ewsba.se
Chair, President, and CEO — Ralph A. LaRossa
Executive Vice President and CFO — Daniel J. Cregg
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Ralph A. LaRossa, Chair, President and CEO, and Daniel J. 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. Public Service Enterprise Group Incorporated'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 A. LaRossa.
Ralph A. LaRossa: Thank you, Carlotta, and thank you for joining us to review Public Service Enterprise Group Incorporated's first quarter 2026 results. Starting with our financial results, Public Service Enterprise Group Incorporated 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-saving energy efficiency programs at PSE&G. 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 am 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. For the 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 cannot say enough about our employees who carry out PSE&G's storm response work, who braved the elements to keep the lights on and homes warm for our customers. The 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 modernization to address the impact that extreme temperatures have on our aging cast iron gas system. Despite this year's winter weather, PSE&G is on track with its 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 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 for 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 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, to PSE&G customers after PJM's implementation. While this matter is still being litigated at FERC, it is another example of how Public Service Enterprise Group Incorporated works in partnership with the state at the regional and federal levels to keep our customer bills as low as possible. I would also like to mention that we are ramping up PSE&G's technology-driven conservation efforts.
PSE&G recently launched two new ways to reduce energy use during peak times to save customers money and help reduce strain on the grid. The first is our demand response program with over 32 thousand residential and small business customers already enrolled to receive an upfront payment for reducing air conditioning use and other activities like EV charging during selected peak hours throughout the year. The second program is our new residential time-of-use rate that can save customers money by shifting some of their usage to off-peak times. This new rate option leverages the more detailed electric usage made available by our AMI investment in smart 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 this directive in the first executive order. We expect that the BPU consultant will release the 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 would 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 price collar through the 2029–2030 Base Residual Auction. This extension is expected to stabilize the effect of upcoming auctions on New Jersey's BGS 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 increase New Jersey-based generation supply, Governor Cheryl recently signed legislation lifting a decades-long moratorium on new nuclear construction. The announcement made at our three-unit site in Salem County highlighted broad support from policymakers, legislators, and labor leaders. Public Service Enterprise Group Incorporated is engaging in efforts to advance new nuclear development at PSEG's site. 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.
It is intended to be a one-time 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, Public Service Enterprise Group Incorporated 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 Public Service Enterprise Group Incorporated was named to the Dow Jones Best-in-Class North America Index for the eighteenth year in a row. We are maintaining the broad set of financial projections that we shared in late February, starting with our five-year regulated capital investment plan of $22.5 billion to $25.5 billion at PSE&G, and $24 billion to $28 billion for PSEG Power, both through 2030.
This investment program supports the utility's 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 Public Service Enterprise Group Incorporated over that same period. 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, then rejoin the call for our Q&A session.
Daniel J. Cregg: Great. Thank you, Ralph, and good morning, everyone. Public Service Enterprise Group Incorporated 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 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 $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 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 2025, reflecting an increase in operating costs due to inflation and extreme weather in January and February.
Depreciation and interest each rose by $0.00 per share compared to 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 [inaudible] 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 2025, but had a limited impact on utility margin. As you know, the Conservation Incentive Program, or CIP, mechanism decouples weather and other economic sales variances from a significant portion of our distribution margin, while helping PSE&G promote the widespread adoption of energy conservation, including energy efficiency and solar programs.
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 have also maintained our five-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 three-year period.
The GSMP III program's total includes approximately $1 billion in accelerated recovery and $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 and capacity starting June 1.
Moving to PSEG Power and Other, for the first quarter of 2026, we reported net income of $164 million compared to $43 million in 2025, while non-GAAP operating earnings were $201 million for the first quarter compared to $172 million for 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 2026.
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 reserves. 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. 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, Public Service Enterprise Group Incorporated had ample liquidity totaling $3.9 billion at March. This includes approximately $400 million of cash on hand, primarily related to net PSE&G financing activity during the quarter. Public Service Enterprise Group Incorporated entered into a $500 million, 364-day variable rate term loan in February, further supporting our liquidity position. Also during the quarter, all of our revolving credit facilities totaling $3.75 billion were extended by two years through March 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 4.20% 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. Public Service Enterprise Group Incorporated also has limited exposure to variable-rate debt, which totaled approximately $915 million and consists of two 364-day term loans and commercial paper, and represented a low 4% of our total debt at March.
Looking ahead, our solid balance sheet continues to support the execution of Public Service Enterprise Group Incorporated's five-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 fifteenth consecutive annual increase. In closing, we delivered solid operating and financial performance to begin the year and are maintaining Public Service Enterprise Group Incorporated'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: Thank you. Ladies and gentlemen, we will now begin the question and answer session for members of the financial community. If you have a question, please press star then the number 1 on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing star then the number 2. If you are on a speakerphone, please pick up your handset before entering your request. One moment, please, for the first question. The first question comes from the line of Shahriar Pourreza with Wells Fargo. Please proceed with your question.
Analyst: Hi. Good morning, team. It is Constantine here for Shar. Thanks for taking the questions.
Ralph A. LaRossa: That is why I paused a little bit there, Constantine. I was not sure if it was you or him. So I did not want to say hello to Shar first. How are you, Constantine?
Analyst: Oh, doing quite well. Thank you so much. Just maybe a quick one starting on the BPU and the legislative process on utility constructs. The different branches finding their footing in terms of priorities—Is there anything in the cost-of-service model getting attention? Or 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 is really outside the state?
Ralph A. LaRossa: Look, I totally agree with what you just said. I think a lot of people are finding their footing, and I think there have been a lot of constructive conversations between the companies, the administration, legislators, and the BPU. I think everybody is trying to do exactly what you said, find their footing, 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.
I hope you hear my tone—I feel positive about the way that we are trying to approach it as a team approach rather than a finger-pointing approach at this point.
Analyst: Great. Appreciate that. And just maybe shifting to the PJM capacity and reserve auction process. Some of the 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? And any concerns around capacity cost allocation for your zone?
Ralph A. LaRossa: I do not disagree with a lot of the comments that have been made outside this area. As you said, there are a lot of people being pretty vocal about it. I would just say that we should all be a little bit calm and watch what happens here. There are a lot of steps to go through, and I do not want to overreact to anything. We obviously need to protect the customers and the utilities, and make sure that they are not being burdened with planning assumptions that are being driven outside of anybody's responsibility. We have some states that have IRPs—they have their own planning assumptions. We have PJM with its own planning assumptions.
And then you have customers putting in requests. All of that needs to be balanced, and to put that on the back of the utilities just does not seem to make a ton of sense for anybody. So we will see how that plays out over time. I feel like it is a chance for us to bring more generation in. We all know there is a resource adequacy problem. I do not know how much we are going to get done—we being the region—by 2031, but I think it is a good step that we are trying, and I 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.
Daniel J. Cregg: And, Constantine, inherent within your question, you did talk about cost allocation. Very consistent with some of our actions related to FERC decisions around cost allocation, we are going to continue to look out for our customers, and in this instance, like in the one that we talked about within the prepared remarks, we will continue to make sure that those allocations, to the best of our ability, are going to be fair for our customers.
Analyst: And maybe just to clarify, do things like the capacity price cap extension provide any additional upside on the power side versus the 6% to 8% plan?
Ralph A. LaRossa: We had envisioned and 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.
Analyst: Appreciate it. Thanks so much for the time today.
Operator: Our next question comes from the line of Carly S. Davenport with Goldman Sachs. Please proceed with your question.
Carly S. Davenport: Good morning. Thanks so much for taking the questions. Maybe just starting on New Jersey—we do have a stakeholder meeting being held by the BPU this week on Executive Order 1, focused mostly on the utility business model. Anything that you are expecting out of that meeting in terms of focus areas, or what you think is on the table to address as we think about the utility business model in New Jersey?
Ralph A. LaRossa: Consistent with what we have 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 have seen focus in other states, our performance, we think, has been exemplary, and I would expect that to continue. I would, as I have said in prior meetings, in some ways welcome the recognition of our utility for the work that we have been able to accomplish from a reliability standpoint, certainly from the ability to hook up customers, and in customer satisfaction.
Those three areas are areas where we think we have a lot of strength, and where the performance conversation goes, we would be supportive of that. We will be participating and we will be constructive in the conversations.
Carly S. Davenport: Got it. Great. That is helpful. And then maybe just sticking in New Jersey, but on the nuclear side—you mentioned the lifting of the moratorium in your prepared remarks. Could you talk a little bit about how you envision Public Service Enterprise Group Incorporated participating on the nuclear front in the state, and what some tangible updates could look like as we think about the opportunities around new nuclear in the state?
Ralph A. LaRossa: Thanks for that. We have obviously been leaning in. It is clear that the federal administration is supportive of additional generation, and it looks like nuclear is one of those areas where there is momentum. The signing of that legislation was a great event and a great signal from the administration of their support. We are going to continue to do what we have been doing, which is try to enable it and advocate really hard for the state. We think we have a great site down at Salem. The port construction was completed, which will make some construction activities easier.
We have great labor in that area, and we have the technical capabilities and operational performance to deliver additional megawatt-hours out of that area. We are going to be advocating hard and try to stay lockstep with the administration on that.
Carly S. Davenport: Great. Thank you so much for the time.
Operator: Thank you. Our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.
Jeremy Tonet: I was just wondering if I could start with large load increase here. Could you provide a bit more color on the current state of conversations and interest there? Where does the total count stand versus last quarter? I think it was 11.8 as of December.
Daniel J. Cregg: That is about right. It is interesting—last year, if you go through the year, we saw quite a significant increase as you step through time, and I think you were seeing the knee of the curve as the interest more broadly was coming about in data centers. I would say directionally you have seen that level off within the state. That 11 thousand MW we always talked about as being somewhere—maybe 10%, 15%, 20% of that may come to fruition if we look based upon history and what we have seen within different new business coming forward. It is hard to predict, which is a broad topic across the sector, but I would say we are still in that ballpark.
The change that we saw across last year had us put that forward so people could understand it, and with the leveling off, there is 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.
Jeremy Tonet: Got it. That is helpful. That leads to my next question—could you provide some color bifurcating between the states as far as interest or type of activity or conversations? At the same time, how does demand response currently factor into any of these discussions, and has that changed over time?
Daniel J. Cregg: I do not think the demand response factor has changed the discussions over time, but your first question is more pointed and provides more differentiation, literally by virtue of what type of data centers are interested in going where. Absent significant tax incentives in New Jersey, you have not seen sizable interest in New Jersey. That has been a consistent concept that we have talked about for a while. In other states—there are plenty of them—some of the larger hyperscalers have the ability to derive financial incentives to go there, and they are following those incentives from everything we have seen. The opportunity set to serve them follows suit with that.
Jeremy Tonet: Got it. Makes sense. I will leave it there. Thank you.
Operator: Our next question comes from the line of Nicholas Amicucci with Evercore ISI. Please proceed with your question.
Nicholas Amicucci: Hey, guys. How are we?
Nicholas Amicucci: Just a couple quick ones for me, if I could. When we think about the cadence at Salem and the potential for the capacity upgrade, would we pretty much assume that you would be seeking the extension first and then any firm announcement on a potential upgrade?
Daniel J. Cregg: You are talking about the license extension first?
Daniel J. Cregg: 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. What we have talked about with respect to the uprate by comparison—we said either the outage in 2027 or the outage in 2029 is when we would anticipate those coming on. There will be activity on the license extension, but I think you will see the upgrade come through within those two time frames that I mentioned.
Ralph A. LaRossa: Very specifically, we are not counting on that extension to be in before we do the upgrade. That is not a gating factor.
Nicholas Amicucci: Got it. Perfect. And then, given the strong performance—somewhat weather-driven—in the first quarter, adjusted EPS is roughly 36% of the midpoint. That is pretty above seasonal. Understanding that it is early, what would you need to see going forward to move either to narrow the guidance range to the upper half or increase guidance altogether?
Daniel J. Cregg: On a normal year, even when you are decoupled, just volumetrically you are going to see a lot more coming through in the winters and the summers. There is a piece of that coming through from this winter. If I were to give you a one-word answer, it would be: what the summer ends up looking like. We are decoupled, so we do not have as much of an impact from that perspective, but there are elements—whether it is weather driving demands a little bit higher on gas and those demands moving things, or even just the snow removal and things of that nature—that have an impact on results.
We have more of those types of events, like everybody else, in the winter and in the summer. I would say, get through the summer and see what we look like.
Ralph A. LaRossa: I think you saw it, Nick. The other piece to this—just to remind you—we mentioned gas ops and that 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.
Nicholas Amicucci: Dan. Thanks, Ralph. We will see you guys in a couple of weeks.
Operator: Thank you. Our next question comes from the line of Julien Patrick Dumoulin-Smith with Jefferies. Please proceed with your question.
Julien Patrick Dumoulin-Smith: Hey. Good morning, Ralph and team. How are you guys doing?
Ralph A. LaRossa: Good, Julien. How are you?
Julien Patrick Dumoulin-Smith: Quite well. Thank you very much. Appreciate it.
Ralph A. LaRossa: Looking forward to another video.
Daniel J. Cregg: Really. Come on. Bring it on. Let us do it.
Julien Patrick Dumoulin-Smith: Gotta keep it lively. Let me ask you about PJM here. I know people keep needling you about it, and I want to come back to it quickly. How do you think about your participation—whether in a bilateral context, or outright in some other permutation? We have heard comments this morning and elsewhere. How do you think about that coming together, and how would you set expectations around this process? You all are keeping close tabs on this whole process at the state level and at PJM. How would you set expectations about what ultimately happens in terms of backstop versus bilateral versus capacity not getting procured on a timely basis?
Ralph A. LaRossa: Your question is our participation in new generation? We start from reliability—looking out for the customer—and then looking out from a customer cost standpoint. We need to make sure that we are protecting the customer, number one, and making sure that there is enough product to deliver to those customers, number two. I am not sure that the way it is currently drafted really does both of those things. I think there is a concern about putting that burden on the LDCs versus the LSEs and whatever other acronyms we want to throw in there. We will participate in the process and advocate strongly. We have a new CEO at PJM that just stepped into the role.
Before we pass any judgment on what is going on at PJM, let us give them a chance to get their feet under them, get the organization structured the way they want, and the rules and proposals the way they would like to see them. We will continue to look at this from the customer's perspective and advocate on that behalf. As to generation—and inherent in this is where the supply will come from—we get the question all the time, will you participate? We have always said we will do utility-like generation. We think we have some sites that make sense.
The question is the fuel supply and whether that fuel supply makes sense for the state that those sites sit in. We are open to it, but it has to be utility-like investments when we have those conversations.
Julien Patrick Dumoulin-Smith: Got it. Okay. Fair enough. And then, when you think about new nuclear—you guys keep talking about it—how do you think about what that looks like in the state in terms of next steps? A lot of folks talk about it, but you have to get the right risk construct. Tangibly, what would the next step look like to show progress if there is to be something to happen?
Ralph A. LaRossa: It is going to be a combination of government supporting the effort. You are going to need strong support from the federal government. There are rumors in different ways, shapes, and forms being discussed by different departments in Washington. Number one, we would need federal support. Number two, you would have to have state support. You would need states looking for offtake agreements, hyperscalers looking for offtake agreements, and companies supporting it. There is a combination of things that would have to come together. But it all, to me, starts with government being aligned for the long term. You need to ensure that not only do you have some financial support, but that you have the permitting and siting support.
We have heard a lot of that from our governor—that is one of the things they want to streamline here in New Jersey. Again, aligned with building new generation. I do not see any state taking on new nuclear without the support of the federal government.
Julien Patrick Dumoulin-Smith: Sorry, and just to elaborate on the last one—timing on when you could follow through on contracted new generation, whether that is gas or more specific storage or solar?
Ralph A. LaRossa: You have to see what all the rules are. That was my point. When you look at this reliability backstop, we will see what those rules are when they come out. If that is a pure market solution, that is not something we are interested in. We are not interested in markets and in participating in that—that is not what our core business is. But if we are looking for rate base, utility-like—We have done that in the past: 30-year PPAs, those types of things. I do not know what will come out of this RBA. And then remember, it is only on the capacity side.
You still have the whole energy side that you have to figure out how you get a contract for.
Julien Patrick Dumoulin-Smith: I hear you. I will leave it there. More to go.
Ralph A. LaRossa: Thanks, Julien. See you in a little bit in May.
Operator: Thank you. Our next question comes from the line of Michael P. Sullivan with Wolfe Research. Please proceed with your question.
Michael P. Sullivan: Hey, guys. Good morning.
Michael P. Sullivan: Picking up on your last comment—the energy side of the equation—any color you can give on this sharp move in PJM pricing and how you are thinking about that on both sides of the house? Any color on longer-term hedges, and then how you are thinking about the bill impact from that on the utility side?
Daniel J. Cregg: The most immediate impact on the bill is going to be the BGS that we procured in February. From a bill perspective, we know what things are going to look like, and for PSE&G customers, they are going to see their bill go down 1.8% by June 1 because of what happened on BGS. From a customer perspective, that will change again next June 1. There is a lot of stability inherent within the BGS construct that the state put together many years ago that still exists. More broadly, if you think about markets, one of the things I think markets are trying to figure out is where this RBA goes and what it brings 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 and needed. Ultimately, through the market construct, that is how prices are going to be set. Those are the bigger questions people will continue to digest, as in any market—they will use the available data. In this instance, it is: how much load is going to actually come online, and the same two questions around supply. I think you have seen some movement over time as people try to think that through.
In general, you are going to have a tighter market because the path to incremental demand is a little bit clearer from a volumetric perspective than the path to incremental supply.
Michael P. Sullivan: That is helpful. Any color on how much you are hedging into this in the out years?
Daniel J. Cregg: For the prompt year, we are pretty close to fully hedged. As you look through the couple of years beyond, we cascade off a little bit.
Michael P. Sullivan: And then next, over the next couple months into the summer resets at the legislature—anything you expect or are focused on getting done between now and then?
Ralph A. LaRossa: Affordability remains a hot topic here in the state. We are prepared for those conversations as they continue, and we continue to be supportive. There is a possibility for people to be talking about resource adequacy solutions—something else that might be out there. We are monitoring, and once those issues—if there is any legislation introduced—come up, we will assess them and comment on them.
Michael P. Sullivan: Great. Thank you very much.
Operator: Thank you. Our next question comes from the line of Analyst with KeyBanc Capital Markets. Please proceed with your question.
Analyst: Good morning. Thank you for taking my questions. I am curious if you see any opportunities for yourselves in the upcoming PJM transmission open window.
Daniel J. Cregg: We touched on a little bit of that in the prepared remarks. On an ongoing basis, we look at what comes through those open windows. We will do exactly the same thing this summer when the next window opens. I would call it a careful look at what makes the most sense for us to do. We have a pretty deep well of experience in building transmission, and that does not mean that everything is going to make sense for us. We carefully take a look at what we think does make sense, and we will put in a competitive bid to the extent that we think something does.
I will remind you, the capital plan that is in place does not 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 we will just increment the capital plan to the extent that we do win as we go forward.
Analyst: Thank you. Then on data centers, I appreciate your comment that absent incentives they are not necessarily looking to locate in New Jersey. Is there an option for your New Jersey assets to have a virtual PPA, virtual offtake with a facility elsewhere, or is that not a major focus right now?
Daniel J. Cregg: We are deliverable beyond New Jersey, and even today, that power flows on the grid in the region. There is absolutely the potential for us to do something with the New Jersey units or the Pennsylvania units beyond the node they are at and beyond the zone they are in. So yes, that is possible.
Operator: Thank you. Our next question comes from the line of Analyst with Bank of America. Please proceed with your question.
Analyst: Hi, guys. Thanks for taking the question. First, on the BGS auction—obviously, you have the 1.8% reduction that is going into effect in June. 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? Do you think you can keep up the same decreases year over year?
Daniel J. Cregg: You understand the pieces as well as we do. The way that auction works is that it is for a three-year period for a third of the load. You are taking a look at—by design, unless there are delays at PJM—capacity auctions that have already transpired. That is a known item. We do not know what they all are now, but we will know by the time that auction comes around. Then you have a forecast of what energy prices look like—that is probably your biggest variable going forward.
The other thing I would say is, being an auction for a third of the total demand, any impact—if you were to see a $3 impact on the price of energy—you would see a $1 impact come through toward the bill because of the gradual effect. You would see that $1 increase across three years, but the gradualism of that mechanism provides gradualism in the impact on rates to customers. Beyond that, trying to estimate exactly where things are going to go is tough to do.
Ralph A. LaRossa: To reinforce something Dan said—the last time we had sticker shock was due to the fact that there was a capacity market delay. Even if prices are incrementally up a little bit, you are 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 three years. Those increases sitting there caused the challenge that we had. It was not necessarily incremental, especially in what we believe is a very good mechanism in the BGS where you have this third/third/third.
Daniel J. Cregg: But for the delay in the capacity auction, you would not have seen the magnitude of the year-over-year increase that you saw.
Analyst: That is very clear. Makes sense. And then on the RBA—I know we have talked a lot about it on this call—but I saw the proposal that you filed jointly with some other EDCs. How are you thinking about the ideal things that need to be solved and would be in your favor? I saw that the load-serving entity should be the cost responsibility, but anything else that you would point out?
Ralph A. LaRossa: The key is the planning process. You really have to make sure that the planning process is a solid one and there is consensus around it. Whoever is the planner is the one that winds up with the accountability. To have the planning done by a town and then the accountability sit at the county level does not make a ton of sense—I am just using a parallel there. We need to get all of that aligned. As I said earlier, states have IRP requirements. In addition, PJM has been granted by the EDCs responsibility for transmission planning. You put those pieces together, and it is odd for that to wind up back with the EDCs.
Therefore, the LSEs—the entities that have been identified with the responsibility—are where we believe the burden should sit.
Analyst: That all makes sense. Very clear. Thanks so much, guys.
Operator: Thank you. Our last question comes from the line of Anthony Crowdell with Mizuho Securities. Please proceed with your question.
Anthony Crowdell: Hey, Ralph, Dan. Thanks for squeezing me in on a busy morning. Just a follow-up to, I think, Nick's question earlier on the nuclear upgrades and maybe the timing of them. If you could help me—when do you file for the approval for the uprates? Is that an additional CapEx opportunity, or is it further out in the five-year plan, or do you already have any included in your current plan?
Daniel J. Cregg: We have the capital for the uprate included, and the timing will depend upon which outage it goes into, Anthony. When I said 2027 or 2029—we will have an outage for those units in 2027 and an outage in 2029. Depending upon how it moves forward, that is when we will end up seeing that uprate go through. You are asking about the uprate, not the license extension, right?
Anthony Crowdell: No. More the license extension. I am sorry if I was not clear.
Ralph A. LaRossa: For the license extension, we will get information back over the next number of years. I know NRC is trying to move that a little bit quicker than they have in the past. At that point, they will let us know whether or not we have to change the oil, change the tires—what needs to be done—and we will be able to forecast the CapEx at that point.
Anthony Crowdell: And again, I know the timing is not clear with the NRC. Is that within the five-year period, or could it be outside the five-year period?
Ralph A. LaRossa: We would certainly gain consensus with NRC on the work that needs to be done within the five-year timeline, and I think the work will be completed outside the five-year timeline.
Anthony Crowdell: Great. That is all I had. Thanks so much.
Operator: Thank you. There are no further questions at this time. I would like to turn the floor back to Mr. LaRossa for closing comments.
Ralph A. LaRossa: Thank you all for your interest and for dialing in today. I know it is a busy day for many of you on the call, so I appreciate you taking the time. I am looking forward to speaking to everybody at AGA, and I will end with another thank you to our team here for the work that was completed through this past winter. The weather was not easy for us, and people continued to work above and beyond our expectations. So thank you to the team, and thank you all for calling in. Looking forward to seeing you all at AGA later this month. Take care.
Operator: Ladies and gentlemen, this concludes today's teleconference. You may disconnect your line at this time. Thank you for your participation.
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