customers' rates, which will be detailed in the case.

Andrew Weisel sought clarification on the reduced load growth forecast, asking if it was due to the pace of new customers or usage from existing ones, and requested the new industrial growth forecast. He also asked how much of the proposed investment pipeline is already in the CapEx plan.

Answer

CFO Kimberly Fontan confirmed the adjustment was due to the timing and ramp-up of new customers, not usage from existing ones, and stated the industrial growth forecast remains close to the original 11-12% range. She also clarified that the significant investments listed on slide 15 are all included in the current $37 billion financial plan through 2028.

Andrew Weisel asked for clarification on the cash component of the Illinois GAAP charge. He also sought to understand the interplay between the VLC tariff and the general rate case, including the expected rate impact for general customers and whether the VLC ruling needs to conclude before the GRC filing. Additionally, he questioned the long-term impact of data center activity exceeding expectations on other customer rates.

Answer

CEO Scott Lauber clarified that the Illinois GAAP charge includes a $130 million prospective rate-based reduction and $125 million in cash credits to customers over three years. For the VLC tariff and GRC, Mr. Lauber stated that the GRC filing in April will separate costs for very large customers, ensuring transparency, and the two processes will run independently. He explained that increased data center rate base will spread corporate allocations across a larger footprint, incrementally benefiting other customers long-term, especially as assets come online in 2028-2030.

Andrew Weisel from Scotiabank inquired about the cash component of the Illinois GAAP charge and sought clarification on the interplay between the Very Large Customer (VLC) tariff and the general rate case, including expected rate impact for general customers, long-term effects of data centers on rates, and the timing of the VLC ruling relative to the GRC filing.

Answer

Scott Lauber, CEO of WEC Energy Group, clarified that the Illinois GAAP charge includes a $130 million rate-based component and $125 million in cash credits over three years. He explained that the VLC tariff and GRC will be transparently separated, with data centers' significant rate base expected to spread corporate allocations and incrementally benefit general customers long-term. Mr. Lauber confirmed the VLC ruling and GRC filing are on independent tracks, likely occurring around the same time.

Andrew Weisel asked about the progress on safe-harboring renewable projects for tax credits, the company's backup plan if they don't qualify, and the rationale behind extending the life of the Oak Creek coal units, including whether it was driven by political pressure.

Answer

President and CEO Scott Lauber reported that 40-50% of renewable projects are already safe-harbored, with work continuing on the rest pending new Treasury guidance. He emphasized that the energy is needed regardless, so alternatives like combined-cycle plants would be considered. Lauber clarified the decision to extend the Oak Creek units was a business decision based on MISO market prices and regional reliability needs, with no political involvement.

Andrew Weisel from Scotiabank asked for an update on the Illinois pipeline safety program's potential CapEx upside and timeline, the progress and confidence level in the Microsoft data center project, and the timing of the company's equity issuances for the year.

Answer

Executive Scott Lauber stated the Illinois pipe replacement program will ramp up in 2026-2027, targeting an annual run rate over $500 million by 2028. He also affirmed strong confidence in Microsoft's 1.8 GW demand forecast. CFO Xia Liu added that the timing of the $700-$800 million in 2025 equity issuances is actively managed based on stock price and cash needs, expressing confidence in meeting the target.

Andrew Weisel requested a breakdown of the CapEx increases for electric generation and natural gas distribution, and asked if the transmission spending increase was related to MISO Tranche 2 projects.

Answer

Executive Scott Lauber clarified that the gas distribution increase reflects growth in Wisconsin, Michigan, and Minnesota, offset by a decrease in Illinois. The electric generation increase includes about $700 million for various projects like wind farm upgrades and plant resilience. He confirmed the transmission increase is for near-term economic development, with MISO Tranche 2 spending expected mostly after the current 5-year plan.

Andrew Weisel from Scotiabank asked about the timeline for potentially reallocating capital back to Illinois, the drivers for the improved O&M outlook, and the full-year expectation for the tax impact in the Corporate and Other segment.

Answer

President and CEO Scott Lauber indicated the company will remain conservative on Illinois capital until there is more clarity from pending dockets, likely in early 2025. CFO Liu Xia explained the improved O&M forecast is due to a company-wide focus on cost control, a combination of one-time and sustainable efficiencies. She also noted the full-year tax impact in the Corporate segment should be slightly positive, with timing shifts driven by Illinois earnings patterns and the Delilah project delay.

Andrew Weisel asked for clarification on the Crusoe Tallgrass project, specifically if the proposed transmission infrastructure and customer-funded construction ensure the entire project is grid-connected and qualifies for the LPCS tariff, how utility fees apply to generation investments like fuel cells, and if more transmission/distribution filings are expected for data center growth. He also questioned the timeline for signing an energy service agreement to meet the Q1 2027 in-service target.

Answer

Marne Jones, Senior Vice President and Chief Utility Officer, explained that microgrid management fees are applied to peak demand, with different pricing structures for market energy, contracted/co-located generation, and utility-owned builds, which would seek risk-adjusted utility returns. Linn Evans, President and CEO, confirmed that much of the energy is currently tied to their system. Ms. Jones indicated that the 500-600 MW demand will necessitate additional investment beyond the current plan, suggesting more filings like the Robinson Substation. She also noted the customer's intention to begin taking service in Q1 2027, with Black Hills Corporation working to align with that goal.

Andrew Weisel asked about the Crusoe Tallgrass project's transmission infrastructure, including the Robinson substation, and how customer-funded construction would impact LPCS tariff applicability. He also questioned whether fuel cell investments by Tallgrass would qualify for utility fees under the LPCS tariff, if other transmission and distribution assets are being fast-tracked for data centers, and the necessary timeline for signing an energy service agreement for the Crusoe project to meet its Q1 2027 in-service target.

Answer

Senior Vice President and Chief Utility Officer Marne Jones explained that the microgrid management fee is applied to peak demand and varies based on the resource mix (market, contracted, or utility-owned generation), with President and CEO Linn Evans confirming that current networks are tied to their system. Marne Jones further elaborated that the resource mix for Tallgrass is still under evaluation, with different pricing structures for market energy, contracted generation, and utility-owned builds, which would seek risk-adjusted utility returns. She also indicated that additional investments beyond the current plan are likely for the 500-600 MW demand. Regarding the Crusoe project, Marne Jones stated that the customer intends to begin service in Q1 2027, and the company is working in alignment to meet this goal.

Andrew Weisel from Scotiabank asked for more detail on the specific drivers for achieving the upper half of the 4-6% EPS growth target starting in 2026 and inquired about the nature and forward impact of recent unplanned generation outages.

Answer

CFO & SVP Kimberly Nooney attributed the confidence in achieving the upper half of the growth target to several factors, including full recovery for the Ready Wyoming project, contributions from Lang II and the Colorado Clean Energy Plan, and strong customer growth, noting this outlook does not include uncontracted data center load. Regarding outages, SVP & Chief Utility Officer Marne Jones confirmed all generation is back online, and Kimberly Nooney added that the year-to-date financial impact was immaterial due to offsetting factors and is not expected to impact future results.

Andrew Weisel from Scotiabank asked for more detail on the specific drivers for achieving the upper half of the 4% to 6% EPS growth target starting in 2026. He also requested specifics on the unplanned generation outages, their current status, and any potential future impacts.

Answer

CFO & SVP Kimberly Nooney detailed that the confidence in achieving the upper half of the growth range is driven by the Ready Wyoming project, Lang II, the Colorado Clean Energy Plan, and general customer growth, noting this outlook does not yet include further data center expansion. Regarding outages, SVP & Chief Utility Officer Marne Jones confirmed all generation units are back online and serving customers. Kimberly Nooney added that the financial impact of the outages on year-to-date EPS was immaterial due to offsetting factors.

Andrew Weisel from Scotiabank asked for more detail on the specific drivers behind the company's confidence in achieving the upper half of its 4-6% EPS growth target starting in 2026, and also requested specifics on the unplanned generation outages mentioned during the call.

Answer

CFO & SVP, Kimberly Nooney, detailed that the primary drivers for higher growth include full recovery on the Ready Wyoming project, contributions from the Lang II and Colorado CEP projects, and strong base customer growth, clarifying this outlook does not yet include uncontracted data center expansion. Regarding outages, SVP & Chief Utility Officer, Marne Jones, confirmed all generation is back online, while Kimberly Nooney added that the financial impact on EPS was immaterial due to offsetting factors.

Andrew Weisel asked for clarification on the drivers for achieving the upper half of the 4-6% EPS growth target starting in 2026 and requested details about the unplanned generation outages mentioned during the quarter.

Answer

CFO & SVP, Kimberly Nooney, detailed that the confidence in achieving upper-half growth stems from the Ready Wyoming project's full recovery, the Lang II and Colorado CEP projects, and strong customer growth, noting this outlook does not include potential upside from new data center deals. Regarding outages, SVP & Chief Utility Officer, Marne Jones, confirmed all generation is back online. Kimberly Nooney added that the financial impact was immaterial to EPS year-to-date due to offsetting factors and does not affect future guidance.

Andrew Weisel of Scotiabank inquired about the specifics of the Colorado electric rate case reconsideration, the recent franchise vote in Pueblo, and the timing of the company's equity issuance relative to its annual guidance.

Answer

Marne Jones, SVP and Chief Utility Officer, explained the rate case reconsideration resulted in a minor revenue increase but no change to the capital structure. She also confirmed the Pueblo franchise was renewed until 2030. Kimberly Nooney, SVP and CFO, clarified that equity is issued based on capital needs and reaffirmed the full-year target, noting future equity needs will be lower due to 2025's outsized capital plan and upcoming project cash flows.

Andrew Weisel sought clarification on the company's credit rating commitment, the reason for the 2024 CapEx shortfall, and the slight delay in the Colorado Clean Energy Plan's in-service timeline.

Answer

SVP & CFO Kimberly Nooney reaffirmed the company's commitment to solid investment-grade credit ratings and its key metric targets. SVP, Utilities Marne Jones attributed the CapEx shortfall to minor project timing shifts into 2025 and explained the Clean Energy Plan timeline was updated as contract negotiations provided more precise scheduling information.

Andrew Weisel inquired about the specifics of the unplanned generation outages, including their financial impact, and asked where earnings might land within the reaffirmed guidance range. He also questioned the potential impact of the U.S. election results on the crypto and blockchain industries and Black Hills' unique position to benefit.

Answer

Marne Jones, SVP of Utilities, clarified that the outage was a rollover from the prior quarter due to component failure. Kimberly Nooney, SVP and CFO, directed him to the presentation slides for the specific EPS impact but declined to comment on positioning within the guidance range. Linn Evans, President and CEO, stated that while their strategy is largely agnostic to federal policy, their decade of experience serving data centers positions them well to capitalize on any industry growth.

Andrew Weisel inquired about CMS Energy's equity financing strategy, specifically whether equity needs will be consistent, ramp up with CapEx, or be front-end loaded, and if the plan includes the use of hybrids or junior subordinated notes (JSNs). He also asked if the updated $24 billion CapEx plan represents a pull from the previously discussed $25 billion incremental opportunities bucket or if it's an entirely new, incremental $4 billion with the opportunities bucket remaining similar.

Answer

Rejji Hayes (CFO and Executive Vice President, CMS Energy) explained that equity needs generally increase with CapEx, with the current $24 billion plan requiring approximately $1.5 billion more equity than the prior $20 billion plan, totaling about $3.75 billion to maintain mid-teens credit metrics. He confirmed the plan includes over $1.5 billion in junior subordinated notes, primarily in 2027-2028. Equity needs are somewhat front-end loaded in the first three years. Regarding the CapEx plan, Mr. Hayes stated they have dipped into the $25 billion backlog, but it's not a perfectly symmetric equation as new Integrated Resource Plan (IRP) and data center opportunities will add to the backlog, describing the CapEx backlog as 'infinite.'

Andrew Weisel inquired about CMS Energy's equity needs, specifically whether they will be consistent, ramp up with the CapEx profile, or be front-end loaded. He also asked if the plan assumes additional use of hybrids or Junior Subordinated Notes (JSNs) and if these could potentially reduce equity needs. Additionally, he asked if the new $24 billion CapEx plan represents pulling $4 billion from the previously discussed $25 billion 'opportunities bucket' or if it's incremental, leaving a similar opportunities bucket beyond the new outlook.

Answer

Rejji Hayes, CFO and Executive Vice President, confirmed that equity needs generally increase with CapEx, noting the current $24 billion plan (up $4 billion from the prior $20 billion vintage) requires approximately $1.5 billion more equity, totaling about $3.75 billion. He stated that over $1.5 billion in JSNs are included in the 5-year plan (primarily 2027-2028), given strong market execution. Equity needs are somewhat front-end loaded, with a significant portion anticipated in the first three years. Regarding the CapEx plan, Mr. Hayes confirmed they dipped into the $25 billion backlog for the $4 billion incremental, but it's not a symmetric equation. He noted that additional CapEx needs are arising from the new Integrated Resource Plan, and large data center opportunities are not presupposed in the plan, further adding to the backlog. He described the CapEx backlog as 'quite infinite.'

Andrew Weisel from The Bank of Nova Scotia sought clarification on the inclusion of the $5 billion IRP-related spending in the upcoming February CapEx update, inquired about CMS Energy's current excess capacity to serve connected load (450 MW) and future large loads (2 GW), and asked for details on the Campbell plant's operational status, required maintenance, and the accounting/financial implications of its continued operation under Department of Energy orders.

Answer

President and CEO Garrick Rochow confirmed that a portion of the IRP-related spending would filter into the next five-year plan, particularly towards the tail end. He stated that CMS Energy has capacity to serve the 450 MW connected load and is expanding capacity through renewables and battery storage for future growth. Regarding the Campbell plant, Mr. Rochow praised the workforce and noted continued DOE orders, with costs and offsetting revenues appropriately spread across MISO North and Central regions, supported by FERC. Executive Vice President and CFO Rejji Hayes added that all Campbell-related costs are treated as a regulatory asset, amortized upon recovery, with Michigan customers to be refunded by MISO North and Central customers.

Andrew Weisel sought clarification on the inclusion of Integrated Resource Plan (IRP) related spending in the upcoming February CapEx update, the current excess capacity to serve new load growth, and details on the Campbell plant's continued operation, including maintenance, accounting, and MISO/FERC implications.

Answer

Garrick Rochow, President and CEO, confirmed that a portion of IRP spending would filter into the next five-year plan, particularly in the tail end, due to long lead times. He stated that the 450 MW of connected load is currently served with existing capacity, which is expanding with new renewables and battery storage. Regarding the Campbell plant, he highlighted the flexible workforce and expected continued orders from the Department of Energy. Rejji Hayes, Executive Vice President and CFO, added that all Campbell operating and maintenance expenses, along with minimal capital investments, are treated as a regulatory asset, amortized upon recovery, with Michigan customers to be refunded by MISO North and Central customers.

Andrew Weisel asked if the company is already implementing cost cuts post-storm, what would happen if the deferral is approved mid-cuts, and for a self-assessment of the storm response.

Answer

EVP and CFO Rejji Hayes confirmed cost-cutting is already in 'implementation mode.' He noted an approved deferral would add flexibility, possibly allowing a reversal of one-time cuts while continuing recurring savings efforts. President and CEO Garrick Rochow graded the storm response a 'B+', citing significant improvement and positive feedback from customers and policymakers, while still seeing room to improve.

Andrew Weisel asked about the potential window for a settlement in the current electric rate case. He also inquired about the upcoming CapEx update, asking if the confluence of demand growth, the REP, and reliability initiatives would lead to a larger-than-usual increase and how that would be financed, particularly regarding equity needs.

Answer

President and CEO Garrick Rochow stated that the window for a settlement is open now and extends up to a final order, but key issues might require a fully adjudicated outcome. Regarding CapEx, Rochow noted that the benefits from the REP and IRP will be layered in over time following regulatory approvals. EVP and CFO Rejji Hayes confirmed the $17B plan will see upward pressure but that the pace of approvals and project build-outs will govern the timing. For financing, he reiterated the 'up to $350M' annual equity guidance for the current plan and provided a rule of thumb of $0.35-$0.40 of equity per incremental dollar of CapEx, though this can be mitigated by strong cash flow, tax credit monetization, and opportunistic hybrid debt issuance.

Andrew Weisel asked for commentary on C&I weather-adjusted sales volumes and requested an assessment of the company's storm restoration performance during the quarter.

Answer

CFO Rejji Hayes explained that while Q2 sales saw a slight pullback, year-to-date trends remain strong and are outperforming conservative plans, especially when factoring in energy waste reduction. President and CEO Garrick Rochow graded storm response a 'B,' highlighting improved restoration times. Rejji Hayes added a 'B+' grade for financial efficiency, citing over $40 million in avoided costs via the CE Way.

Andrew Weisel asked for specifics on the 700 MW of natural gas capacity proposed for Maryland, including the origin of the relocated turbines and their availability timeline. He also questioned if recent federal announcements regarding new nuclear (e.g., Trump administration's $80 billion pledge) have altered Constellation's comfort or appetite for new nuclear construction, and what conditions (PPA, government support, customer contracts) would be necessary for the company to proceed.

Answer

President and CEO Joe Dominguez clarified that the natural gas turbines are lightly used assets currently located in buildings in the Midwest and New England, which can be relocated relatively quickly to Maryland. He described them as state-of-the-art in terms of heat rates and refurbished for rapid redeployment. On new nuclear, Mr. Dominguez stated that while he remains cautious, he is gaining confidence. Key requirements for Constellation to move forward include a durable PPA, clear and constructible pricing with reliable partners, monetization of Constellation's unique land value (infrastructure, talent, community acceptance), and an operating services agreement for Constellation to operate any new units on its land. He acknowledged federal involvement as positive but emphasized the need for detailed cost numbers and commitments before significant capital is put at risk.

Andrew Weitzel asked for specifics on Constellation's 700 megawatts of natural gas capacity in Maryland, including the origin and timing of the relocated turbines. He also questioned if federal government announcements have changed Constellation's appetite for new nuclear construction, outlining the conditions required to move forward, such as PPAs, clear pricing, and leveraging existing land assets.

Answer

President and CEO Joe Dominguez clarified that the natural gas turbines are existing, lightly used assets physically located in buildings in the Midwest and New England, which can be refurbished and redeployed relatively quickly to Maryland. Regarding new nuclear, Mr. Dominguez stated that a durable PPA and clear, constructible pricing with good technical partners are paramount. He emphasized the unique value of Constellation's existing nuclear sites, including infrastructure, land, talent, and community acceptance, which he aims to monetize through output and operating services agreements. While commending government leadership and recent announcements, he remains cautious, requiring full details, clear cost numbers, and commitments before significant capital investment.

Andrew Weisel questioned Eversource's land acquisition strategy, specifically regarding the Mystic acquisition, whether it's for standalone development or in partnership with customers, and if it's more about optionality than large dollar investments. He also sought clarification on the equity outlook, including the increase in the 2025 outlook, the removal of a previous comment about issuance timing, and its relation to CapEx or credit metrics.

Answer

Chairman, President, and CEO Joe Nolan explained that land acquisitions are for Eversource's own regulated business in strategic locations for energy injection, not for data centers, and mentioned another strategic site is forthcoming. Executive Vice President, Chief Financial Officer, and Treasurer John Moreira reaffirmed that equity needs are covered for the near term, with the majority of issuance expected towards the latter end of the forecast period, supported by the Aquarion sale cash and storm cost securitization.

Andrew Weisel asked for more details on Eversource's land acquisition strategy, specifically if it's a 'land grab' for standalone development or involves working with customers/partners, and if the financial investment is small, focusing more on optionality. He also inquired about changes to the 2025 equity outlook, noting an increase and the removal of a comment about the majority being issued in the back half of the forecast period, asking if this relates to CapEx or long-term credit metrics.

Answer

CEO Joe Nolan explained that land acquisitions are for Eversource's own regulated business, strategically located for energy injection, and not for data centers. He mentioned the Mystic purchase and upcoming news on another strategic site. CFO John Moreira clarified that the company is done with equity issuance for the near term, and the majority of equity needs will still be towards the tail end of the forecast period, not next year, with the Aquarion sale and storm cost securitization covering needs.

Andrew Weisel of Scotiabank questioned the rationale for activating the ATM equity issuance program in Q2 and asked if Eversource is ready to redeploy capital back to Connecticut following recent legislative and court developments.

Answer

EVP, CFO & Treasurer John Moreira explained the ATM was used in June to provide liquidity, with future use dependent on the Aquarion sale timing and debt balances. On Connecticut, Moreira stated the company wants to see 'more constructive data points from the commission' first, specifically citing the pending Yankee Gas case outcome. CEO Joseph Nolan added that clarity on AMI would also be a factor.

Andrew Weisel questioned the rationale for resuming ATM equity issuances in Q2 and asked whether Eversource is ready to redeploy capital back to Connecticut following recent legislative and court developments.

Answer

John Moreira, Executive VP, CFO & Treasurer, explained the Q2 equity issuance was to provide liquidity and future needs depend on the Aquarion sale timing and debt balances. On Connecticut capital, Mr. Moreira stated the company wants to see more constructive data points from the commission first, specifically citing the pending Yankee Gas rate case outcome as a key factor.

Andrew Weisel of Scotiabank sought clarification on the FFO to debt cushion, how the Massachusetts PBR inflation mechanism interacts with tariffs, and the timing of a potential CL&P rate case.

Answer

EVP and CFO John Moreira confirmed the 100-basis-point cushion applies to both S&P and Moody's thresholds. He clarified that the PBR inflation mechanism addresses O&M, not capital, and is capped at 5%. He also stated that the company is still assessing the timing for a CL&P rate case, with the earliest potential filing being in the fall.

Andrew Weisel inquired about the potential for the recently acquired Mystic site to become a major investment opportunity, possibly exceeding $1 billion, and if it was included in the current capital plan. He also asked for the expected annual value of shares from DRIP and employee programs.

Answer

Executive VP and CFO John Moreira stated that Mystic is not yet in the capital plan but represents a significant long-term opportunity. Chairman, President and CEO Joseph Nolan added that the company would be comfortable with a large, FERC-regulated investment there. Moreira guided to an annual value of $100 million to $120 million from DRIP and employee stock programs.

Andrew Weisel inquired about the timing of the South Fork tax equity benefit and asked for clarification on the FFO to debt walk, given the increase in cash flow drivers. He also asked about the potential for shifting more capital away from Connecticut.

Answer

EVP, CFO and Treasurer John Moreira explained the South Fork tax benefits will likely be realized beyond 2026 as other tax attributes are being used first. He clarified the FFO/debt target range is unchanged, with the cash flow increase reflecting more quantified items. CEO Joseph Nolan reiterated that they have already moved $500 million in capital from Connecticut and will continue to monitor the regulatory climate for future investment decisions.

Andrew Weisel of Scotiabank asked about the primary driver for the recent asset sales, the allocation and timing of the $4 billion in incremental CapEx, and whether the stronger balance sheet might alter the company's thinking on dividend growth.

Answer

President & CEO Harry Sideris and EVP & CFO Brian Savoy explained the sales were an efficient way to fund growth and unlock the full potential of their businesses. Sideris confirmed the $4 billion in new CapEx is entirely for Florida in the 2028-2029 timeframe. Savoy stated that the current 2% dividend growth is appropriate for the investment cycle and helps lower the payout ratio over time.

Andrew Weisel of Scotiabank inquired about confidence in navigating the 'foreign entities of concern' (FIAC) clause, whether earnings from the Duane Arnold restart could offset the phase-out of renewable tax credits, and the reason for FPL's modest Q2 earnings growth.

Answer

John Ketchum, President, CEO & Chairman, expressed high confidence on the FIAC provisions, noting their safe-harbored projects through 2029 are not subject to them. Both Ketchum and Brian Bolster, President & CEO of NextEra Energy Resources, pushed back on the idea of an 'earnings cliff,' citing massive, persistent demand for energy infrastructure. Michael Dunne, EVP & CFO, attributed FPL's modest quarterly growth to a lower ROE this year and other factors, which he does not expect to persist.

Andrew Weisel asked for clarification on the moving pieces of the FFO to debt metric, which declined to 13.2%, and the path to reaching the 14-15% target. He also questioned if recent regulatory wins were already included in the $54 billion CapEx plan.

Answer

Trevor Mihalik, EVP and CFO, explained the year-end 14% FFO to debt was under an old methodology; the new methodology, accounting for deferred fuel, brought it to ~13.5%. He stated the minority interest transaction will add 40-60 bps, and continued focus on efficient operations will help them reach the 14-15% target range. Regarding the CapEx plan, he confirmed that while there are always puts and takes as projects are added or fall away, the plan generally incorporated expectations for such projects.

Andrew Weisel followed up on the dividend policy, asking how quickly the payout ratio would decline, and requested more specific guidance on the timing and form of the planned equity issuance for modeling purposes.

Answer

EVP and CFO Chuck Zebula indicated the dividend payout ratio would drift down gradually rather than abruptly. Regarding equity, he reiterated the need for support in 2025 and 2026 and stated that all options are being considered, but did not provide a specific share count assumption for 2025.

Andrew Weisel followed up on the dividend, asking how quickly the payout ratio would decline, and requested more specific guidance on the timing of the $5.35 billion equity need.

Answer

CFO Charles Zebula indicated the payout ratio decline would be gradual. He reiterated the need for equity support in 2025 and 2026 but did not provide a specific issuance schedule, noting that all financing options, including equity-like securities, are being considered.

Andrew Weisel asked for the company's trailing FFO to debt metric and for details on the proposed ramp-up of the Infrastructure Recovery Mechanism (IRM) to $1 billion.

Answer

EVP and CFO David Ruud provided the FFO to debt metric as being 'right at 15%'. President and COO Joi Harris explained that the IRM increase was proposed as a 3-year ramp with tiered options to give regulators flexibility. She noted a $1 billion approval would create more distance between rate case filings.

Andrew Weisel inquired about DTE's progress on its tree trimming program to reach a 5-year cycle and asked if the reliability spending outlined is fully funded within the current 5-year capital plan and contingent on rate case outcomes.

Answer

Executive Joi Harris stated that about 80% of the system is on a 5-year tree trimming cycle and the company is on track to complete it by the end of 2025. She confirmed the reliability spending is fully embedded in the capital plan but is contingent on constructive rate case outcomes. CEO Gerardo Norcia added that the program is funded by a securitized tree trim surge approved years ago.

Andrew Weisel asked for clarification on O&M levels, questioning if they have returned to normal after 2023's aggressive cuts or if the company is already in 'lean mode' for 2024. He also asked about the timing of taxes in the Corporate and Other segment.

Answer

EVP and CFO Dave Ruud characterized 2024 as feeling very different from 2023, stating that last year's O&M reductions were largely one-time. He described the company as being back to its 'normal DTE mode' of productivity and efficiency improvements, using its 'lean and invest' strategy as needed. Ruud also confirmed the negative earnings in Corporate and Other due to tax timing were consistent with the budget and will reverse by year-end.

The analyst sought to confirm if guidance figures were for calendar years, questioned the level of future CapEx needed to maintain stable cash flow, asked for a simplified post-2026 outlook, and inquired about other management changes.

Answer

Executives confirmed the guidance is for calendar years, not run-rate. They explained that initial CapEx extends asset life, and the post-2026 outlook is stable until new projects are announced. They also introduced Jessica Geoffroy as the new CFO.

Asked about potential transmission constraints related to the Duane Arnold restart, whether the new framework agreements contribute to the current 2027 plan or are incremental beyond it, and the reasons for the recent performance and outlook of the customer supply business.

Answer

The company is not concerned about transmission at Duane Arnold due to its large and flexible project pipeline. The new framework agreements are factored into achieving the midpoint of current development plans but offer upside potential. The customer supply business performance reflects a normalization of margins and volatility as gas prices have subsided from their 2022 highs.

Sought clarification on the 7 GW of projects with tech and data center customers, asking about the pace of additions and whether the total includes transmission, and also inquired about transmission opportunities with these customers.

Answer

The company clarified the 7 GW total consists of ~3 GW of operational and ~4 GW of backlog renewable and storage projects, not transmission. They noted that while data center customers are very supportive of new transmission to serve their load, they rely on partners like NextEra to actually develop and build the infrastructure.

Andrew Weisel of Scotiabank asked for details on the land at Artificial Island and posed a two-part question on nuclear economics: the potential risk to the IRA's nuclear PTC from an election, and whether New Jersey's ZEC program might be revamped if data centers sign contracts, to avoid ratepayer subsidies for tech companies.

Answer

Daniel Cregg, EVP and CFO, declined to comment on land specifics. Ralph LaRossa, Chairman, President and CEO, addressed the ZEC program, noting it expires before any data center deal would be active. He stated he would not support New Jersey ratepayers subsidizing tech companies and believes it's unlikely a company would receive a subsidy on top of a market-based power contract. He also noted the federal PTC's definition of 'gross revenues' is still pending.

Andrew Weisel of Scotiabank sought to clarify how many megawatts of nuclear capacity are available for new contracts and asked about the rationale for the higher cost of the EE2 energy efficiency program.

Answer

Chair, President and CEO Ralph LaRossa indicated the entire nuclear portfolio could be available for long-term contracts after the current state program ends in May 2025. Regarding the EE2 program, LaRossa and EVP/CFO Dan Craig explained the higher cost is due to shifting from simple measures like light bulbs to more complex HVAC upgrades and commercial projects, a strategy aligned with the BPU's goal to fund initiatives that would not happen otherwise.

Andrew Weisel asked for clarification on how much of PSEG's nuclear capacity is uncommitted and available for a new dedicated customer, and also questioned the drivers behind the higher cost per kWh saved in the EE2 program.

Answer

Chair, President and CEO Ralph LaRossa confirmed the entire nuclear portfolio could be available for long-term contracts after the current state ZEC program ends in May 2025. He explained the higher EE2 program cost is due to a shift from simple measures like light bulbs to more complex HVAC and industrial upgrades, which aligns with the BPU's strategy. CFO Daniel Cregg added the BPU aims to fund projects that would not otherwise occur.