Public Service Enterprise Group Incorporated ($PEG)

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 2026 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, May 5, 2026, 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. .

Good morning, and welcome to PSEG's First Quarter 2026 earnings presentation. On today's call are Ralph LaRossa, Chair President and CEO; and Dan Craigg, 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.

Thank you, Carlotta, and thank you for joining us to review PSEG's first quarter 2026 results. Starting with our financial results. PSEG reported net income of $1.48 per share and non-GAAP operating earnings of $1.55 per share. Our first quarter results reflect continued investment in utility infrastructure focused on reliability and cost savings energy efficiency programs at PSE&G. And at PSEG Power, higher gas volume and capacity revenues have more than offset the absence of the zero emission certificate program that concluded last May. With this solid start to 2026, we are maintaining our full year non-GAAP operating earnings guidance in the range of $4.28 to $4.40 per share. On the operations front, I'm very pleased to report that our utility and nuclear operations delivered excellent reliability during one of the harshest winters in decades. In preparation for these extreme weather events that included high snow accumulation, ice and Arctic air temperatures, PSE&G initiated its winter weather readiness procedures and ensured adequate staffing for timely storm response. Starting in January with Winter Storm Fern through winter storm Hernando in late February that dropped 30 inches of snow on parts of Northern New Jersey, PSE&G systems held up well during intense conditions. With a relatively small group of customers that were affected by the weather, PSE&G was able to restore service to virtually all customers within 24 hours. I can't say enough about our employees who carry out PSEG's storm response work and have braved the elements to keep the lights on and homes warm for our customers. Utility experienced peak winter gas [ send out ] on February 7, following over a week of subfreezing temperatures. These conditions underscore the need for continued investment in gas infrastructure monetization to address the impact that extreme temperatures have on our aging cast iron gas system. Despite the year's winter weather, PSE&G is on track with 2026 capital spending plan of approximately $4.2 billion, investing in critical energy infrastructure, cost saving energy efficiency and system modernization for reliability and to meet new demands. During the same time, we have worked with the Governor's office and the New Jersey Board of Public Utilities to keep electric rates flat in 2026 in keeping with the executive orders 1 and 2 that are addressing utility costs and generation supply. PSE&G's electric customers will also benefit from the update, reflecting the latest basic generation service auction results, which will go into effect on June 1. On February 1, we also kept residential natural gas rates flat through the remainder of the 2025, 2026 winter heating season, delivering to our customers the lowest gas bills in New Jersey and in the region. And there is more good news for PSE&G electric customers. In early March, FERC issued an order supporting PSE&G and the State of New Jersey's objection to its PJM transmission cost allocations. FERC's ruling reallocating these costs is expected to result in significant refunds of over $100 million based on our estimates, the PSE&G customers after PJM's implementation. While this matter is still being litigated at FERC, it's another example of how PSEG works in partnership with the state at the regional and federal levels to keep our customer bills as low as possible. I'd also like to mention that we are ramping up PSE&G's technology-driven conservation efforts. PSE&G recently launched 2 new ways to reduce energy used during peak times to save customers money and help reduce strain on the grid. The first is our demand response program with over 32,000 residential and small business customers already enrolled to receive an upfront payment for reducing air conditioned use and other activities like EV charging during selected peak hours throughout the year. The second program, our new residential time-of-use rate that can save customers money by shifting some of their usage to off-peak time. This new rate option leverages the more detailed electric usage made available by our AMI investment in smarter meters. Combined with our energy efficiency programs, PSE&G offers customers a variety of ways to reduce energy usage, manage their bills and starting this summer, participate in creating a more flexible energy grid through our virtual power plant pilot. The BPU has started the process of implementing the directive in the first executive order to examine the regulation of the electric distribution utility business model. We expect the BPU consultant will release a study this summer and that a stakeholder process on the topic will continue throughout the remainder of the year. We intend to fully engage with the BPU throughout this process. Now turning to PSEG Power. First, I'd like to congratulate the PSEG nuclear team for completing a second consecutive breaker-to-breaker operating run at Salem Unit 2 to begin their refueling outage this April. That notable accomplishment contributed to a 95.5% capacity factor and supplied 8 terawatt hours of reliable, carbon-free baseload energy to New Jersey and the grid during the first quarter. Last week, FERC approved the extension of the PJM capacity price collar through the 2029/2030 base residual auction. This extension is expected to stabilize the effect of upcoming auctions on New Jersey's [ PGS ] default prices even as regional demand growth advances with a limited supply response. As part of an all of the above long-term approach to increasing New Jersey-based generation supply, Governor Sherrill recently signed legislation lifting a decades-long moratorium on new nuclear construction. The announcement made at our 3-unit site in Salem County highlighted broad support from policymakers, legislators and labor leaders. PSEG is engaging in efforts to advance new nuclear development at PSEG's site, and we believe the site's unique strengths, including an early site permit, prime logistics, access to a skilled workforce and opportunities to leverage our operating expertise through contractual arrangements, make it a leading candidate for new nuclear deployment. We have also been watching developments related to PJM's proposed reliability backstop procurement auction. This is intended to be a onetime procurement or emergency auction to accelerate new dispatchable generation that can be brought online by 2031 to serve data center-driven load growth. More details from PJM are expected over the next month and we will continue our vigilance during the stakeholder process to advocate on behalf of PSE&G's customers. Wrapping up, PSEG had a strong operating and financial quarter to start the year. By doing the right thing for our customers, our communities and our shareholders with an eye towards a sustainable future. Our corporate reputation for excellence beyond our well-known reliability and customer satisfaction awards was recognized again last week when PSEG was named to the Dow Jones best-in-class North America Index for the 18th year in a row. We are maintaining a broad set of financial projections that we shared with you late in February, starting with our 5-year regulated capital investment plan of $22.5 billion to $25.5 billion at PSE&G and $24 billion to $28 billion for PSEG, both through 2030. This investment program supports the utility 6% to 7.5% compound annual growth in rate base also through 2030 and helps drive a 6% to 8% non-GAAP operating earnings CAGR at PSEG over that same period. And I would highlight again that items, including nuclear revenue opportunities above current market prices, winning additional competitive transmission solicitations or making incremental system investments to connect several thousand megawatts of solar and battery storage resources to the grid to meet new demand would be incremental to our 6% to 8% non-GAAP operating earnings CAGR. I will now turn the call over to Dan, who will review this quarter's results and then rejoin the call for our Q&A session.

Great. Thank you, Ralph, and good morning, everyone. PSEG reported net income of $1.48 per share for the first quarter of 2026 compared to $1.18 per share in 2025 and non-GAAP operating earnings were $1.55 per share for the first quarter of 2026 compared to $1.43 per share in 2025. We 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 and 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 $577 million for 2026, which compares to $546 million in 2025, utilities results reflect ongoing investment in energy efficiency, gas system modernization and transmission, the seasonality of gas demand and the continued gradual increase in the number of electric and gas customers. Starting with the waterfall on Slide 9. Compared to the first quarter of 2025, transmission margin increased $0.01 per share due to higher investment. The first quarter distribution margin increased by $0.07 per share compared to the year ago period and largely reflects incremental gas margin from the third quarter 2025 GSMP II extension roll-in, an increase in the number of customers in the quarter and higher gas demand outside of the decoupling mechanism. Higher investment in energy efficiency also contributed to distribution margin in the quarter. Distribution O&M expense was $0.01 per share higher compared to the first quarter of 2025, reflecting an increase in operating costs due to inflation and extreme weather in January and February. Depreciation and interest each rose by $0.01 per share compared to the first quarter of 2025 due to capital investments and higher long-term debt interest rates. And for utility taxes and other, lower flow-through taxes had a net favorable impact of $0.01 per share in the first quarter compared to the prior year period. First quarter weather as measured by heating degree days was 5% colder than normal and 8% colder than the first quarter of 2025, but had a limited impact on utility margin. As you know, the Conservation Incentive Program or CIP mechanism, decoupled 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 programs. And under the CIP, the number of electric and gas customers drives margin and residential customer growth for both segments was about 1% over the past year. On our regulated capital spending program, PSE&G invested approximately $800 million during the first quarter, and we remain on track to execute our full year 2026 plan, of approximately $4.2 billion, focused on continued investments in infrastructure modernization, energy efficiency, electrification initiatives and load growth. We've also maintained our 5-year regulated capital investment plan of $22.5 billion to $25.5 billion through 2030. PSE&G began the next phase of the GSMP III program in the first quarter, and we anticipate investing a total of $1.4 billion over the 3-year period. The GSMP III program total includes approximately $1 billion and accelerated recovery of [ $360 ] million in stipulated base. Also in the first quarter, the BPU certified the results of the annual New Jersey Basic Generation Service or BGS auction that was held to secure electricity for customers that have not selected a third-party supplier. These auction results will have the effect of lowering the cost of electricity supply by 1.8% on PSE&G residential electric bills for energy capacity, starting June 1 of this year. Moving to PSEG Power and Other. For the first quarter of 2026, we reported net income of $164 million compared to $43 million in the first quarter of 2025, while non-GAAP operating earnings were $201 million for the first quarter compared to $172 million for the first quarter of 2025. Referring again to the waterfall on Slide 9. The first quarter 2026 net energy margin was flat compared to the year earlier quarter as higher gas operations and capacity prices were offset by the absence of zero emission certificates, lower generation volume and the absence of fuel and energy management fees under the renewed LIPA contract, which commenced in January of 2026. The O&M costs declined in the quarter, providing a $0.06 per share benefit compared to the same period in 2025, primarily reflecting a net reduction in operational expenses and an adjustment to tax resource. The impact of higher interest costs and lower depreciation expense netted to a drag of $0.01 per share in the first quarter, reflecting incremental debt at higher interest rates, partly offset by lower depreciation expense, reflecting our expectation that the NRC will approve a 20-year license extension for the New Jersey nuclear units. And lastly, taxes and other items had a net favorable impact of $0.01 per share in the quarter compared to 2025. Touching on some recent financing activity. PSEG had ample liquidity totaling $3.9 billion at the end of March. This includes approximately $400 million of cash on hand, primarily related to net PSE&G financing activity during the quarter. PSEG entered into a $500 million 364-day variable rate term loan in February, further supporting our liquidity position. And also during the quarter, all of our revolving credit facilities totaling $3.75 billion were extended by 2 years through March of 2031. On the financing front this past January, PSE&G issued $1 billion of secured medium-term notes, or MTNs, consisting of $500 million of 4.2% MTNs due 2031 and $500 million of 5.63% MTNs due 2056. A portion of these proceeds were used to repay $450 million of MTNs at just under 1% that matured in March 2026. PSEG also has limited exposure to variable rate debt, which totaled approximately [ $915 million ] and consists of 2 364-day term loans and commercial paper and represented a low 4% of our total debt at the end of March. Looking ahead, our solid balance sheet continues to support the execution of PSEG's 5-year capital spending plan directed mostly to regulated CapEx without the need to issue new equity or sell assets and provides for the opportunity for consistent and sustainable dividend growth. As demonstrated by the 2026 indicative annual rate of $2.68 per share established by our Board in February. This new dividend rate represents an annualized increase of approximately 6% for 2026 and marks our 15th consecutive annual increase. In closing, we delivered solid operating and financial performance to begin the year and are maintaining PSEG's full year 2026 non-GAAP operating earnings guidance of $4.28 to $4.40 per share. We are also reaffirming our 6% to 8% compounded annual growth rate for non-GAAP operating earnings through 2030 based on the continued execution of our strategic plan. That concludes our formal remarks, and we are ready to begin the question-and-answer session.

[Operator Instructions] And the first question comes from the line of Shar Purreza with Wells Fargo.

it's Konstantin here for Shar.

That's why I paused a little bit there, Konstantin. I wasn't sure [indiscernible]. So I didn't want to say hello to Sharr first.

Just maybe a quick one, starting on the BPU and the legislative process on utility constructs. Are the different branches finding their footing in terms of priorities? Is there anything in the cost of service model, getting attention or I guess, do the changes in ROE move the needle on affordability? Or is there just a general recognition that the pressure is coming from the supply/demand that's really outside the state.

Look, I totally agree with what you just said. I think a lot of people are finding their footing, and I think there's been a lot of constructive conversations both between the companies, the administration and legislators and the BPU. I think everybody is trying to do exactly what you said, find their footings. And I think everybody does recognize the challenge has been generated from outside the state, but I also think we all know that we have some responsibility to do what we can from an affordability standpoint for our customers. So everybody is trying to row in the same direction. And I hope you hear my tone, I feel positive about the way that we're trying to approach it as a team approach rather than finger-pointing approach at this point.

Great. Appreciate that. And just maybe shifting to the PJM capacity and reserve auction process. some of the PJM neighbors have been vocal around it. What could we see in terms of your participation in the [ RBA ] from both the power side and as the EDC, any concerns around capacity cost allocation for your own?

Yes. I mean I just -- I don't disagree with a lot of the comments that have been made outside this area. As you said, there's a lot of people being pretty vocal about it. I would just think that we should all just be a little bit calm and watch what happens here. There's a lot of steps to go through. And I don't want to overreact to anything. Obviously, we need to protect the customers, the utilities make sure that they're not being burdened with planning assumptions that are being driven outside of anybody's responsibility. We've got some states that have IRPs. They have their own planning assumptions. We have PJM with it's own planning assumption. And then you have customers putting in requests, all of that needs to be balanced and put that on the back of the utilities just doesn't seem to make a ton of sense for anybody. So we'll see how that plays out over time. But I feel like, look, it's a chance for us to bring more generation in. We all know there's a resource adequacy problem. I don't know how much we're going to get done. We'd be in the region by 2031. But I think it's a good step that we're trying and hope it produces some results. But I think the limiting factor of 2031 is going to make it really tough for us to make this a game changer.

And [ Constatin ], just inherent within your question, you did talk about cost allocation and I think very consistent with some of our actions related to a FERC decision around cost allocation. We're going to continue to look out for our customers and in this instance like in the one that I'm referencing and that we talked about within the prepared remarks, we'll continue to make sure that those allocations to the best of our ability are going to be fair for our customers.

And maybe just to clarify, do you think like the capacity price cap extension provide any additional upside on the power side kind of versus the [indiscernible] plan?

Well, I think we had envisioned -- we have spoken in the past about the fact that we thought things were going to stay about where they were. So I would leave the comment there.

Our next question comes from the line of Carly Davenport with Goldman Sachs.

Maybe just starting on New Jersey. I guess we do have a stakeholder meeting being held by the BPU this week gone on executive order on kind of focused mostly on the kind of utility business model. I guess anything that you're expecting out of that meeting in terms of focus areas or kind of what you think is on the table to address as we think about the utility business model in New Jersey?

Yes. Look, I think, consistent with what we've said in the past, we expect performance to be one of the biggest issues that will be on the table. And we welcome that in the areas that we've seen focus in other states. Our performance, we think, has been exemplary, and I would expect that to continue. So I would -- as I've said in prior meetings, in some ways, welcome the recognition of our utility for the work that they've been able to accomplish from a reliability standpoint, certainly from an ability to hook up customers and customer satisfaction. So those 3 areas, areas that we think we have a lot of strength in. And that's where the performance conversation goes, we would be supportive of that. But I think that's where -- we'll be at the meeting, we'll be participating, and we'll be constructive in the conversations.

Got it. Okay. Great. That's helpful. And then maybe just sticking in New Jersey, but just on the nuclear side, I know you mentioned the lifting of the moratorium kind of in your prepared? And just maybe talk a little bit about how you envision PEG kind of participating on the nuclear task force in the state and maybe what some tangible updates could look like as we think about the opportunities around new nuclear in the state.

Yes, we did -- thanks for that. We've been obviously leaning in. It's clear that the Sherrill administration is supportive of additional generation. It looks like nuclear is one of those areas that there is some momentum being gained in that area. Obviously, the signing of that legislation, we thought was a great event, great signal from the administration of their support. So we're going to continue to do what we've been doing, which is try to enable it and advocate really, really hard for the state. We think we have a great site down at Salem. There's been -- port construction was completed. It's going to make some construction activities easier. We have some great labor in that area, and we have the technical capabilities and operational performance that to deliver additional megawatt hours out of that area. So we're going to be advocating hard and try to stay lockstep with the administration on that.

Our next question comes from the line of Jeremy Tonet with JPMorgan.

I Was just wondering if I could start with a large load increase here. I was just wondering if you could provide a bit more color, I guess, on the current state of conversations and interest there? And where does the total count stand versus last quarter or I think it was [ 11.8 ] as of the end of December.

Yes, Jeremy, that's about right. And we've seen -- it was interesting. Last year, if you go through the year, we saw quite a significant increase as you step through time. And I think you kind of were seeing the knee of the curve as the interest more broadly was coming about in data centers. I'd say directionally, you've seen that kind of level off within the state. That 11,000 we always talked about as being somewhere, I don't know, maybe 10%, 15%, 20% of that may come to fruition if we look based upon history, what we've seen within different new business coming forward. Hard to predict on that, which is, I think, a broad topic across the sector. But I'd say we're still kind of in that ballpark. I think the change that we saw across last year had us put that forward, so people could get an understanding and the leveling off, there's a little bit less to talk about on that front. We still pursue the ability to try to serve some of that load, either here or in Pennsylvania where we have the peach bottom units and that activity continues.

Got it. That's helpful. And that kind of leads to my next question here, if you might be able to provide some color bifurcating between the states as far as interest or type of activity -- type of conversations. And at the same time, just curious, I guess, as how does demand response currently factor into any of these discussions? And has that changed over time?

No, I don't think the DR has kind of changed the discussions over time, but I do think your first -- the first part of your question is a little bit more pointed and provides a little bit more differentiation. Just literally by virtue of what type of data centers are interested in going there. I would say that absent the significant tax incentives in New Jersey, you have not seen the sizable interest in New Jersey. That's been a consistent concept that we've talked about for a while. And then in other states, and there are plenty of them, where some of the larger hyperscalers have the ability to drive some of the financial incentives to be able to go there. And so they are following those incentives from everything we've seen. And I would say that the opportunity set to serve them follow suit with that.

Our next question comes from the line of Nick Amicucci with Evercore ISI.

Couple of quick ones for me, if I could. So when we just about kind of the cadence at Salem and the potential for the capacity upgrade. Would we -- is it pretty much assumed that you would be seeking the extension first and then any kind of firm announcement on the potential upgrades?

You're talking about the license extension first? .

Yes.

Yes. The license extension, the Salem units have current licenses that run through 2036 and 2040. Anything we would do to extend that another 20 years would happen in advance of that. But what we've talked about with respect to the uprate by comparison, we said either the outage in '27 or the outage in '29 is when we would anticipate those coming on. So there will be activity, I think, on the license extension, but I think you'll see the uprate come through within those 2 time frames that I mentioned.

Yes. So very specifically, we're not counting on that license extension to be in before we do the upgrade. That's not a gating factor, right?

And then if I could, just given kind of the strong performance, obviously, somewhat weather driven in the first quarter, but it's probably adjusted EPS, roughly 36% at the midpoint. And so that's pretty above seasonal. Just wanted to see -- I mean, understanding that it's early still in the year. But what kind of -- what would you need to see kind of going forward to then kind of move either to kind of cut the guidance range to the upper half or kind of increase or increase guidance altogether?

Yes. I think on a normal year, even when you decouple just volumetrically, you're going to see a lot more coming through in the winters and the summers. And so I think there's a piece of that that you see coming through from this winter. I think if I were to give you a one-word answer, it would be what the summer ends up looking like. I mean we're decoupled, so we don't have as much of an impact from that perspective, but there are some elements whether it's weather driving demand is a little bit higher on gas and that those demands moving things or even just the snow removals or things along those nature have an impact on what the results look like. And we have more of those types of events, I think, like everybody else in the winter and in the summer, so I would say, get through the summer and see what we look like.

I think you saw -- Nick, the other piece to this, just to remind you, we mentioned the gas ops there and there was some value generated from our gas operations group. Just a reminder, that also goes to offset customer rates pretty dramatically. So another good news message for the customers in New Jersey that we were able to transact in that area.

Our next question comes from the line of Julien Dumoulin-Smith with Jefferies.

Come on, bring it on. Let's do it. You got to keep it lively. Look, let me ask you guys about PJM here. And I know people keep needling you about it, and I want to just come back to it real quickly. How do you think about your participation, whether in a bilateral context or outright and some other permutation. Again, we heard comments this morning, we've heard comments elsewhere. I mean just how do you think about that coming together? And just how would you set expectations around this process? You all are keeping close tabs on this whole process at the state level and at the PJM level, how would you set expectations about what ultimately happens in terms of backstop versus bilateral versus just capacity not getting procured on a timely basis?

Yes. So in your question here is our participation you mean in new generation or existing...

Any flavor, but I'm curious about the you're waxing about the process and then separately, your participation in any flavor?

Yes. Look, I think the #1 thing that we've been focused on, and this goes back a long time, before the words resource adequacy were popular is the reliability, right, and the reliability of the grid. And we've been on it since 2003, since the lights went out. So we start from there, looking out for the customers and then looking at from a customer cost standpoint. I think we need to make sure that we're protecting the customer, number one, and making sure that there's enough product to deliver the customer; number two. And I'm not sure that the current -- the way it's currently drafted really does both of those things. I think there's a little bit of a concern about putting that burden on the LDCs versus the LSCs and whatever other acronyms we want to throw in there. But we will participate in a process and we're going to advocate strongly. We've got a new CEO at PJM that's just stepped into the role. I want to -- before we pass any judgment on what's going on at PJM, let's give them a chance to get their feet under them and get the organization structured the way they want in the rules and proposals the way they'd like to see them. So we'll continue to look at this from the customer's perspective and advocate on that behalf. Part 2 is when you think about generation and inheriting that, hey, where is the supply going to come from? And we inherently get -- we get the question all the time, will you participate. We've always said we'll participate in utility-like generation. We think we have some sites that make sense. The question is the fuel supply and whether or not that's a fuel supply that makes sense for the state that those sites sit in, but we're open to it, but it's got to be utility-like investments when we have those conversations.

Got it. Okay. Fair enough. And then just when you think about the -- you guys keep talking about new nuclear and obviously, I get why. How do you think about what that looks like in the state in terms of next steps? I mean a lot of folks talk about it, but obviously, you've got to get the right risk construct, I totally appreciate that. But just tangibly, what would the next step look like here just to show progress if there is to be something to happen.

I think it's going to be a combination of government supporting the effort, right? You're going to need to see some strong support from the federal government. There's rumors around that in different ways, shapes and forms that you hear being discussed from different departments in Washington. So number One, I think we'd need federal support. Number two, you'd have to have state support. That would be -- I think you need states looking for offtake agreements. You need hyperscalers looking for offtake agreements. You need companies supporting it. I think there's a combination of things that would have to come together. But it all to me starts with the government being aligned and that government being aligned from the long term, right? You need to ensure that not only do you have some financial support, but that you have the permitting support and the siding support. Heard a lot of that from our governor, that's one of the things that they want to streamline here in New Jersey. So again, aligned with building new generation. But I don't see any state taken on new nuclear without the support of the federal government.

Sorry. And just to elaborate on the last one real quickly, your response there. Is there a timing on when you could follow through on contracted new gen, whether that's gas or more specific storage or solar?

No. I mean I think you got to see what all the rules are. That was my point. When you look at this reliability backstop, I think we'll see what those rules are to come out. But if that's a pure market solution, that's not something we're interested in. And that was the point I wanted to make. We're not interested in markets and participating in that. That's not what our core businesses. But if we're looking for rate base utility like, we've done that in the past, 30-year PPAs, those types of things. But I don't know what will come out of this [ RVA ]. And then really remember, that's only on the capacity side, right? You still got the whole energy side that you got to figure out how you get a contract for it.

Our next question comes from the line of Michael Sullivan with Wolfe Research.

Picking up on the kind of your last comment there, just the energy side of the equation. Any color you can give on just this pretty sharp move in PJM pricing and how you're thinking about that on kind of both sides of the house. Like any color on longer-term hedges? And then how you're thinking about kind of the bill impact from that on the utility side.

Well, Michael, this is Dan. The most immediate impact on the bill is going to be the BGS that we just procured in February. So from a bill perspective, we know what things are going to look like. And for PSE&G customers, they're going to see their bill go down 1.8% by -- on June 1 because of what happened on BGS. And again, from a customer perspective, that will change again next June 1. . So there's a lot of stability inherent within the BGS construct that the state put together many, many years ago that still does exist. And I think more broadly, if you think about market -- one of the things I do think that markets are trying to figure out is where this RBA does go to and what it does bring in from a supply perspective, people are weighing their own individual views as to how much load is going to come on the system and what generation is going to be there to meet it. And that's ultimately through the market construct how prices are going to be set. And so I think those are the bigger questions that people will continue to digest like in any other market, they'll use the available data. But in this instance, it's how much load is going to actually come online when it's going to come online and the same 2 questions around supply. And I think you've seen some movement over time as people try to think that through. But in general, I think you're going to have a tighter market because I think the path to incremental demand is a little bit clearer from a volumetric perspective and the past incremental supply.

Okay. That's helpful. And any color on how much you're hedging into this in the out years?

No. I mean the thing that we've said is that for the front year, we're pretty close to fully hedged. And then as you look through the next couple of years, that will cascade off a little bit.

Okay. And then just last thing, just kind of next couple of months here into kind of the summer resets at the legislature. Anything you expect or are focused on getting done between now and then?

No, look, I'll weigh in there a little bit, Michael. I think that affordability remains a hot topic here in the state. I think we are prepared for those conversations as they continue to take place, and we continue to be supportive. I think there is a possibility for people to be talking about resource adequacy solutions. That's something that might be out there. And again, we're just monitoring and once those once those issues, if there's any legislation introduced, we'll assess them and comment on them. .

Our next question comes from the line of Sophie Karp with KeyBanc Capital Markets.

I'm curious if you see any opportunities potentially for yourselves in the upcoming PJM transmission open window.

Yes. So, I think that we even referenced a little bit of that on the prepared remarks. We, on an ongoing basis, do take a look at what comes through those open windows. We'll do exactly the same thing this summer when the next window opens. I think I would call it a careful look at what we think makes the most sense for things for us to do. I think we have a pretty deep well of experience in building transmission and that doesn't mean that everything is going to make sense for us. And so we go through pretty carefully, taking a look at what we do think makes sense. And we will put in a competitive bid to the extent that we think something does. And so I'll remind you the capital plan that's in place doesn't have anything that we have not already won through a competitive process. But I absolutely think we have the skill set to be able to expand in that area and then we will just increment the capital plan to the extent that we do win as we go forward.

Okay. And then on kind of [indiscernible], I appreciate your comment that absent of the incentives they not necessarily looking to locate in New Jersey. But is it an option for your New Jersey assets to have virtual PPA virtual offtake with facilities elsewhere? Or is that not a major focus right now?

No. Look, we are deliverable to beyond New Jersey and even today, that power flows on the grid in the region. And so there is absolutely the potential for us to do something with the New Jersey units or the Pennsylvania units beyond the node that they're at and beyond the zone that they're in. So yes, that is possible.

Our next question comes from the line of Ronnie Sen with Bank of America. .

First, on the BGS auction, obviously, you got the 1.8% reduction that's going to go into effect June. So I guess, how are you thinking about the repeatability of that with capacity prices either staying at the same level or going lower and potentially power prices going up. But I guess, do you think you can kind of keep up the same decreases year-over-year?

Yes. I mean you understand the pieces as well as we do. And the way that auction works is that it's going to be for a 3-year period for the 1/3 of the load. So what you're doing is taking a look at at least by design, unless there are delays at PJM capacity auctions that have already transpired. So that's a known item. We don't know what they all are now, but we'll know what they are by the time that auction comes around. And then a forecast of what energy prices look like. And that's probably your biggest variable as you go forward. What will those energy prices look like? The other thing I would say, though, is it being an auction for 1/3 of the total demand, any impact -- if you were to see a $3 impact in the price of energy, you would see a $1 impact come through towards the bill because of the gradual effect of that. You see that $1 increase across 3 years, but the gradualism of that mechanism is going to provide gradualism and the impact on rates to customers. But beyond that, trying to estimate exactly where things are going to go, is kind of tough to do, obviously.

Yes, just to reinforce something Dan said there. Just a reminder, the last time we had sticker shock was due to the fact that there was a capacity market delay. So even if prices are incrementally up a little bit, you're not going to have that same sticker shock situation that we experienced a year ago when the BGS price came in so high because the capacity prices had piled up for 3 years. And those increases sitting there caused the challenge that we had. It wasn't necessarily incremental, especially in what we believe is a very good mechanism in BGS where you have this third, third and third.

Yes, it's a great point. But for the delay in the capacity auction, you would not have seen the magnitude of year-over-year increase that you saw.

Yes. I think that is very clear. It makes sense. And then on the RBP, I know we've talked a lot about it on this call, but I saw the proposal that you filed jointly with some other EDCs. I guess how are you thinking about what's the ideal things that need to be solved? And would be in your favor for that, like in terms of -- I thought that the load serving entity should be the cost responsibility, but anything else that you'd point out?

No, what I said earlier, I think it was the key is the planning process, right? You've really got to make sure that the planning process is a solid one, and there's consensus around it. And then lever is the planner is the one that winds up with the accountability, right? That's the key. To have the planning done by a town and then the accountability sit at the county level doesn't make a ton of sense, right? I'm just using some sort of parallel there. So I just really think we got to get all of that aligned. And as I said earlier, states have IRP requirements. In addition to the states having the IRP requirements, PJM has been granted by the the responsibility for transmission planning. So you put those pieces together and it's kind of odd for that to wind up back with the EDCs. Therefore, the lower serving entities that are the entities that have been identified with the responsibility is where we believe the burden should sit.

And our last question comes from the line of Anthony Crowdell with Mizuho Securities.

Just a follow-up to, I think Nick's question earlier on the Nuclear [ uprates ] and maybe the timing of them. Just if you could tell me, when do you file for the timing, but also approval for the uprates. Is that an additional CapEx opportunity or it's further out in the 5-year plan or you already have it included in your current plan?

Yes. We've got the capital that's included there. And the timing of it is going to depend upon which outage it goes into, Anthony. So it's -- that's when I said '27 or '29, we'll have an outage for those units 2027, outage in 2029. And depending upon as that thing, how it moves forward, that's when we'll end up seeing that [ uprate ] go through. You're asking about the [indiscernible] not license extension, right?

No, more of the license extension. I'm sorry, if I wasn't clear. Just...

So the license extension, we'll get information back over the next x amount of years, right? I know NRC is trying to move down a little bit quicker than they have in the past. And at that point, they'll let us know whether or not we have to change the oil, change the tires, what needs to be done and we'll be able to forecast the CapEx at that point.

And again, is it -- I know the timing is not there at the NRC, is that within the 5-year period it could be or it could also be outside the 5-year period?

I think we would certainly get -- we would gain consensus with NRC the work that needs to be done in the 5-year time line. And I think the work will be completed outside the 5-year time line.

And there are no further questions at this time. I would like to turn the floor back to Mr. LaRoSSa for closing comments.

Well, thank you all for your interest in dialing in today. I know it's a busy day for many of you on the call. So I appreciate you taking the time. And looking forward to speaking to everybody at AGA. And I'll end with note of thank you to our team here for the work that was completed through this past winter. The weather was not an easy -- it was not easy for us and people continue to work above and beyond our expectations. So thank you to the team, and thank you all for calling in and looking forward to seeing you all at AGA later this month. Take care. .

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