Public Service Enterprise Group Incorporated (NYSE:PEG) Q2 2025 Earnings Call Transcript

Public Service Enterprise Group Incorporated (NYSE:PEG) Q2 2025 Earnings Call Transcript August 5, 2025

Public Service Enterprise Group Incorporated beats earnings expectations. Reported EPS is $0.77, expectations were $0.698.

Operator: Ladies and gentlemen, thank you for standing by. My name is Rob, and I’m your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group’s Second Quarter 2025 Earnings Conference Call webcast. [Operator Instructions] As a reminder, this conference is being recorded today, August 5, 2025, and will be available for replay as an audio webcast on PSEG’s Investor Relations website at https://investor.pseg.com. I would now like to turn the conference call over to Carlotta Chan. Please go ahead.

Carlotta N. Chan: Good morning, and welcome to PSEG’s Second Quarter 2025 Earnings Presentation. On today’s call are Ralph LaRossa, Chair, President and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today’s discussion are posted on our IR website at investor.pseg.com, and our 10-Q will be filed later today. PSEG’s earnings release and other matters discussed during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income as reported in accordance with generally accepted accounting principles, or GAAP, in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today’s materials.

Following our prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Ralph A. LaRossa: Thank you, Carlotta, and thanks to all of you for joining us this morning to review PSEG’s second quarter 2025 results and to discuss our outlook for the business over the rest of the year. PSEG delivered another quarter of solid operating and financial performance. And PSE&G is on track to execute on its full year $3.8 billion regulated investment program to maintain reliability. PSE&G also benefited from a full quarter of regulatory recovery of and on over $3 billion of previously invested capital, which was approved in the October 2024 settlement of our electric and gas distribution base rate case. PSEG’s results also reflect the positive impact of higher output from our nuclear generating fleet, which benefited from the absence of a Spring Hope Creek refueling outage experienced last year.

During the past quarter, we also continued to prioritize meeting our customers’ expectations on both the reliability and affordability fronts. In late June, we successfully operated through 3 consecutive days of 100-degree plus temperatures, prompting high electricity usage that set a summer peak load of 10,229 megawatts on June 24, the highest system load we have experienced since 2013. The value of our infrastructure resilience and storm restoration efforts benefited customers during a series of intense heat, wind and rainstorms, providing yet another validation of our investments in the system to maintain reliability, which also improves the customer experience. Our utility crews in New Jersey and on Long Island are working tirelessly to safely keep the lights on, restoring service to interrupted customers on a timely basis, redirecting employees from nonemergency work to focus on emergent service requests and deploying mutual aid to reinforce our local crews to restore service to customers even faster.

During the 4-day heat storm in June, PSE&G crews restored service to 99% of storm-interrupted customers within 24 hours. I could not be more proud of our team’s work and these results. Turning to our affordability focus. Given the warmer-than-normal summer thus far, higher electricity usage is expected to result in higher customer bills. In addition, our customers are seeing the electric rate impact of last year’s PJM capacity auction, which is just now translating into summer utility bills. PSE&G has responded by partnering with the New Jersey Board of Public Utilities to implement a summer relief initiative, providing all residential customers with deferred billing during 2 high-usage summer months, shifting collection of the deferral to lower electric usage months with no interest charged to customers.

The utility has also extended showoff protections for income qualified residential customers and suspended electric reconnect fees through September 30. In addition, PSE&G is processing 2 sets of upcoming state-funded residential energy assistance payments that will also reduce eligible customer bills. We also continue to connect our customers in need of payment assistance with all available resources, including our award-winning energy efficiency programs to help lower usage. Last month, PJM released the results of its latest capacity auction, which priced within a FERC-approved price collar at $329 per megawatt day for the 2026 to 2027 energy year. Despite this latest increase in capacity prices, we anticipate a near flat impact on customer electric bills when this latest price is feathered into the BGS supply rates in June of 2026.

This assumes other supply-related costs remain the same, preserving the reduction from other charges expected to come off the bill. As we’ve discussed on prior calls, the resource adequacy challenges in New Jersey and across the entire 13-state PJM region are becoming more acute as we see both growing demand and new supply slow to respond. Recent reports reflect an increasing amount of new large load applications that are quickly eroding existing reserve margins. Within the confines of PJM, it’s hard to see the path to new generation through existing market signals, which may require the consideration of a new approach to procuring capacity and resource planning. In New Jersey, the legislature convened on June 30, having held a series of hearings on energy affordability in advance of the PJM capacity-related summer rate increases.

Legislation introduced this past March, Assembly Bill 5439 could enable regulated utilities to be among those companies able to compete for potential generation projects should New Jersey decide to build or pursue new in-state generation. New Jersey remains a net importer of power. And during the June heat storms imported nearly half of its electric needs from out of state. Abundant excess generation capacity to our West that for many years, made power imports a convenient option is quickly being absorbed by rapid growth of native load in those states. In New Jersey, policymakers have begun to actively weigh the priorities of economic growth with system reliability and affordability and the state’s environmental policies. In fact, today, the BPU is conducting a technical conference on resource adequacy, focusing on the recent PJM capacity auction results and state-driven solutions.

We look forward to partnering with New Jersey and regional stakeholders to develop policy consensus on long-term comprehensive solutions that can meet our growing demand and improve resource adequacy while safeguarding affordability and reliability to meet New Jersey’s energy needs. While these conversations continue, our $3.8 billion regulated capital investment plan for 2025 is focused on infrastructure replacement and modernization to ensure safe and reliable service and to meet growing customer demand. These efforts are on track and on budget. As mentioned last quarter, PSE&G began the second phase of its Clean Energy Future-Energy Efficiency II program which will help customers save energy, lower their bills and reduce carbon emissions while supporting job training and economic growth right here in New Jersey.

And speaking of economic growth, as of June 30, PSE&G’s pipeline of large load inquiries for new service connections grew to over 9,400 megawatts, up 47% from 6,400 megawatts reported as of March 31. And as I’ve stated previously, these numbers include both mature applications that we refer to as new business, approximately 2,600 megawatts of the total, which has gone up by 40% since March 31 as well as feasibility studies and initial leads. Our engineering assessment turnaround is still averaging about 4 months, and this response time is supportive of the state’s objective to spur economic development. To the extent these large load prospects convert into new utility customers in the future, fixed costs are then spread over a larger user base which can help to lower existing customer bills.

Turning now to PSEG Power & Other Our nuclear units generated and supplied the grid with approximately 7.5 terawatt hours of carbon-free baseload power and achieved a fleet capacity factor of 88.8% for the second quarter, lowered by the scheduled refueling outage at Salem Unit 1. During this fall’s refueling outage, PSEG nuclear will perform the work needed to extend Hope Creek’s fuel cycle from 18 to 24 months. This is the first of several steps we are taking to optimize our plants, providing the grid with more reliable 24/7 carbon-free power between now and Hope Creek’s next scheduled refueling outage in the fall of 2027. In addition, our Salem upgrade project will bring approximately 200 megawatts for the size of a small modular reactor of incremental carbon-free dispatchable power during the 2027 to 2029 time frame.

We were also pleased that federal tax legislation passed in July preserve the downside price protection from the nuclear production tax credit, or PTC, as well as the PTC availability for expansions of nuclear capacity, which supports the planned power upgrade at Salem. In addition, the legislation permanently extends 100% bonus depreciation to qualified business property. To summarize, we had a good quarter and first half of 2025, which provides us with a solid base to confidently deliver on our full year 2025 non-GAAP operating earnings guidance of $3.94 to $4.06 per share, which is up 9% at the midpoint over 2024 results. Our 2025 guidance includes a full year of new distribution rates from our 2024 base rate case settlement, which was reached last October as well as an upcoming refueling outage at our 100% owned Hope Creek nuclear unit this fall.

In closing, we are also reiterating PSE&G’s updated 5-year capital spending program at $21 billion to $24 billion, which supports an expected rate base CAGR of 6% to 7.5% through 2029. This, in turn, drives PSEG’s 5% to 7% non-GAAP operating earnings CAGR while continuing to use the nuclear PTC as our reference price for power. PSEG intends to execute this capital plan without the need to issue new equity or sell assets. I’ll now turn the call over to Dan, who will walk you through the results for the quarter and our outlook for the remainder of 2025, and then I’ll rejoin the call for Q&A.

Daniel J. Cregg: Great. Thanks, Ralph. Good morning, everybody. PSEG reported net income of $1.17 per share for the second quarter of 2025 compared to $0.87 per share in 2024, and non-GAAP operating earnings were $0.77 per share in the second quarter of 2025 compared to $0.63 per share in 2024. These solid results were up over 20% from last year’s second quarter, reflecting the benefit of new distribution rates, which were placed into effect at PSE&G on October of 2024 and higher generating volume at PSEG Power, which reflects the absence of last spring’s Hope Creek refueling outage, which will take place this fall, raising O&M and lowering output in the second half of 2025. We’ve provided you with information on Slides 8 and 10 regarding the contribution to net income and non-GAAP operating earnings by business for the second quarter and first half of 2025.

Slides 9 and 11 contain waterfall charts that take you through the net changes for the quarter and year-to-date periods over the prior year and non-GAAP operating earnings per share, also by major business. Let’s start with PSE&G, which reported second quarter net income and non-GAAP operating earnings of $332 million for 2025 compared to $302 million in 2024. For the year-to-date ended June 30, PSE&G reported net income and non-GAAP operating earnings of $878 million in 2025 compared to $790 million in 2024. Utilities results were driven by the implementation of new electric and gas base distribution rates that went into effect last October to recover a return of and on previous capital investments totaling more than $3 billion. Beginning on Slide 9 with the PSE&G column, Transmission margin was $0.01 per share higher compared to the year ago quarter on higher investment and a prior year true-up.

Our distribution margin increased by $0.10 per share compared to the year ago period, largely reflecting the impact of the rate case plus recovery of and on PSE&G’s regulated energy efficiency investment. On the expense side, distribution O&M costs were $0.01 per share favorable compared to the second quarter of 2024, though for the full year, distribution O&M is expected to be higher versus the prior year. Both depreciation and interest expense each rose $0.02 per share compared to the second quarter of 2024, reflecting higher levels of depreciable plant investment and long-term debt at higher interest rates. Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to 0 over a full year, had a net unfavorable impact of $0.02 per share in the second quarter compared to the prior period, reversing a positive $0.02 per share impact in the first quarter of 2025.

Weather conditions during the second quarter, as measured by the temperature humidity index were 21% warmer than normal, but 14% cooler than the second quarter of 2024. As you know, the Conservation Incentive Program or CIP mechanism decouples weather and other economic sales variances from a significant portion of our distribution margin, while helping PSE&G promote the widespread adoption of energy conservation, including energy efficiency and solar program. Under the CIP, the number of electric and gas customers is the primary driver of distribution margin, and each segment grew by approximately 1% over the past year. On the capital front, as Ralph mentioned earlier, PSE&G invested approximately $900 million during the second quarter, and we are on track to fully execute our 2025 regulated capital investment plan of $3.8 billion, focused on infrastructure modernization, energy efficiency and meeting growing demand.

And we have maintained our 5-year regulated capital investment plan of $21 billion to $24 billion through 2029. We began the next phase of our energy efficiency program during the first quarter of 2025, and we anticipate investing up to $2.9 billion over a 6-year period. The energy efficiency program total includes approximately $1 billion of ongoing repayment options to help our customers finance their energy efficiency equipment and appliances and provides customers with energy information and options to manage their energy use and lower their bills. Moving on to PSEG Power & Other. For the second quarter, PSEG Power & Other reported net income of $253 million in 2025 compared to $132 million in 2024, and non-GAAP operating earnings were $52 million in the second quarter of 2025 compared to $11 million in the second quarter of 2024.

For the year-to-date ended June 30, PSEG Power & Other reported net income of $296 million in 2025 compared to $176 million in 2024, and non-GAAP operating earnings of $224 million in the first half of 2025 compared to $180 million for the first half of 2024. Referring again to the waterfall on Slide 9. For the second quarter of 2025, net energy margin rose by $0.04 per share, driven by higher nuclear generating output. O&M was $0.03 per share favorable compared to the second quarter of 2024, driven by the absence of last spring’s Hope Creek refueling outage. Interest expense rose by $0.02 per share, reflecting incremental debt at higher interest rates. Taxes and other were $0.03 per share favorable compared to the second quarter of 2024, in part due to the use of a lower annual effective tax rate in 2025, that will reverse over the balance of the year.

On the operating side, the nuclear fleet produced approximately 7.5 terawatt hours during the second quarter, up by 0.5 terawatt hour over the same period in 2024 and reached 15.9 terawatt hours for the first half of this year, both benefiting from the absence of last spring’s Hope Creek refueling outage. Capacity factors for the nuclear fleet were 88.8% and 94.3% for the quarter and 6-month period ended June 30, 2025, respectively. In late July, PSEG Nuclear cleared approximately 3,500 megawatts of its eligible nuclear capacity in PJM’s base residual auction, at $329 per megawatt a day for the energy year beginning June 1, 2026 through May 31, 2027. This latest result is up from $270 per megawatt day for a similar amount of capacity in the 2025, 2026 PJM capacity auction.

For the second half of 2025, results at PSEG Power & Other will be impacted by this fall scheduled Hope Creek outage and the completion of the 3-year Zero Emission Certificate award that ended on May 31, which will offset higher capacity revenues related to the 2025, 2026 auction results in the back half of this year. Touching on some recent financing activity. As of June 30, PSEG had total available liquidity of $3.6 billion, including $186 million of cash on hand. On the financing front, PSEG Power issued $1.5 billion of senior unsecured debt this past May, consisting of $750 million of 5.2% 5-year notes due 2030 and $500 million of 5.75% 10-year notes due 2035. The proceeds from this sale were used to repay the $1.25 billion variable rate PSEG Power term loan that was scheduled to mature engine.

PSEG’s variable rate debt at the end of June consisted of a 364-day term loan at PSEG Power for $400 million, which matures in December of 2025 and commercial paper. As of June 30, following the redemption of the PSEG Power, $1.25 billion variable rate term loan in May. Our level of variable rate debt represents approximately 3% of our total debt. In July 2025, federal fax legislation preserved the downside price protection of the nuclear production tax credit as well as the PTC availability for expansions of nuclear capacity which supports our planned power upgrade at sale. In addition, this legislation permanently extends 100% bonus depreciation for qualified business property, improving cash flow at PSEG Power as it executes on its planned capital program.

As Ralph mentioned, we are reaffirming PSEG’s full year 2025 non-GAAP operating earnings guidance of $3.94 to $4.06 per share as well as a long-term 5% to 7% non-GAAP operating earnings CAGR through 2029 at nuclear PTC threshold. Our solid balance sheet supports the execution of PSEG’s 5-year $22.5 billion to $26 billion capital spending plan without the need to sell new equity or assets and provides the opportunity for consistent and sustainable dividend growth. That concludes our formal remarks, and we are ready to begin the question-and-answer session.

Q&A Session

Operator: [Operator Instructions] The first question today is from the line of David Arcaro with Morgan Stanley.

David Keith Arcaro: So today, we’ve got the New Jersey Resource Adequacy conference going on at the BPU. I was just wondering if you could give a sense of where conversations stand with regard to the future of generation build in New Jersey?

Ralph A. LaRossa: Thanks, David. Yes, so it’s a little bit tough for us to do this real time. They are literally — folks are literally having conversations right now. So there really hasn’t been a big change from a legislative standpoint, right? We talked a little bit in the prepared remarks about the bill that is currently sitting in the legislature. But I’m looking forward to the conversation today that’s taken place. And I would tell you, we are advocating really for some decisions to be made by the state as we move forward. And that’s really just around what are the forecasts they’re looking for. We’ll be talking about that. What are the reliability outcomes they’re targeting. What are the affordability targets they have.

And then finally, the environmental policy goals. When you put those 4 pieces together, we think we’ll be able to find the right answer and solution for the state. And we’ll be willing to help out in that in whatever way the state is looking for us to play a role. So we’re going to stick to those 4 points. and really try to drive some decisions from the existing administration and obviously having conversations with the potential gubernatorial candidates.

David Keith Arcaro: Yes, absolutely. That makes sense. Appreciate that. And then a big increase in the data center pipeline for this quarter. And I was wondering if you could give an update on maybe specifically with regard to the nuclear plant opportunities and an update on data center conversations there, what is the interest level that you’re seeing in the site most recently and then thoughts on timing as to whether you could get to an agreement this year?

Ralph A. LaRossa: Well, I’m going to — I’ll give that to Dan, as I usually do on the data centers. I would just say from an economic development standpoint, we’re glad to see New Jersey still playing a role in that. They have continued to advocate for data centers and for technology companies to locate into New Jersey. So it’s good to see that, that is working, and that is playing out in the numbers that we provided. I think yesterday, there was an announcement by CoreWeave for a large investment they’re making in Kenilworth, New Jersey for some real estate that they’re purchasing. So I think the work that’s being done on the economic development front is bearing some fruits now, and I’ll let Dan talk specifically about anything down at nuclear.

Daniel J. Cregg: And David, there continues to be discussion and I think Ralph’s earlier commentary on the numbers going up in the state are evidence of that. And I think that you’re well aware that our assets are both in New Jersey and in Pennsylvania. And I think there’s opportunities across those states and frankly, wherever power can be delivered from those units for the nature of what we have. So the discussions continue. There continues to be interest, and we’ll let the timing kind of speak for itself as we go forward.

Operator: Our next question is from the line of Nicholas Campanella with Barclays.

Nicholas Joseph Campanella: I just wanted to follow up on that last point maybe. In your prepared you kind of — you brought up clearly the need to add new generation in New Jersey. The fact that the state is an importer of power, and you talked about needing to kind of balance affordability and resource adequacy along with economic development. Just how do you kind of see that impacting your ability to move forward with a multiyear contract by the end of this year? And is it still your intention to deliver something by the end of the year? I just wanted to be a little bit more pointed on that.

Ralph A. LaRossa: So again, we’ve been — we would say we’d like to do something with this administration. We’ve been saying that for many months now, and I think that, that would still stand. But we’re not going to do a deal just for the sake of doing a deal by a certain time frame, right? So we’ve talked about that and that really hasn’t changed. I think from a balancing standpoint, Dan just put it really well. We have assets in both Pennsylvania and New Jersey. We have data centers showing up across the PJM footprint, not just in New Jersey. And I think this resource adequacy conversation that’s taken place today recognizes the fact that what happens in our bordering states matters to New Jersey. When you’re importing 50% of your power on your peak days, those decisions that are being made by other economic development organizations, other governors, other utilities, all have an impact on what happens here in New Jersey.

So I don’t think we have — we tend to have to think we have all the answers. But to your very specific question on how it all comes together. I think it’s really a PJM question. It’s not just a New Jersey question.

Nicholas Joseph Campanella: That makes a lot of sense. I appreciate the context. And then maybe with the capacity auction results, I know you kind of talked about the ZEC roll-off, that kind of offsets the ’25, ’26. But then when we think about ’27, ’28, how are you kind of framing where you are on a gross receipt basis? And I guess my question is, are you now higher in the range because of the ’26, ’27 outcome?

Ralph A. LaRossa: Well, I’ll let Dan talk to again some more specifics here, but we have not come off of the fact that our guidance remains at the PTC 4 with our 5% to 7%, and I’ll give it to Dan to talk from there.

Daniel J. Cregg: Yes, exactly. And obviously, it goes against the backdrop of what the market looks like, Nick, and you know as well as anybody that capacity is a piece of what the nuclear facilities make as much as they run, energy is a bigger piece. But if you’re seeing higher capacity clears that sustain then you’re going to see higher capacity component of the overall revenue that will sustain at a higher place. And if energy markets, the electricity side, the energy side, ends up moving to a point where you are higher, well, then we’re going to have moving off of that. We are not there right now with respect to what we see for the CAGR that we’ve put out. But we continue to monitor, we continue to market the output. And ultimately, that’s going to determine where we land against the backdrop of future forecasts. But right now, as Ralph says, what we have out there is based upon the threshold.

Operator: Our next question is from the line of Michael Sullivan with Wolfe Research.

Michael P. Sullivan: I wanted to just ask another one on kind of the New Jersey supply situation. I guess outside of this bill that’s out there, what are the other options if that weren’t to move forward? And then we saw kind of next door in Pennsylvania, one of your peers doing kind of a JV outside of the regulated construct. Is that something you guys would consider at some point?

Ralph A. LaRossa: We have — so we have very specifically said we are not interested in moving back into the merchant generation business. So that has not changed for us. I think the construct that was mentioned by others is really maybe a little bit different, but I’ll let that — let them speak for themselves. And so what does that leave us with? It leaves us with the PJM process. And look, we’ve been very thoughtful about that for many years at this company. We don’t think that it’s attracting additional generation. We think there’s problems with the capacity process that exists, the market as it’s called and how it exists there at PJM. And so unfortunately, if there isn’t a change, and there isn’t some more control taken by the state of New Jersey, we will be living with the outcome of that process.

And all we can speak to are the facts. And the facts are that there has not been any new baseload generation built in New Jersey for quite some time. And I believe our former merchant generation business was the last one to do so.

Daniel J. Cregg: And I think the only thing I would add to that, Michael, is some of the discussions that others are listening to concurrent with this call, I think are going to that topic. And there’s other discussions. So I think there’s a — the PJM governors are going to meet next month to try to talk about what’s going on. And so I think that right now, all those discussions are against the backdrop of the challenges that we have from what’s in place at PJM and what supply could come out of that process or not come out of that process. And as a result, what things should be done to ensure that we have the supply we need. So that’s where those discussions are all circling around.

Michael P. Sullivan: Okay. That’s really helpful. I appreciate all the color there. And then just shifting over to OB3, can you maybe put a little more numbers or quantification around some of the benefits there, both with respect to bonus depreciation and what that does for your cash tax position and then also the new tax credit on the uprate. Like any numbers around those 2 items you can give us?

Daniel J. Cregg: No. And Michael, I think that the thing that it mainly did from the standpoint of the PTC is it retained what was in place. There was some discussion that hard to tell exactly how much traction it got about potentially shortening it or potentially changing it. But everything from a nuclear PTC perspective, stayed in place and if we — an answer to the next question, if we move to a higher overall market condition, I would still love to have that protective backdrop of the PTC from the standpoint of an overall revenue threshold. I think what really for us was new within that was bonus depreciation. We’ve had different bouts of bonus depreciation in the past, and this one is laying out to make it permanent. But as a reminder, the bonus is not throughout the entire company.

It is only for the unregulated piece, and there’s not that much capital that’s there. So is it a help? Yes, it’s a help, but it’s kind of around the edges from the standpoint of an overall cash flow perspective, that it will accelerate some of that cost recovery a little bit earlier than otherwise would have been the case.

Operator: Our next question is from the line of Ross Fowler with Bank of America.

Unidentified Analyst: It’s actually [ Randy ] here for Ross. I just had a quick question about the — we saw a lot of affordability-focused bills in this session. So I guess from your perspective, which of those bills are kind of gaining the most traction and kind of how the — will have likely the biggest impact moving forward, I guess, in terms of like regulated gen, which you talked about or cost deferrals or reassessing New Jersey’s role in PJM?

Ralph A. LaRossa: So the session has closed officially, right? So they can always come back. But right now, there is no there’s no scheduled time for the legislature to come back to discuss those bills. I think they have a couple of items that we’re dealing with on health care, but there’s nothing that’s very specific to the utility space. So I would be hard-pressed to say that any one of those specific bills are ones that we’re focused on. I think what we’re really focused on is finding a solution for the customers. And we’ve done that with the short term, and now we’re trying to have a conversation, which, again, is taking place as we speak at the New Jersey Board of Public Utilities on the resource adequacy. And we’re going to continue to advocate as strong as we have at PJM.

So I wouldn’t point you to any one of those bills specifically because, again, they may — they will change down the road if they even continue in some fashion. But I would just leave it at that and not really speculate on what might or might not happen.

Unidentified Analyst: Okay. That makes sense. And then just secondly, I know you’ve mentioned the 200 megawatts out of Salem, but I guess more broadly, what potential is there for incremental generation and upgrade on the nuclear fleet to upgrades refueling cycles, license extension and then I guess how much of that has already been executed?

Ralph A. LaRossa: Well, thanks for that. We’re actually — from an execution standpoint, much of the engineering work has been done on everything that you asked about. But we did mention earlier in the prepared remarks, the fact that in this refueling cycle that will be taking place in the fall at Hope Creek. We will be setting the unit up for the first time for a 24-month run. So that is the change in the fuel cycle that we had talked about. So we’re continuing to execute on the plan that we had discussed and the engineering work, and we have not discussed the cost or the exact timing of that. But we plan the upgrades for the Salem units later in the next few years. So, nothing specific has been out there on that yet, but I think we did say we’ll have that done by the end of the decade for sure and we’ll have that information out by the end of the year.

Operator: Our next questions are from the line of Carly Davenport with Goldman Sachs.

Carly S. Davenport: Maybe just to start on the update on the large load inquiries at the utility level. Is that sort of 10% to 20% conversion rate still hold in your view on that 9,400 megawatts? And is that all data centers at this point? Or are there any other customers in that bucket?

Ralph A. LaRossa: There’s a few other customers in that bucket, but I would say the bulk of that, if not over 90% of that is all data center related. And if you think about the numbers that we quoted to you, the 9,600 megawatts is sort of everything together and then you apply the 10% to 20%, it kind of aligns with our what we call new business number, that’s out there. So the short answer is yes, it’s sticking with the 10% to 20%. And longer answer is you can see that in the details that we’ve provided.

Carly S. Davenport: Perfect. And then maybe just thinking about 2025 earnings growth, as you think about 1H, growth is tracking above your full year 9% expectations. I know that we’ll have the Hope Creek outage in the fall, which will be a drag. But I guess I just would love your thoughts on how you feel about execution within the full year guidance range at this point in the year?

Ralph A. LaRossa: Yes. We tried to make the point, we feel confident about being within the range for sure, and we reiterated that. So I don’t think we’re going to go anywhere beyond that at this point.

Daniel J. Cregg: Carly, we’re at the halfway point, we do sit a little bit north. And I think that, that Hope Creek outage that, that’s the reason we did highlight within the materials that, that was coming at the back end, just a reminder that, that’s 100% owned. And so when that does come through, it has a bigger impact as we move through quarter-by-quarter.

Operator: Our next questions are from the line of Ryan Levine with Citi.

Ryan Michael Levine: Would you seek the customer bill deferral mechanism for an additional year as a result of the higher PJM capacity prices during peak load months? Is that something you’re contemplating given the recent events?

Ralph A. LaRossa: Well, first of all, that conversation will take place with the new administration and the new BPU. So right now, there’s nothing in the plan for the state of New Jersey to pursue that.

Daniel J. Cregg: Ryan, just to be clear, with respect to the capacity auction that just happened and the impact on the bill. What we saw in June was the reflect of what I’ll describe as a catch-up. Because the PJM auctions were as delayed as they were, you’re seeing the cumulative effect of catching up from the prior auction results to that $270 that we saw. What happened in June brought everything up to $270. So you would not expect to see as a result of the $329 that kind of a jump, number one. And number two, if you just take a look at in our normal BGS process, the auction that’s rolling off the bill and the auction that’s rolling on the bill and you take a look at where prices sit now, not only do we not expect a jump like we saw in June, we don’t really expect much movement at all because what’s coming off the bill is a little bit higher than what would roll on at the current prices.

And so that’s not to say that something couldn’t be done from the standpoint of what you’re describing. That’s not in place now. Ralph answered 100% corrected that we work with the regulators as we were to do that. But it would not be in the face of an increase like we saw in June because that is not what is forecasted as we go forward just based upon the mechanisms and the pricing.

Ryan Michael Levine: And then just one follow-up in terms of the large load request additions. Is there any color around how many customers or individual projects represent that large megawatt increase just to assess kind of the chunkiness of that add?

Ralph A. LaRossa: Yes. So I would — I’ll add some color without any details. And the color is that what we see here in New Jersey would be a smaller projects than what you’re hearing in some other places. So you’re not talking about 1,000 megawatt hyperscale in the middle of the Garden State Parkway, right? So it’s a little different type of environment here, a lot of edge computing, a lot of backup locations, but it’s large. And look, our peak load is not much north of 10,000, and we’re getting close to that in inquiries that we’re receiving in. It’s a game changer for all of us. You’re seeing it across the PJM footprint. And so just we’re getting our fair share is the way I would put it, but smaller projects than what some of the other states are seeing.

Ryan Michael Levine: And then lastly, you referenced the CoreWeave development from earlier in the week. Is that incorporated in this updated forecast or projection?

Ralph A. LaRossa: There’s a piece of the conversation that they’ve talked about that’s in our current projections. They have not gone out with their full build yet for what they planned.

Operator: Our next questions are from the line of Travis Miller with Morningstar.

Travis Miller: So just following up on this resource adequacy discussion. At a high level, I wonder if you could characterize, is the concern among New Jersey, the legislatures, BPU, etc, that there aren’t enough electrons, either energy or capacity in New Jersey, i.e., that 50% import? Or is it just that the economics aren’t good for the customer bill? If that makes sense, how is that debate characterized?

Ralph A. LaRossa: Well, I would say in the near term, it has all been focused on affordability. And that’s where the conversation has been focused with the capacity price increases and what customers are seeing. So it starts there right now. But it is not too far in the recent past that you can look back in and talk about reliability concerns that folks had. And you can also, not too far in the recent past, talk about environmental concerns that people have had about what kind of power we were importing or not importing into the state. So we continue to — that’s why we keep bringing everybody back to the big picture, what is out there from a policy standpoint that we can — and what solutions can we bring to solve for all those policy issues that are being raised.

So I don’t want to say it’s all affordability because it’s not too far in the past. I mean — and my past is a little bit different maybe than others. I’ll go back to 2003 when the lights went out. The whole focus at that point was on reliability. Not too far after that, we had an issue from affordability standpoint, where — we were — we had some congestion that was taking place, and that was resolved with some transmission build that was done. Then we focus back on some environmental concerns that were taking place, and then we focused on reliability again after Superstorm Sandy. So it’s been all of those pieces that have been out there and have been discussed and we’re just reminding people of all of it as we focus today on affordability.

Travis Miller: Okay. That’s great. I appreciate all that. Here’s to hoping the lights don’t go out for you guys again through all of this. But one quick question on the — if the state were to go to a regulated generation option, would that need FERC approval? Would that have to go through FERC or some other federal entity?

Ralph A. LaRossa: No, I don’t believe it would. I think as long as the state — it went through a regulator. They’ll have to be a question about whether or not it’s an FRR or how they would actually go about the process. But I do not believe it would require any FERC approvals.

Operator: Our next question is from the line of Paul Fremont with Ladenburg Thalmann.

Paul Basch Michael Fremont: Congratulations on a strong quarter. I just wanted to sort of maybe better understand CoreWeave, would the relationship there be with the utility or with PEG Power if there is a relationship between Public Service and the new data center.

Ralph A. LaRossa: Yes. The only thing that’s been out there with CoreWeave has been the utility, and that’s what we spoke to, and that’s what we’ve included here, Paul. Anything else from a relationship standpoint will come out when Dan talks about whatever Dan talks about down the road at future conversations.

Paul Basch Michael Fremont: Okay. And then the purchase that they made involves some cogeneration facilities. So is it contemplated that there would be a need for additional generation at the site? And if so, how much in terms of megawatts.

Ralph A. LaRossa: Yes, that’s a question for their site management and that I wouldn’t be able to tell you. There is a cogen facility there. So I guess it’s sort of behind the meter generation, as we have said multiple times, there’s cogeneration in the state of New Jersey, and there’s multiple sites that have that. So a lot to be determined there as to how that’s used and what other needs they might have.

Paul Basch Michael Fremont: And how big is the existing cogen facility, how many megawatts?

Ralph A. LaRossa: I don’t have that off the top of my head, Paul, again, it’s a question for their site team. I’m not sure what capabilities that unit has today. Nameplate was under 100, if I remember correctly, but I couldn’t tell you exactly.

Operator: The next question is from the line of Julien Dumoulin-Smith with Jefferies.

Julien Patrick Dumoulin-Smith: Let’s just quickly — well, first off, I got to say, speaking of energy up on the year, you guys are trending very well in the year, $0.26 year-to-date. I heard your comments about being confident in the range, but I’m curious where you’ll land next quarter as far as reiterating that guidance. Maybe a comment more than the statement — more than the question.

Ralph A. LaRossa: Your comments and questions, we appreciate that.

Julien Patrick Dumoulin-Smith: Absolutely or maybe in response to Carly’s, any — but just going back to the Garden State energy storage. I mean, I heard your comments earlier about power, right, and maybe not necessarily expanding the scope per se, but what’s the willingness to participate in this initial bid process that seems ongoing now of the gigawatt? Or to what extent do you anticipate Power and/or PSE&G participating in the current phase into future phases, right? Again, you could approach this from a few different angles. But how do you think about that being “the primary answer” in the current environment as best we talk about this resource adequacy problem here in New Jersey.

Ralph A. LaRossa: Yes. So there’s a lot in that question. I would say, how do we think about it from a primary solution. I’ll dive on that a little bit. I want to take you from the 3 or 4 topics that we talked about and not the least of which is an affordability question. Then there’s an environmental question or some other questions that need to take place there, right? So until we see what some of the pricing is at, I don’t know how much of a solution it will be. We’ve seen prices that are high. We’ve seen prices that are coming down to some degree on some of the battery activity. But I wouldn’t say it’s a silver bullet right now. I think it’s part of an all of the above that we’ve advocated for 3 years. And I think if I’m not mistaken, we had made a filing over 5 years ago, down with the state of New Jersey proposing a battery solution from our utility.

So we believe in it. It’s just a question of how much from an affordability standpoint fits into that. We like to call it Venn diagram where everything comes together. So a little bit more there. And then our participation, we haven’t talked to and I won’t front-run anything about that. There are multiple states that have some battery requests out, and we look at all the opportunities all the time but we have not commented on that.

Julien Patrick Dumoulin-Smith: Got it. And look, Ralph, you’re always in the know on these things. With respect to PJM and this conversation on governance and engagement here, I mean, how do you think we could look at the auction in just PJM and New Jersey’s relationship going forward? I mean I know they’re asking for board seats the representation and shifts in government. But there’s also a separate conversation about shifting the nature of this auction towards bifurcated structures and/or just other permutations that I’m sure are swimming out there, if you will. Any comments on any of that?

Ralph A. LaRossa: Look, I’m going to take you back to things that we have said for, again, years and even when my predecessor was on this call, there’s — the governance at PJM doesn’t allow for a lot of the things that people are talking about to just be unilaterally implemented. So we have to get through a process where the members are going to vote on this. It may sound crazy, right? But the members are going to vote whether or not they want to have the governors participate or not and or their representatives. And then if not, maybe the governors could take some action and go down to FERC and have a conversation that could play out. But this governance process is the core problem here right now, and it’s really — it’s not something we have not said in the past, and I’ll just reiterate it, it’s how crazy does it sound that the governors have to get a member’s committee vote to allow a vote to take place to have a seat at the table.

And it’s — we have certainly tried to represent the customers. We welcome the transparency of the voting process that people are calling for. We think they’re at the end of the day, we’ll get to a good solution here, but it’s not an overnight silver bullet, and I’ll use that term again, solution that’s going to take place. And I’m happy we have the collar in there right now. It’s given us some time to have a conversation. But it, again, didn’t solve the long-term problems that we’re facing.

Operator: Last question is from the line of Paul Patterson with Glenrock Associates.

Paul Patterson: Just sort of to follow up on these policy questions. I’m just wondering, I mean, given that — I think you mentioned 5439, I don’t think that’s moved. And I guess what I’m wondering is given that the legislatures is kind of in recess here and the fact that you’ve got a governor who’s leaving, we’ve got election coming up here. And just the politics of all this and what have you, is it likely that anything is going to happen legislatively, you think this year in New Jersey, given all these dynamics and the fact that we just don’t seem to have that much movement on a lot of this stuff.

Ralph A. LaRossa: Yes. Look, I think there’s a lot of momentum behind it. I think there is a lot of consistency in the conversation, whether it’s with the existing administration, either of the gubernatorial candidates, I think there are some nuances in how they would approach the solution. But I think every one of them that we talk to continues to desire more control over those items that I mentioned, I’ll continue to say them. It’s the reliability, it’s the affordability and the environmental piece of it and the forecasting, right? I mean you’ve heard that in the past. So all 4 of those pieces need to come together. And I think that every one of the — whether it’s the existing administration or the 2 future potential administrations feel like that’s something they want more control over.

So the possibility exists, right? It could happen if there’s alignment between the existing administration and an incoming administration, a lot of things could happen towards the end of the year.

Paul Patterson: Okay. With respect to batteries and their ability to sort of give a capacity value. And given where prices are in the capacity market, is there any thought about revisiting what you were mentioning before? Because it sounds like you could build those as a utility asset. Any thought about how those might work economically, given where capacity markets are in the curve and what have you? Or is it — just what are your thoughts about that, I guess?

Ralph A. LaRossa: Yes. No. Look, I think there’s a lot of opportunity there from a revenue standpoint to your — to what you’re saying. But right now, that’s still all a merchant solution. The utility did propose a rate base solution, and it has not been acted on yet. And I respect that. Right now, the BPU is — and it’s been for many years, has looked at that as a merchant solution. I think that Garden State battery storage specifically says they would like to have a merchant solution for it. And so maybe the math will work out. I won’t opine on that right now. I’ll just tell you that I think there’s a role for the utilities to play, and I think there is a potential role for the competitive markets to play.

Operator: At this time, I’d like to turn the floor back to Mr. LaRossa for closing comments.

Ralph A. LaRossa: Thank you. Well, I’ll end where I started, which is to thank you to the employees for the work that was done. This has not been an easy weather pattern for us over the past couple of months. While we talk about storms and we talk about heat, we don’t talk about when that all occurs. And this is — these storms have rolled in consistently on Fridays, and the disruption that puts on people’s lives, the ability that they — for them to spend time with their families is interrupted, and we certainly just take a second to pause and thank everyone for the work that they’ve been doing during that time. And then I also want to thank our customers for engaging with us and having conversations. We are here for our customers.

But we also know that there’s challenging times from an affordability standpoint, not just with utility bills, but across the board. And we are bringing those solutions in the near term and fighting hard and advocating for the long-term solution. So you’ll continue to hear and see more of us doing that and you’ll continue to hear and see more of us on the road as we get back out there in the next couple of months. So thanks for calling in, and have a great rest of your summer.

Operator: Ladies and gentlemen, this concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.