Title

Presentation

Public Service Enterprise Group Incorporated misses on earnings expectations. Reported EPS is $1.43 EPS, expectations were $1.44.

Operator: Ladies and gentlemen, thank you for standing by. My name is Shamali, and I am your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group’s First Quarter 2025 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, April 30, 2025, and will be available for replay as an audio webcast on PSEG’s Investor Relations website at investor.pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Carlotta Chan: Good morning, and welcome to PSEG’s first 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 LaRossa: Thank you, Carlotta. And thank you for joining us this morning to review PSEG’s first quarter 2025 results and discuss the outlook for the business. PSEG delivered a solid operating and financial performance at both our utility, PSEG and our nuclear units. Overall results for the first quarter benefited from a full quarter of regulatory recovery of and on our invested capital approved in the October 2024 base rate case settlement, as well as the seasonality of gas revenues, which are concentrated in the first quarter. Results also reflected positive impact of our consistent and reliable nuclear generation performance which realized higher prices, primarily driven by weather. Our service territory experienced multiple cold spells in January and February, with temperatures remaining below 20°F for several days in a row which prompted our highest winter peak load for both gas and electric in the last six years.

During these challenging conditions, PSE&G maintained high levels of reliability and efficient customer response times. While PSEG nuclear generated and supplied the grid with approximately 8.4 terawatt hours of 24/7 carbon-free power. PSEG’s focus on increasing the predictability of our results continues to benefit both customers and the company, aided by our Conservation Incentive Program, which decouples revenues from volumes and deferral mechanisms for pension and storms from the recently concluded rate case. This predictability, combined with PSE&G’s predominantly residential and commercial customer profile, also reinforces our stability as a utility investment with defensive characteristics in a turbulent equity market. We consistently manage our cost structure to keep bills as low as possible, while maintaining PSEG’s financial flexibility to deliver safe and reliable service.

The domestic concentration of our supply chain also limits the amount of tariff-related cost pressure on our O&M. Combined with our multilayer labor agreements with all of our New Jersey unions extending into 2027 provides stability for our largest operating costs. As we’ve discussed previously, the basic generation service, or BGS default rate is scheduled to increase our residential electric bills by 17% starting June 1. As a reminder, BGS is a pass-through cost for energy supply that PSE&G does not burn a profit on. The increase is largely due to the July 2024 base residual auction result of $270 a megawatt day that was reflected in the latest BGS update as well as a true-up for the prior two years of BGS auction, which had included proxy prices for capacity.

Last week the New Jersey Board of Public Utilities directed the state’s electric companies to submit proposals to mitigate the customer bill impacts of the BGS increase. PSE&G continues to work with the BPU and state policymakers to develop a solution. We understand the real kitchen table difficulties these PGM-related increases will have on our electric customers. However, until new generating supply is added to the grid given the existing resource adequacy and balance, upward pressure on energy prices will persist. While these discussions are ongoing, PSE&G continues to offer an enviable record of reliability, affordability and customer satisfaction. PSE&G’s combined electric and gas bill still compares favorably to all other utilities in New Jersey.

Our reliability metrics continue to differentiate our service and our customer satisfaction rankings are second to none. I would add that this last metric measures us against all of our large peers in the East, not just in New Jersey. Our regulated capital investment plan for 2025 remains 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. PSE&G also began rolling out 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 here in New Jersey. In February, we mentioned a 12-fold increase in inquiries from large load or data center customers into PSE&G’s new business pipeline, which had grown from 400 MW in early 2024 to 4,700 MW.

These numbers include both mature applications and initial leads. Our latest update now shows PSE&G experienced another quarterly increase in large loan inquiries for new service connections and the pipeline now exceeds 6,400 MW of capacity requested as of March 31. Our engineers have been responding to these inquiries on a timely basis, still averaging about four months and our speed to response is supportive of the state 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 operations generated the supply of the grid with approximately 8.4 terawatt hours of clean and reliable baseload power and achieved a fleet capacity factor of 99.9%.

Over the past quarter, there has been a lot of discussion in New Jersey about the need and potential for new generation in the region and potentially in the state. Specifically, legislation was introduced this past February that proposes to change the current New Jersey law that prohibits regulated utilities from building and owning new generation. We remain open to this possibility, and we continue to work with New Jersey policymakers about this and other solutions to meet New Jersey energy needs. Regarding the ongoing discussion around the pending data center proceeding at FERC, we recently submitted PSEG’s comments in support of colocation with the position that’s behind the meter data center should pay for their actual use, consistent with the treatment of other behind-the-meter customers on our system, such as rooftop solar and universities.

Several other large generators in data center developers have requested a 90-day settlement process, which could be a path towards timely establishment of rurals for colocation. To recap, we are reiterating PSEG’s full year non-GAAP operating earnings guidance at $3.94 to $4.06 per share, which is up by approximately 9% at the $4 midpoint over our 2024 reported results. We are also reiterating PSE&G’s updated five-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 using the nuclear production tax credit as our reference price for power. Before I conclude, let me again thank our 13,000 employees across PSE&G Nuclear, PS Long Island [ph] and at services for their dedication and positive difference they make every day for our customers, our company and the communities where we live and work.

I will 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 rejoin the call for a Q&A.

Dan Cregg: Thank you, Ralph. Good morning, everybody. PSEG reported net income of $1.18 per share for the first quarter of 2025 as compared to $1.06 per share in 2024. And non-GAAP operating earnings were $1.43 per share in the first quarter of 2025 compared to $1.31 per share in 2024. We’ve provided you with information on Slide 8 regarding the contribution to net income and non-GAAP operating earnings by business for the first quarter. And Slide 9 contains a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings per share also by major business. Starting with PSE&G, which reported first quarter net income and non-GAAP operating earnings of $546 million for 2025 compared to $488 million in 2024.

Utilities results were driven by the implementation of new electric and gas base distribution rates that went into effect October 15, 2024, and as Ralph mentioned, the recovery of previous capital investments totaling more than $3 billion. Starting with the waterfall on Slide 9, compared to the first quarter of 2024 transmission margin was $0.01 per share lower due to the timing of expense recovery. First quarter distribution margin increased by $0.20 per share compared to the year ago period and largely reflects the impact of the rate case, recovering a return on and of our capital investments, and in particular, gas revenues, as approximately half of our annual gas revenues are realized in the first quarter. The margin also benefited from recovery of energy efficiency investments.

Distribution, O&M expense was $0.05 per share unfavorable compared to the first quarter of 2024 with the year-over-year increase driven primarily by timing, as well as higher distribution operational costs due to inflation and the cold weather in January and February. Depreciation and interest expense rose by $0.01 per share and $0.02 per share, respectively compared to the first quarter of 2024, reflecting growth in investment and higher interest expense. Weather during the first quarter, as measured by heating degree days, was 4% warmer than normal, but 13% colder than the first quarter of 2024. As a reminder, weather variations have a minimal impact on PSE&G’s utility margin because of the Conservation Incentive Program or CIP mechanism.

This decoupling mechanism limits the impact of weather and other sales variances positive or negative on electric and gas margins, while helping PSE&G promote the widespread adoption of energy conservation including energy efficiency and solar programs. Under the set, the number of electric and gas customers is what drives margin, and each segment grew by approximately 1% over the past year. On capital spending, as Ralph mentioned, PSE&G invested approximately $800 million during the first quarter, and we remain on track to execute on our 2025 regulated capital investment plan of $3.8 billion, focused on infrastructure modernization, energy efficiency and meeting growing demand. We’ve maintained our five-year regulated capital investment plan of $21 billion to $24 billion through 2029, representing a $3 billion increase from our previous plan, driven by reliability and resiliency investments, our expanded energy efficiency program and demand growth.

As mentioned, we commenced this next phase of our energy efficiency program in the first quarter, and we anticipate investing a total of $2.9 billion over a six-year period. The energy efficiency program totals include approximately $1 billion of unbilled repayment options to help customers finance their energy efficiency equipment and appliances. Moving to Power & Other, for the first quarter of 2025 Power & Other reported net income of $43 million compared with $44 million in the first quarter of 2024. Non-GAAP operating earnings were $172 million in the first quarter compared to $169 million in the first quarter of 2024. Returning to the waterfall on Slide 9, for the first quarter of 2025, net energy margin rose by $0.02 per share driven by higher nuclear generation performance, coupled with higher realized prices due to the cold weather mentioned earlier.

The weather conditions also contributed to a higher margin in our gas operations for the quarter. O&M increased by $0.03 per share compared to the first quarter of 2024, mostly driven by higher nuclear costs and interest expense rose by $0.02 per share, reflecting incremental debt or higher interest rates. Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to 0 over a full year and other items equally combined to have a net favorable impact of $0.04 per share in the quarter compared to 2024. Touching on some recent financing activity. As of the end of March, PCG had total available liquidity of $4.6 billion including approximately $900 million of cash on hand. While PCG had significant available liquidity in the year-end 2024 at $2.6 billion, this represents a significant improvement as we access the bond markets at both PSE&G and PSEG during the first quarter.

In total, this quarter, we issued $1.9 billion of long-term debt, which reduced commercial paper outstanding and increased cash on hand. Our liquidity position was further enhanced during the first quarter by extending the expiration of our existing $3.75 billion revolving credit facilities by one year to March of 2029. PCG’s variable rate debt at the end of March was at PSEG Power consisting of a $1.25 billion term loan, which matures this coming June, and a 364-day term loan for $400 million, which matures in December of 2025. As of March 31, we continue to have a low level of variable rate debt, representing approximately 7% of our total debt. On the financing front, in early March, PSE&G issued a total of $900 million of secured medium-term notes, consisting of $400 million of 5.05% medium-term notes due March 2035 and $500 million of 5.5% medium-term notes due March of 2055.

A portion of the proceeds will be used to repay $350 million of 3% medium-term notes due May 15. Later in March, PSEG issued $1 billion of senior notes consisting of $600 million of 4.9% notes due March 2030 and $400 million of 5.4% notes due March 2035. The portion of these proceeds will be used to repay $550 million of 0.8% senior notes due August 15. Looking ahead, our solid balance sheet supports the execution of PSEG’s five-year capital spending plan dominated by regulated CapEx without the need to sell new equity or assets and provide the opportunity for consistent and sustainable dividend growth. In closing, we delivered a solid operating and financial performance to begin the year, and we are on track to deliver PSEG’s full year 2025 non-GAAP operating earnings guidance of $3.94 to $4.06 per share, and we are also reaffirming our long-term forecast of 5% to 7% compounded annual growth for non-GAAP operating earnings through 2029, based upon the execution of our capital investment programs and the use of the nuclear PTC threshold as our reference price.

That concludes our formal remarks. And operator, we are ready to begin the question-and-answer session.

Operator: Thank you. Ladies and gentlemen, we’ll now begin the question-and-answer session for members of the financial community. [Operator Instructions] Our first question comes from the line of Shar Pourreza with Guggenheim Partners. Please proceed with your question.

Unidentified Analyst: Hi, good morning, team. It’s actually Constantine here for Shar. Thanks for taking the questions.

Ralph LaRossa: Hey, Constantine.

Dan Cregg: Hey, Constantine.

Unidentified Analyst: Good morning. Maybe just starting off on the 6,400 megawatts of large load interconnection that you’ve noted in the prepared remarks. Do you see a time line starting to form on the potential load inflection and how is New Jersey thinking about resource adequacy with that load potential? You mentioned the legislative potential but do you envision a potential shift on gas generation policy or anything else?

Ralph LaRossa: Yes. You broke up a little bit at the end there, Constantine, but I think what I heard was when do we see that load coming in at 6,400 and also the how resource adequacy is being thought about in New Jersey as a result of that. Is that…

Unidentified Analyst: Right.

Ralph LaRossa: Good, some, yes, okay. Great. So look, we have always said, take that 6,400 and you apply a factor 10%, 20%, and we’ll leave that to you all the to think what the right amount is, again, remembering for us from an earnings standpoint, we’re decoupled. So the way we think about it is more from a – this good news for customers if we can spread any costs across additional megawatt hours, and that, that would certainly be a positive from a customer standpoint. For the timing of it, I think it’s happening at different stages. We are seeing some interconnections take place already. Obviously, the ones that are a little bit larger in a couple of hundred megawatt requests we have they still seem to be some folks that have been shopping for the best location for their particular application that they might have.

But we just see that the state’s economic development plan is taking hold and happy to see the amount of additional megawatt of requests that we’ve had come in. As it relates to resource adequacy, look, that’s a big conversation that’s taking place across the entire RTO footprint right now. And we just saw some new planning numbers come out from PJM that we have some questions about. There’s an upcoming TAC meeting. We’re going to be asking some questions at that TAC meeting regarding some of the assumptions that are in there. And the one thing that we heard from our legislators over the last week or two was to be more vocal about that, and you can certainly expect us to be more vocal with our questions as we move forward.

Dan Cregg: Daniel here, so your other part of your question, Constantine is proposed legislation in New Jersey. We had some hearings last week. There’s discussion of it. So I would say right now, it’s at the discussion point as opposed to certainly being active, but we are here and remain available as a resource to the state if they decide to take resource adequacy into their own hands through some legislation.

Unidentified Analyst: Understood. Appreciate that. And on the FERC 206 with the comments that were filed last week? And do you have a view on settlement process versus outright order? Any preferred route from your perspective? And has that FERC process come up in your commercial discussions at all in artificial around? And would you be able to kind of mitigate any of that for any kind of continued provisions? Or are we kind of walking step by step there?

Ralph LaRossa: Yes. So I’ll let Dan – I think you asked a little bit about specific conversations, so I’ve always given that to Dan, and I’ll do that again as that is being led by his team. But generically, as it relates to the proceeding down a FERC, we would always like to see a settlement, right? I mean, that, that, to me, is always the best solution I would love to see the industry come together and find solutions to help the tech industry out. It’s pretty clear based upon some information I continue to see tech needs for generation continue to grow. And we, as an industry, need to find a common solution to meet that, I certainly think that in doing that, we need to make sure that we’re not discriminatory in one customer class versus the other and has been the single concern that we’ve had since this process started. But Dan, do you want to talk a little bit about?

Dan Cregg: Yes. No, I agree with Ralph. And that’s – I think the non-discriminatory aspect is really important. I think I’ll just leave the commercial aspect to just a single comment that I think that the counterparties are looking for the flexibility, the most flexibility that they can have right now, there’s some uncertainty related to how much they will have. And so they’re waiting on this answer, whether settlement can get us the best answer, which it seems like it’s going to be more representative of what the parties are looking for. I think that, that would be ideal but they’re never easy to get. So time will tell whether we can. We’ll have one of those.

Unidentified Analyst: Excellent. Appreciate that. That’s for taking the questions.

Ralph LaRossa: Thanks, Constantine.

Operator: Thank you. Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Ralph LaRossa: Hey, Durgesh.

Durgesh Chopra: Ralph, good morning. Thank you for taking my question. Good morning, Dan. Hey, just on the commercial arrangements related to nuclear. Just I understand there’s a lot of moving pieces and the time line is uncertain. But just from a demand perspective and the tone from your large load customer perspective, has that changed over the last few months, maybe since February when we spoke last time earnings, has that changed? Obviously, there’s a lot of news in the market, there’s tariffs. We’ve seen Microsoft, Amazon, some of the other hyperscalers sort of pull off of some of the contracts, just seeing if you’re seeing any softness there?

Dan Cregg: No, I would definitely would not call it softness. I think there’s still a demand for power, and I think there’s still a demand for that type of power. I think there’s also a desire to have answers to some of the questions that remain outstanding, but I would say, there continues to be interest in the nature of the power and the scarcity of the power that nuclear provides.

Ralph LaRossa: And Durgesh, overall, that’s why we included those numbers that we did in the new business activity that we’re seeing. It has not slowed down. And again, maybe it’s the same person calling 50 locations and ask for the same question. But I don’t see that as the case. These are unique at least for us, they’re unique requests that are coming in and I continue to be surprised and impressed by the amount that we’re seeing.

Dan Cregg: 10,000 megawatt peak, Durgesh. So 6,400 is not all coming in. I mean Ralph talked about some lower percentage of that, but the requests do continue, so.

Durgesh Chopra: Got it. That’s very helpful color. Just switching gears quickly on LIPA, just what to expect there? I believe there are some meetings here at end of May. Do you expect a decision then? Or what are kind of the data points or dates we need to track throughout the year? Is this – as they make the decision on whether you’re going to provide services there or not?

Ralph LaRossa: So Durgesh, I got to take a half a step back for you. I don’t know if you’re aware of the meeting that just took place at LIPA on this subject. Are you up to speed on that?

Durgesh Chopra: The one – the first – I think there’s a – what I’m up to speed on is there was a first – I guess, you weren’t awarded the first portion of the contract and then there is the bigger contract that still…

Ralph LaRossa: Yes. No, there was actually – so over the last 24 hours, there’s been a lot of activity on this front. So let me just try to summarize for everybody on the call, what’s taking place. There was a recommendation made by LIPA management to select a different service provider. That recommendation was just voted down by the Board. That took place within the last half hour or maybe within the last hour is a better way to say that after we started this call. So we are just – we’re happy to see that we’re still in consideration, but I don’t know anything more than that and all I can promise to anyone who’s on the call, who’s on Long Island or any customers on Long Island, we will continue to do the right thing and provide high-quality service to the customers on Long Island as long as we can.

So there was a flurry of activity over the last 24 hours and that culminated in – within the last hour, I said, with a novo from LIPA Board on the management recommendation to select a different service provider.

Durgesh Chopra: Got it. Sorry, I missed that. So what – do we know what the next step is here? Do they go back to the drawing board or what…

Ralph LaRossa: It gets right back to what you said on May 22, there is going to be a next Board meeting, and I expect that they’ll hear some next steps. They went into executive session after the public session. So I would imagine that, that among other things are being addressed, so.

Durgesh Chopra: Perfect. Okay. I’ll leave it there. Get back into queue. Thanks so much.

Ralph LaRossa: All right. Thank you, Durgesh.

Operator: Thank you. Our next question comes from the line of David Arcaro with Morgan Stanley. Please proceed with your question.

David Arcaro: Hey, good morning. Thanks so much.

Ralph LaRossa: Hey, David.

David Arcaro: Maybe on New Jersey and affordability. I was just curious if you could elaborate on your strategy or approach to managing affordability just given some of the concerns I think stemming from PJM capacity pricing, but what are approaches that you could take to manage some of the concerns that have popped up from both the governor and the commission?

Ralph LaRossa: Yes. No, I appreciate that question. Certainly has been a hot topic here. We look, our concern is trying to reach some consensus that helps customers over this peak that came in. We are listening to recommendations that come from the Board of Public Utilities. They have a couple of ideas about how they can help mitigate through some deferral of charges to customers that are – is under consideration from all the electric distribution companies here in New Jersey. We would certainly be supportive of anything that comes out from the Board. There are legislators that have proposed a number of different bills, I think the most significant one would be one that would be addressing the core problem here, which is supply.

And another way to procure supply in the state, some of them in DAngelo put a bill in to look to bring generation into the state and to open it back up to regulate utilities to have that opportunity. Again, Dan mentioned it a little bit in the beginning, we would certainly be willing to participate in that and help find solutions for the state. We think we have some unique sites that could be helpful in meeting that the ones that have pipes and wires already to it. And obviously, we’d have to take some different actions on the site to generate there. But we’re listening to everyone. It’s an issue that it’s going to face customers. And as I mentioned in the prepared remarks, it’s going to hit every customer in we want to help our customers as best as we can through this time.

It’s one piece of the affordability challenges that they’re facing.

Dan Cregg: Yes. And the other things that are going on in the background, David, there’s a lot of customer assistance like lip, and we’re making sure that customers are aware of the programs that are out there to help those in need that probably will be get toughest from the standpoint of some of these increases. So one of activity at the company and a lot of activity outside the company, all addressing this particular issue.

Ralph LaRossa: And not to mention, the timing of our rollout of the energy efficiency program, which, again, I mentioned in the prepared remarks is very helpful on that front as well because if we can help customers use less as I said, to an earlier question from – as we’re decoupled, we can help the customer and be supportive without any financial impact to us as a result. .

David Arcaro: Yes. Excellent. Okay. That’s helpful. Thanks. And then on – I guess, on your efforts contract nuclear capacity with data centers. I was just curious where do things now stand – like are you discussions and negotiations contingent on the FERC process and figuring out behind-the-meter co-location arrangements and frameworks or such that, that time frame is going to be important and then may be critical to getting over the finish line here? Or are there other approaches that may not kind of have to wait for the full FERC process and potential settlement to play out?

Ralph LaRossa: Yes. No, I’m going to give that to Dan to give you any details he wants. I think you addressed a bunch of what you said for. But look, we think the FERC process is helpful to show that the industry as a whole is meeting the need. And again, I would encourage us to reach a settlement on that front so that we can show solidarity in meeting the customers’ needs here and that customer being the technology company that are so thirsty for generation. But Dan, do you want to add anything specific?

Dan Cregg: The simple answer is no. It is not contingent upon that. I think it’s helpful to have that move forward, but the simple answer is no.

David Arcaro: Okay, got it. Thanks so much. I’ll leave it there.

Ralph LaRossa: Thanks, David.

Operator: Our next question comes from the line of Nick Campanella with Barclays. Please proceed with your question.

Ralph LaRossa: Good morning, Nick.

Nick Campanella: Hey, good morning. Thanks for that real-time update on LIPA. That was impressive. Hey, I just wanted to follow-up on the prior line of questioning, just in regards to the commercial agreement and we kind of talked about this prior just being maybe a more realistic opportunity for 2025. And just given everything that’s transpired, can you – I just want to be clear, like, do you still see executing on nuclear deal in 2025 as still on the table before the governor leaves office in your mind?

Dan Cregg: Yes. No change, Nick. We are still what we’ve been saying with respect to how we are progressing and what we’re doing is still where we are today.

Ralph LaRossa: Yes. I don’t have a real-time update for you other than tell you the following from the governor standpoint. These are another economic development mission in the Middle East and is talking about continued attraction of technology jobs to the state. So I’ll get an update on that as that progresses and there are some news reports about what he’s doing, but he is – he’s working until his last day here, and one of the topics is to continue to attract technology companies.

Nick Campanella: Okay. That’s helpful. And then just maybe remind us on like the quantum of megawatt it could potentially be part of a commercial agreement? Would you be open to doing more than a third of it at this point? Just trying to take your temperature on up.

Dan Cregg: Yes, there’s not a target number, but I would say that there’s no restriction on anything that we have within the portfolio to the extent that there is interest related to some kind of a commercial agreement.

Nick Campanella: All right, thanks. See you at AGA.

Ralph LaRossa: See you then, Nick.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.

Ralph LaRossa: Hey, Jeremy.

Jeremy Tonet: Hi, good morning. Just maybe building a little bit on prior comments here and appreciating PJM’s collar for the next capacity auctions. How do you think about the potential capacity price outcome in the next auction as it relates to customer bill growth at this point? And do you see the price floor carries enough substance to incent ongoing investments in capacity supply? Just any other thoughts on the market there?

Ralph LaRossa: Well, look, I’ll – we’ll take this one again. I would say a couple of things turn around and make the comment. I’ve seen a bunch of reports that would indicate that the price that we could expect would be on the northern side of that collar from a range standpoint, somewhere between the midpoint and the top, I think, is what we continue to see in the consensus of documents that I’ve read. We have an internal opinion. We really don’t talk about that. But I would say, I turn it back around and mention what I’ve read from others. The good news from that standpoint for our customers, if there is good news in this, is that the – because we have rolled in three years’ worth of capacity increases because we had that proxy price in the BGS auction before, we would not expect to see a large increase for customers in the forward years as a result.

So that’s a positive. What’s a negative is the prices are not coming down if that – if those projections are right, that would kind of keep it in that same range, some percentage up or down. But that not the double-digit increases that we’ve all seen here in New Jersey. And again, that was a combination of delays at PJM and the capacity market as well as a lack of generation, which gets to your second question, which is do we think that those prices – and Jeremy, I’d be way in front of my skis on that since we’re not in the merchant generation business at the moment here and don’t expect to be ever again in the merchant generation business, we have not done a lot of homework on costs and how that would wind up playing out and with tariff increases and so on.

So look, if we have an opportunity to do something in rate base, be able to answer that question in a lot more detail. But Dan, do you want to add anything?

Dan Cregg: No, I’ll just add two things. On your last point, the concept of bullet prompt incremental generation, honestly, it’s less about the price and more about the duration and the time frame that you’re talking about. So given the periods that the auction covers and given the time frame that it takes to build something new, the price that they’re putting out is not something that you’re going to get if it prompts you to build a new unit. So I think the timing continues to be the challenge at PJM and then just kind of maybe piling out what Ralph talked about before with respect to the overall pricing and customer bill. The BPU set up a good process so that you could gradually see changes over time. That good process was – it kind of lost some of its benefits by virtue of PJM’s delays in the capacity auction.

So that proxy price amplified the effect of a price move because there was a catch-up. We’re still not caught up with respect to timing of capacity auctions and so that proxy price, which was in the last go around the previous auction as we move forward is currently the previous auction. So that proxy price is the $2.70 price we saw last time. And so Ralph says we don’t expect to see a big move by virtue of whatever happens within this auction, it’s because we’re sitting at that higher proxy price. So there could be smaller moves, but nothing in the magnitude of what we’ve seen. And the collar surrounds that $2.70. So as Ralph said, probably leaves you closer to where we are now, but without another jump like we are addressing right now within the state.

Jeremy Tonet: Got it. That’s helpful context there. Thank you for that. And maybe pivoting to offshore wind and fully appreciating that PEG has exited offshore wind. But maybe just any thoughts as far as recent frictions offshore wind that we’re seeing today? And how you think that impacts maybe the transmission planning opportunity set? Are there any knock-on effects to you guys that we should think about?

Ralph LaRossa: Well, no knock-on effects for us to the East of New Jersey because we didn’t have anything in the plan as we’ve spoken about quite a bit, maybe opportunities now to the West, depending upon how we solve for the resource adequacy concerns and the capacity. I think – look, we – again, I’m going to be a little bit repetitive here. We have to be very loud about any concerns that we have regarding that process and the parameters that exist because five years from now, we’ll be dealing with the results of it. So it’s pretty clear to us to help customers we need to either build more wires or build some generation in the state, and it’s important to have the accurate parameters built into the PJM process now so that we get it right in the out years.

Jeremy Tonet: Got it. That’s helpful. I’ll leave it there. Thank you.

Ralph LaRossa: Thanks, Jeremy.

Operator: Thank you. Our next question comes from the line of Julien Dumoulin-Smith with Jefferies. Please proceed with your question.

Julien Dumoulin-Smith: Hey, good morning team. Good to chat with you guys again.

Ralph LaRossa: Hello, Julien.

Julien Dumoulin-Smith: Hey, pleasure. Hey, so just a following up on this affordability there. I’d love to hear a little bit more specifically. I know you guys alluded to kind of guiding customers with what’s out there. But I just want to make sure I’m hearing from you guys right, especially as you think about proposals and trying to swage concerns out there. I mean, what would you say specifically, you all bring to the table or would potentially bring to the table in a long-term and short-term sense here? I mean I just wonder in the scope of how far this affordability narrative is going in the state and what you’re hearing from the stakeholders, whether it’s the governor with BPU on this?

Ralph LaRossa: Yes. Look, again, this is – I think what we’re here, Julien, is what the whole country is here and affordability is a concern and it goes from eggs to energy. So from our standpoint, we want to do our part and the conversation here in New Jersey was magnified quite a bit by everything we just talked about with the inadequacy of the PJM capacity market process being delayed as long as it was. And having this compounding effect. So we can’t change that. That’s a governance issue that PJM needs to deal with, and they’ll do what they need to do. But what we can do is what we’ve been trying to do at PJM, which is advocate for some stability, so we don’t have this happen again. That’s a long-term solution because the long-term solution is to get more generation, more supply that could show up as new generation in the state.

We’ve talked a lot about the fact that we’ve been more than willing to do it in rate base. If we can play a role there, it would be helpful, we will certainly do that or it could show up by new wires being built and bringing in generation from another location. What I hear from policymakers in the state is that they would like to have more control over their destiny and that would lead me to believe that we would want to have more generation in the state. But those conversations are ongoing, and you’ve seen some of that in the press. What we can do in the short term is three things, right? We can help from an affordability standpoint, providing customers with access to some of these programs that are out there, systems programs. We can help with energy efficiency, just continue to help people use less, and we’ve talked about that quite a bit over the years.

And the new thing that was an idea that was put forth by the BPU was to try to get more people on a plan that would levelize the cost over a 12-month period. We have a program called the equal payment plan. This would be a little bit different than that. But not very different as I currently read it, and would be more of a short-term solution so that customers are still incented to use less electricity in the long-term and that count on an equal payment plan. So that’s a policy decision that will be continue to be discussed with the Board. But we have said, and we want to be part of the solution, and we’ve always been that way in the state. I don’t see that being any different. So whether it’s the long-term, the rules, the supply or the short-term where we’re trying to help customers out, and in the three ways that we mentioned, we’re going to be here as best we can.

Dan Cregg: Yes. On that short-term item too, kind of an obvious statement, Julien, but our energy year starts June 1. So you’ll see volume increases at the same time, you’re starting to see that price increase. And so part of that design and part of that thinking is take this thing out of the summer months.

Julien Dumoulin-Smith: Yes, absolutely. And guys, just to clarify here real quickly on LIPA, you guys have commented that you see offsetting potentially this headwind to the extent to which you may or may not get it. Would that be effective here as soon as the start of next year as far as your ability to offset the full ramp, right, the $0.06 to $0.08 ballpark that we’re talking about here?

Ralph LaRossa: Yes. Well, it’s not that high. I think we’ve been saying $0.05 to $0.06, but I won’t get into back and forth on that. I think that – look, first of all, it’s immediate, we would have to manage costs and any other costs were associated with LIPA we would have to remove those costs, and there’s multiple ways to do that. And then on the revenue side, we’re always looking for other opportunities. And we always have oars in the water on that front, and I would hope that we could bring one or two of those opportunities we’re looking at to fruition in a timely enough fashion to offset it. So that’s the goal here. And that’s why we’re confident that we’d be able to offset it and remain with our earnings projections that we’ve put out there to $0.05 to $0.07.

Julien Dumoulin-Smith: Got it. All right. Excellent guys. Thank you so much. Appreciate it.

Ralph LaRossa: Thanks, Julien.

Operator: Thank you. Our next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question.

Carly Davenport: Hey, good morning. Thanks for taking the questions. Maybe just a follow-up on the large load pipeline comments from earlier. Any indications you can share on the breakdown of that 6,400 megawatts in terms of what are more geared towards initial applications versus those that are more mature in the process?

Dan Cregg: Yes. Carly, it continues to morph as you go through time, right? You’ll have some drop off, you’ll have some come on in, but we’ve generally characterized the number as trying to do two things. The first thing we’re trying to do is give an indication of total interest that has come forward, while at the same time, also trying to bring some reality to it because we’ve said as a 10,000 megawatt peaking system, we don’t expect 6,400 megawatts to come on. And so Ralph mentioned earlier, 10% to 20%, I think we continue to try to do some guest work. Obviously, you don’t know when someone starts to initiate an interest exactly where they’re going to go. But as time goes on, their continued interest, how far they go in the process, how often they communicate and what they’re doing, gives us some sign that we can get some kind of a gauge as to which are going to be more likely and which are not.

And so I don’t know if you’re in that 10% to 20%, 25%, somewhere within there, I think is a reasonable expectation as to what’s going to come forward. And that’s also used for planning purposes. We don’t plan our system around 6,400 megawatts coming on to the system. We plan for a subset of that based upon that experience. And so it’s probably in that ballpark. It’s an imperfect estimate, but it is an estimate.

Carly Davenport: Got it. Okay. Very clear. That’s helpful. Thank you. And then maybe just as you think about the current five-year capital plan, any color you can provide in terms of where you see potential exposure on the tariff front? And any risk mitigation tactics that you see as necessary there?

Ralph LaRossa: Carly, I don’t want to completely dismiss it because what we don’t know, we don’t know. But I am very comfortable that we do not have any real problems around the quarter because of the type of work that we are planning over the near-term, right? It’s kind of the very straightforward replacement activities that we have in that last mile. We are not planning on large transmission projects in this cycle. We’re not planning on that. We have a little bit of substation and switching station work to do, but no major efforts like we had after Superstorm Sandy. So since the major work is behind us, large project risk is behind us. And we’re really focused on this last mile activity. And the only project that we have of any magnitude is the Maryland project. And I have had no indications yet that we have any supply chain concerns on that front.

Carly Davenport: Great. Thank you so much.

Ralph LaRossa: Thanks, Carly.

Operator: Thank you. Our next question comes from the line of Michael Sullivan with Wolfe Research. Please proceed with your question.

Ralph LaRossa: Hey, Michael.

Michael Sullivan: Hey, Ralph. I know you kind of just hit this in one of the recent questions just in terms of short-term and long-term solutions. But do you think the short-term solutions are sufficient enough to kind of tamp down some of the political rhetoric here just given like the long-term solution, how long-term are we talking? Like if you were able to bring regulated generation online, how long would that take?

Ralph LaRossa: Yes, Michael, I don’t want to front run something that isn’t there yet. So it will be hard for us to say that. I would simply be thinking about that this way. We’re seeing five to six-year lead times on some of the turbines and you could call that four, you could call it eight, depending upon who you talk to, but I’ll say, five to six on that front. So what we need is we need the decisions made. You know by law we cannot move into this area right now because of [indiscernible] and if the law has changed in the state of New Jersey, we will be there for the customers and for the policymakers. So it’s a little bit of the chicken in the egg, when does the law get changed and then when do we actually get the place orders to try to find some solutions?

That’s – so to give you a time line when we could actually have additional supply on the system would be, I think, disingenuous on my part to do that. So I think what we’re doing in the near-term is the best we can do with the cards that were dealt. And I say we, as the state of New Jersey. We’re all working together on this, the policymakers and the companies.

Michael Sullivan: Okay. Understood. And just kind of tied to that, just wanted to get your thoughts on the governor’s challenge of the previous PJM auction results and how that factors into the dynamics?

Ralph LaRossa: Yes. Look, I think policy makers are rightfully concerned about the spike that they saw. And so I think you’re seeing questions get asked in a number of different ways by a number of different policy leaders. We’ve had some assembly leaders, some tenant leaders here in the state, asking those questions, either in public hearings or by sending letters as well. So it’s not a surprise. This is something you would expect leadership to do is to ask some questions when you have something like this take place? And what took place here as I think we’ve said multiple times is we’ve had this governance challenge that has caused the three year – all three of these auctions to pile up on top of each other. And as a result, the customers are seeing the spike.

Dan Cregg: Yes. I mean they’re going to – Michael, they’re going to do their investigation. They’re going to find out what they find out. We’re not aware of anything that’s problematic, but there’s nothing wrong with that check going on just to validate what has happened.

Michael Sullivan: Okay. And just last one, just back to the long-term solutions, is regulated generation in New Jersey the only solution that’s being considered? Or are there any other bills that we should be watching?

Ralph LaRossa: No, no, no. I think – look, I think there’s three solutions, right, we’ve talked about. And I say generation without picking a source or a technology. You could – the first is you could have rate base, which I mentioned. The second is you could have – you could somehow incent a competitive generator to site here. And the third is you can import. I mean that is the simple way we think about it. And the imports we’re going to probably need some bigger wires or more wires if we go that route. Again, we be in the state. If we come up with a solution for competitive generator, we will be there from an interconnection standpoint. We’ve been very vocal about the fact that we’ve been very responsive to those types of requests as they come in regardless of the technology.

And if it becomes a regulated solution, we think we have a couple of sites that might make some sense for us. So we just look forward to the continuing conversation and try to push it so we can avoid this can get kicked too far.

Michael Sullivan: Very helpful. Thank you.

Ralph LaRossa: Thanks.

Operator: Thank you. Our next question comes from the line of Bill Appicelli with UBS. Please proceed with your question.

Bill Appicelli: Hi, guys. Just one quick question here. Just going back to something Dan said earlier about the commercial opportunities and flexibility being key. I mean, just maybe a little bit more color around what that means. Is that flexibility around being on grid or the timeline of how quickly things can ramp? I mean what exactly is sort of the flexibility aspect they’re looking for?

Ralph LaRossa: Well, this is a follow-on something Dan said, I’ll let Dan answer it.

Dan Cregg: Yes. Look, just think about trying to strike a commercial deal when there is uncertainty around rules that are going to be met urgently, and that work continues to go on and on and on. And so I think, really, just trying to get in line how this is going to work and how it can work and what the optionality is with respect to how you would interconnect. It’s nothing more complicated than that. And we’ve said before given where we are and given the transmission rates where we are, it is not as critical as it is in some other areas. But I think all parties would prefer a situation where they have all the rules and they know exactly what they’re dealing with. And I think it’s just – it’s taken us a long time as an industry and as the regulators within the industry to come to that final answer.

Now we had a question before about the settlement. And I think that would be a great answer because it will be the participants that are actually devising where things are going to go that would ultimately get approved. But that doesn’t happen overnight either. And so I think there is as a general desire to move more quickly and get this done, but it’s lingered for a while. So that’s really all it is, Bill, it’s trying to solidify exactly what the landscape is that we’re working at.

Ralph LaRossa: Yes. And Bill, I would just add, look, if you think about where we have our generation right now, we can satisfy a bunch of things, whether it’s redundancy, accessibility, extra capacity, location and I could go on and on. So we still feel very, very good about the opportunity set that’s in front of us.

Bill Appicelli: Okay. And then just lastly on, what are you guys seeing on the adoption for demand response, right? That’s obviously been something that’s gotten more attention here as the price signal is going up. Is that something you’re seeing an increasing level of interest in from your customers?

Ralph LaRossa: Yes. I think you see it in a couple of different ways, right? But we don’t have as much as you might hear from other companies because of the low industrial load that we have. From a residential standpoint, we do see it. We see it show up from mostly, in that case, from a thermostat standpoint and from some pools that are not running and so on at certain times. And that has continued. And our energy efficiency programs that we talk about all the time address exactly that issue for mostly – again, mostly the residential customers.

Bill Appicelli: Okay. All right. Great. Thanks very much.

Ralph LaRossa: Thanks, Bill.

Operator: Thank you. And there are no further questions at this time. I would like to turn the floor back to Mr. LaRossa for closing comments.

Ralph LaRossa: Well, thank you so much. Listen, I think the conversation has rightfully been a lot today around affordability and what customers are facing. And again, we are in that depth of that issue. We know what’s going on around kitchen tables, and that’s because of the 13,000 employees that we have here who are not only doing the job that they do day in and day out but are those people that are having those same conversations around the table regardless of the cause of the affordability challenges they might be having. So we’re very well aware of that. We’re going to be here to be a solution provider to the state, and we hope to continue to be a solution provider to the people of Long Island as well as we’ve discussed. So we appreciate all of your interest, and we will see you at AGA in May. Thanks for calling in.

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