Public Service Enterprise Group Aktie

Ladies and gentlemen, thank you for standing by. My name is Rob, and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's Second Quarter 2026 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, August 4, 2026 and will be available for replay as an audio webcast on the PSEG's Investor Relations website at https://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 Second Quarter 2026 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 or loss, 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 second quarter 2026 results.

Starting with our financial results. PSEG reported net income of $0.67 per share and non-GAAP operating earnings of $0.86 per share, bringing our first half results to $2.15 per share of net income and $2.41 per share of non-GAAP operating earnings.

Our ongoing investments in PSE&G system replacement, reliability and energy efficiency were the main drivers of growth in our financial results in the second quarter. And that PSEG Power, an increase in realized market prices, higher nuclear generation and gas operations, more than offset the absence of the zero emission certificate programs that concluded in May of 2025.

With results for the first half of 2026 coming in as expected, we are pleased to reaffirm our full year non-GAAP operating earnings guidance in the range of $4.28 to $4.40 per share. Now our operational results may have even been better as we successfully managed one of the most challenging storm restorations in our company's history.

Over the July 4 holiday weekend, a series of heat ways and successive thunder storms hit our service area, accompanied by wins of over 70 miles per hour. PSE&G reconnected approximately 380,000 customers, with nearly all customers restored within 24 hours of losing power, demonstrating the value of our system reliability investments and our crew steadfast commitment to our customers.

PSE&G's round-the-clock restoration efforts were led by over 330 crews and were supported by over 10 million proactive customer communications. In addition to thanking our employees who participated in the storm response, I also want to highlight that we worked this multi-day restoration efforts with an excellent safety record and provided PSE&G crews to help our neighboring utilities with their restorations.

We support and welcome the upcoming review of our storm response by the New Jersey Board of Public Utilities, and we will be submitting a comprehensive post-event performance report to them tomorrow, August 5.

During the heat wave, PSE&G reached a peak summer load of 10,446 megawatts, the highest level in 14 years and activated demand response part of our Clean Energy Future programs during 3 separate events in early July, helping to keep peak energy costs down for customers.

Our clean energy future programs now generate more than $1 billion in annual customer savings, helping nearly 525,000 residential and business customers save energy and lower utility bills since we began the CEF-EE program back in October of 2020.

Our EE investments have also supported approximately 9,300 jobs statewide over the past 6 years, including a network of more than 1,000 trade and union allies. We are proud of our strong performance to date in this program, including the success of our job programs, including the use of union labor for this work.

We expect to file our proposal to implement the BPU's recently adopted framework for a 1-year extension of the EE II Trinium by September 30. And more good news for customers, this month, we are implementing residential bill credits consistent with Executive Order 1 and continuing the 12-month schedule refund of approximately $166 million of the zero emission certificates that started back in June. PSE&G has also filed with the BPU to lower residential gas bills by more than 5% beginning October 1, continuing to benefit our customers with the lowest gas utility bills in New Jersey and the region.

We are also pleased to mention that PJM made a filing at FERC in June to implement a favorable prospective change to transmission cost allocation rules effective June 1, 2026. Based on public data from PJM, this prospective change will result in approximately $33 million benefit to our Sonal transmission customers for the period running from June 1 through year-end 2026, with an expected prospective annual benefit of approximately $65 million. This is another example of how we continue to advocate on behalf of our customers.

Since Governor Cheryl's inauguration, her administration has had focused on New Jersey affordability. The Governor's first Executive Board has directed the BPU to study modernizing the electric utility business model. And last month, the BPU released its consulting report, which also marked the conclusion of Phase 1 of this directive.

While no formal recommendation was issued, several examples of promising regulatory frameworks from other states and multiple reforms were highlighted. These included multiyear rate plans, performance-based rates, performance incentive metrics, earnings sharing mechanisms, decoupling and shared saving mechanisms, all of which can further alignment and transparency between the utility business model, state energy policy goals and affordability in state.

The BPU will now proceed to Phase 2 of this effort, which is expected to focus on cost discipline, financing modernization, targeting incentives and share savings and stage performance-based rate making. PSE&G will fully participate in this proceeding, and we expect to file comments by September 18. We are encouraged by the reports balanced assessment of the extent to which the business model changes can address affordability as well as the report highlighting the value of utilizing multiple criteria in its decision-making.

As we prepare for these upcoming stakeholder proceedings, combined with the growing regulatory lag that comes from our historical test year and our robust capital program, we believe there is an opportunity to bridge Governor Cheryl's call for greater accountability and transparency with our regulatory requirement to recover prudently invested capital and update our cost of service.

PSE&G's last base rate case settled in October of 2024, established a requirement to file our next base case no later than 2029. However, we have stated before that we could file sooner if conditions warranted. When you consider that we have added a significant amount of distribution rate base at a time when there have been fewer infrastructure investment programs, the alternative is more frequent base rate cases. As a result, PSE&G currently anticipates filing by year-end 2026 to update base rates.

Now turning to PSEG Power. PSEG nuclear also performed well during the quarter, supplying the grid with 7.8 terawatt hours of carbon-free 24/7 baseload generation and achieving a capacity factor of 92% that included the second consecutive breakthrough breaker run at Salem Unit 2.

As widely expected, PJM's latest capacity auction priced at $325 per megawatt day, the upper end of the price collar and fell 6.8 gigawatts short of PJM's targeted reliability requirement. This collar will remain in place during the upcoming December 2026 auction, covering capacity pricing into mid-2030. The uncapped price in the latest auction would have been $555 per megawatt day, but the reserve margin still falls well below PJM's reliability requirement.

We are continuing to review PJM's recent filings detailing the reliability backstop procurement and IRAS roles, the interim resource adequacy service formerly known as Connect and Manage, including PGM's Friday submission to FERC. As part of the bilateral phase of PJM's RBP, PSEG Power recently submitted several project proposals throughout the region that may qualify as new, dispatchable generation that could be paired with new large loads through bilateral contracts.

Turning to long-term resource adequacy here in New Jersey, Governor Cheryl recently signed a Power New Jersey Act into law, establishing a new nuclear procurement process at the BPU to procure at least 1,100 megawatts through a state-backed program. As the only operator of existing nuclear generating facilities in New Jersey, PSEG Nuclear has been engaging in efforts to enable new nuclear development at our site in Salem County since 2016.

When we obtained an early site permit from the U.S. Nuclear Regulatory Commission, one of only 6 currently issued in the United States. We believe that new nuclear generation represents a compelling long-term solution to address New Jersey's growing resource adequacy needs and support economic development in South Jersey and a successful framework for new nuclear will require an appropriate allocation of project risk.

At the same time, PSEG Power's continuing discussions with interested parties that see value in our existing nuclear production, future nuclear uprates and other generation opportunities. In summary, our teams delivered solid financial and operational results for the second quarter and first half of 2026, enabling us to maintain PSEG's full year 2026 non-GAAP operating earnings guidance.

We are also reaffirming PSEG's 5-year non-GAAP operating earnings growth outlook of 6% to 8% through 2030 as we continue to pursue opportunities incremental to our long-term forecast, including the potential to contract our nuclear output under multiyear agreements. Importantly, our solid balance sheet enables the funding of PSEG's total 5-year capital investment program of $24 billion to $28 billion without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth.

I'll now turn the call over to Dan, who will review the quarter's results and then rejoin the call for the Q&A session.

Great. Thank you, Ralph, and good morning, everybody. PSEG reported net income of $0.67 per share for the second quarter of 2026 compared to $1.17 per share in 2025, and non-GAAP operating earnings were $0.86 per share in the second quarter of 2026 compared to $0.77 per share in 2025.

These quarterly results bring first half 2026 net income to $2.15 per share and non-GAAP operating earnings to $2.41 per share. We provided you with information on Slides 8 and 10 regarding the contribution to net income and non-GAAP operating earnings by business for the second quarter and first half of 2026.

Slides 9 and 11 contain waterfall charts that take you through the net changes for the quarter and year-to-date periods over the prior year and non-GAAP operating earnings per share also by major business.

Starting with PSE&G, which reported second quarter net income and non-GAAP operating earnings of $342 million for 2026 compared to $332 million in 2025. Utilities results were driven by ongoing investment in our energy efficiency and gas system modernization program.

Referring to the waterfall on Slide 9, transmission margin was flat compared to the year ago quarter as higher investment was offset by a prior year true-up and our distribution margin increased by $0.05 per share compared to the year ago period, largely reflecting incremental gas margin from GSMP II extension roll-ins and higher investment in energy efficiency.

Compared to the second quarter of 2025, distribution O&M expense was up by $0.01 per share, reflecting an increase in operational costs due to inflation. And depreciation and interest expense each rose by $0.01 per share due to ongoing capital investments and higher long-term interest rates. And utility taxes and other had a net favorable impact of $0.01 per share.

Weather conditions during the second quarter, as measured by the temperature humidity index, were 29% warmer than normal and 9% warmer than the second quarter of 2025. As a reminder, 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 electric was about 1%, and gas was flat over the past year. The CIP is also benefiting customers as higher revenues from last year's warmer-than-normal summer weather will continue to be refunded to electric customers and PSE&G has a 5% decrease pending for residential gas customers, driven by the higher revenues from the colder-than-normal winter earlier this year.

On the capital front, PSE&G invested approximately $1 billion during the second quarter and is on track to execute our full year 2026 regulated capital investment 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 5-year regulated capital investment plan of $22.5 billion to $25.5 billion through 2030.

We completed the GSMP II extension program in 2025 and were approved to roll in $23 million effective April 2026 as planned. PSE&G continues to execute on the GSMP III program approved by the BPU last November. We expect to invest a total of $1.4 billion over a 3-year period, with approximately $1 billion of the total program receiving accelerated recovery with the balance and stipulated base to be recovered in our next base rate case.

And as Ralph mentioned earlier, we expect the rate case of more frequent base rate cases in the future as fewer clause-based IIPs cover our capital program. And since our last rate case concluded in 2024, PSE&G has made significant investments in distribution rate base to support the reliability of our system.

We continue to explore the details of the E3 consultants report addressing Governor Cheryl's Executive Order 1 related to New Jersey's regulatory construct. Elements of the report provide opportunities to enhance the transparency of the regulatory model which would be helpful for setting customer expectations as well as the inclusions of performance-based metrics, which based on our high level of service and customer satisfaction, we would welcome.

Switching to transmission and following up on the potential earnings impact of the recent legislation that could eliminate the 50 basis point RTO incentive, we estimated in our 2025 10-K, that loss of that incentive could represent an annual headwind of $40 million of net income or approximately $0.08 per share.

Last February, we considered the possibility that the RTO incentive earnings might be eliminated at some point when we rolled forward our long-term non-GAAP operating earnings guidance to 6% to 8% through 2030. I would also note that the effective date of this legislation is January 2027, so there will not be an impact on 2026 results.

Moving now to PSEG Power & Other. For the second quarter, PSEG Power & Other reported a net loss of $8 million in 2026 compared to net income of $253 million in 2025. And non-GAAP operating earnings were $83 million in the second quarter of 2026 compared to $52 million in the second quarter of 2025.

Returning again to the waterfall on Slide 9. For the second quarter of 2026 versus 2025, net energy margin rose by $0.08 per share, driven by higher generation volume, higher capacity prices and higher gas operations, partly offset by the absence of those zero emission certificates and the LIPA-related fuel and energy management fees.

O&M was flat compared to the second quarter of 2025 and interest expense rose by $0.01 per share, reflecting incremental debt at higher interest rates. Lastly, taxes and other items had a net unfavorable impact of $0.01 per share in the second quarter compared to 2025.

In July, PSEG Nuclear cleared approximately 3,600 megawatts of its eligible nuclear capacity in PJM's base residual auction at $325 per megawatt day for the energy year beginning June 1, 2028, and going through May 31, 2029. This latest result represents a modest decline from the $333 per megawatt day price set in the prior PJM capacity auction.

Touching on some recent financing activity. PSEG had strong available liquidity totaling $3.4 billion as of the end of June. This includes approximately $200 million of cash on hand. On the financing front, in June, PSEG issued $500 million of 4.8% unsecured senior notes due 2031 and used the proceeds to prepay $500 million of a 364-day term loan initiated in February of 2026.

PSEG's level of variable rate debt represented approximately 3% of our total debt as of the end of June. Our variable rate debt consisted of the unhedged portion or about half of the $500 million 364-day term loan at PSEG Power maturing in December of 2026 and commercial paper.

Looking ahead, our solid balance sheet continues to support the execution of PSEG's 5-year capital spending plan, dominated by regulated CapEx without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth.

In closing, we delivered solid operating and financial performance in the second quarter and first half of 2026, enabling us to maintain PSEG's full year 2026 non-GAAP operating earnings guidance of $4.28 to $4.40 per share. We're also reaffirming our 6% to 8% compound annual growth rate for non-GAAP operating earnings outlook through 2030 based on our confidence of executing our 5-year regulated capital investment plan, that also supports a 6% to 7.5% compound annual growth in rate base over the same period.

We continue to pursue nuclear revenue opportunities, competitive transmission projects and incremental utility infrastructure projects, including making incremental system investments to connect solar and battery storage resources to the grid to meet new demand which could provide upside to our current growth outlook through 2030.

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

[Operator Instructions] The first question is from the line of Nicholas Campanella with Barclays.

So I guess, Ralph, you said in your prepared just in regards to the base rate filing, you kind of talked about fewer investment infrastructure programs and the alternative is just more frequent base rate cases. Can you maybe juxtapose that against the BPU report? And how much of the decision to file is on the back of the report versus, I guess, anything that's transpired from the RTO adder that you brought up or the EE spend? And then what parts of this report and recommendations do you think make it into this base rate review?

Yes. Thanks, Nick. So I don't expect a lot to make it in this base to this filing. And that's exactly why I think the timing of the filing aligns pretty well with the state's goals here. I think for all of us, as we look at the E01 report, we see a state that's looking for a little more transparency, a little more performance-based ratemaking and potential for some multiyear rate plans. To be set up appropriately for that, you need a base rate case. And so the timing of that aligns with the fact that we haven't had anything on the electric side and upwards of 5 years for an IIP kind of puts us in a place where this makes a ton of sense for us right now. And I think it makes a ton of sense for the state.

If you look across the utilities in New Jersey, most of the gas utilities have been in for a rate -- a base rate case. And I think we heard from some of the others in New Jersey, the other electrics that they were planning to come in and I think Orange Rockland just settled. So if you look across the spectrum, we think this fits and it would keep us from being an outlier as we go into the next phase of E01.

Okay. And then maybe just a lot kind of changed since you gave the 6% to 8%, and I know you're reaffirming that today. But I guess you're maybe pulling forward a base rate review. There's the RTO adder that's out there that I know you addressed is not going to be really impactful until '27. Just taking into kind of account the moving pieces, just where do you kind of see yourself in this range?

Yes. Nick, we see ourselves in the 6% to 8% as we've been saying. So that hasn't changed. We reaffirmed. We believe there's other opportunities that are presenting itself in the industry that we have opportunities to participate in. I think you talked -- we talked a little bit about the RBA, a few other things that are happening at PJM, our potential upgrades at our nuclear plant that we've talked about quite for a few different times on these different calls. So we remain confident in the 6% to 8%. And the RTO adder was one of the scenarios that we had planned for. .

The next question is from the line of Richard Sunderland with Truth Securities.

Picking up the RBA commentary here, can you speak a little bit more to the project proposals? And I guess any way to frame the scale and type of opportunity that you're seeing for PSEG Power in that?

Yes. No, Rich, thanks for that. So look, I think people have -- in some degree, forgotten a little bit about the capabilities that we have inside the company as it goes to generation. We were one of the -- we built some of the last generation plants in PJM and certainly PJM East when we completed the Warren and Keys. We exited that because it was a market-based solution that really existed and was not something that we were -- we wanted to be part of.

Now as PJM is moving into this RBA and there's more opportunities for long-term PPA type or utility-like agreements, we see an opportunity that might present itself. So we've got a few opportunities, we think, inside New Jersey, if you outside New Jersey that we're taking a look at. And I don't want to go much further than that right now because things are still changing at PJM and we'll read the tea leaves on that, just like everyone else is. I think even the load forecast is going to change. We saw some things on that as recently as yesterday.

So as those opportunities present themselves, we'll look at it. But we have a skill set here that exists and we kept the people. Just for those that may not recall, when we did exit the fossil business, we offered those employees an opportunity to stay along with us in the utility and many people did at all sorts of levels in the organization. So we think we've got the skill set to put that group back together, and we think that there's opportunities now that are more utility-like, which kind of align exactly what the investments we're looking to make.

Got it. That's super helpful. And then, I guess, turning to the PSE&G side, but in similar light to a few of the opportunities you outlined in terms of the 6% to 8% range and upside. Can you speak a little bit more to what you're focused on right now in terms of capturing some of that distribution investment upside or other areas of focus and kind of the time line to crystallize that and have a view on what may move into the plan over the next few years?

Yes. Look, we'll roll forward our CapEx at the beginning of next year as we have in the past couple of years. So that cycle is going to remain the same. I think our gas distribution business is focused as it always has been on replacement of cast iron. That's still something that I don't see changing.

I think on the electric side, you've seen a lot from Governor Cherly's administration about being ready for solar, more distributed energy resources, batteries and so on. And I think that you'll see more alignment with our last mile conversations that we've had over the last few years and are -- they have a specific PSUP program that they've talked about at the Board of Public Utilities as the new Board President gets his feet under him at the Board there. I think you'll see a little more focus on driving the electric utilities in that direction. And any updates we'll have will roll out in the first quarter of next year.

The next question is from the line of Carly Davenport with Goldman Sachs.

Just 2 questions on the power side for me. One, could you provide any updates in terms of hedging activity beyond 2026, so where you are in '27 or '28 at this point?

Carly, there's nothing incremental for us to disclose. There's nothing in the materials that we have disclosed. We're working our way through for the future years as we step through time.

Okay. Got it. And then I guess as you're thinking about potentially getting towards more regulatory certainty in PJM. I'm curious if you have seen any inflections in interest from data center or other large load customers for PPAs at power relative to prior quarters?

Yes, I wouldn't say there's inflections, Carly. I think there's been some continued interest in pursuit on some things. I think that continues. I think the process in PJM is something that people have, I think, for the past few months. No one is out there, they try to figure out where it's going and what it's going to mean from the standpoint of new load. And I do think that this whole RBP and IRAS processes are going to help folks figure out what is going to be expected of them so they can work against that backdrop.

And so I think really the only change we've seen is just maybe just a caveat in the discussions related to the fact that if something has to happen, they are not boxing themselves in through any kind of an agreement to trouble that thing that they need to stay in compliance with. But I wouldn't call it inflections, I would just call it people reading the context of where we are with respect to PJM.

The next question is from the line of Michael Sullivan with Wolfe Research. .

Ralph, on the BPU review that's ongoing, any sense to when that's just fully wrapped up? And then on the rate case that you're about to file, any sense of size of rate increase or could it potentially be a decrease to align with the governor. How should we be thinking about that?

Yes, Michael, I would say the next step is phase 2. I think you've all that information is in the public, and I don't want to front-run anything at the BPU. I think they've got their own time line. And as I mentioned, we've got a new President at the BPU who is getting up to speed and we'll see what -- if he wants to make any changes to the time line that was published, but I don't expect that to be the case.

And then as far as our rate case goes, look, we haven't disclosed anything more on that, and I'll leave. We wanted to signal to you all that we were getting aligned again with the state and the timing that was going to be required to adequately execute on E01. And so put those 2 pieces together, and we wanted to make sure that we're transparent about that with the investment community. So we get that information out, but no more details on that at this time.

Okay. Great. And then on the power side, can you just give a sense of to the extent you're pursuing opportunities in the RBP, what sort of returns you'd be targeting and how the math works with the $555 price cap in there?

Yes, that's a great question, I'm going give that to Dan. Look, I think a lot of that is a TBD, Michael, but it's -- right now, the way that process is set up, you have to raise your hand first. And so we've raised our hand and we wanted to, again, remind folks that we're in that business, but I'll give turn it to Dan for a little bit more.

Yes, Michael, we see potential in what is there to explore and determine whether something there is going to be attractive. It would be foolish to provide what an expectation would be of returns in a competitive situation, so I won't do that. But I do think that there's enough there for us to be interested in exploring getting into the process and seeing if it meets the criteria, which what we've talked about is whether it's going to be utility-like or contracted enough to be attractive to us. And so all of those elements that I just talked about go into kind of risk and you're going to compare your return to the risk that you're taking. So obviously, it's more complicated than just providing a number to you with respect to what the return would be.

Michael, I just -- let me just double down on what Dan said regarding the risk profile in the utility like, I just want to reinforce that. We said it through an earlier question as well, but that's really important to us. However, I do think that, as you said, there's some more clarity in the PJM regulatory construct they're putting together. I think it's getting closer to utility-like with at least some of these opportunities that exist.

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

I just wanted to go back to the bilateral discussions as you touched on before. And sorry if you had already said this, but in these conversations for -- with bilaterals, is it interest in existing assets or both? Or how should we think about that?

Yes, I think it's both, but more interest in new, right? If you think about the entire tone I think across the country with respect to new load coming on, you don't have discussions about new load coming on with at least a preference for having incremental generation to join that. So I think there's also an understanding of the new generation takes a while to come on. And so I think there is a preference to have something new to kind of fit within that overall dialogue. But I would say there is not solely an interest in new is how I would describe it.

Got it. And so is there -- is it like kind of a 1:1 would you say? Or is there any ratio or this all just going to vary?

There's not a fixed ratio is just a preference that's all.

Got it. One last quick one, if I could. Obviously, a lot of new supply needs, how do you think new nuclear could fit in here? Do you think the -- it is possible or it's just too far off at this point, just any thoughts there would be great.

I think, Jeremy, you asked -- you kind of answered your own question there, is it potentially too far off, right? It depends upon the time line that you're looking at. I do believe that new nuclear makes sense, as we said in the prepared remarks, I think it's aligned again with the policies of the state. So we've always done that. And so we're trying to enable that as best we can. Whether or not those units, whether it's in New Jersey or across the country come on quick enough for some of the load that's looking to connect, these are 12 years -- 12-year long projects. I won't revisit what's happened in the past. So we need short-term solutions as well as long-term solutions. And I think that the new nuclear certainly falls in the long-term bucket.

And even if you take a look at what the RBP is talking about, they're talking about it in 2032. So that's half the time to get to 12 years that Ralph just talked about. So I think there's near term, medium term and long-term nuclear certainly on the longer term.

Next question is from the line of Rinny Singh with Bank of America.

I guess first on the comments around the Phase I study. There's a pretty broad range of reforms that they proposed. I guess, how are you thinking about as we move forward this negotiation and your input into the stakeholder process and what would have the most merit in New Jersey, both like as utility owners and then the conversations with the BPU?

Yes. I think look, we see multiple paths and you kind of said there's multiple things that they put forth in E01. I thought they really just put forth a number of options but not necessarily a number of reforms, right? There's multiyear rate plans, there's performance-based rates, but these are things we've seen before in the industry. And that will provide more transparency for our customers. So I welcome everything that's being discussed. I think more transparency for customers is helpful for us especially when you have some of the billing cycles like we've gone through. I think one of the best things that came out of the report was the reference to only 25% of the bill is distribution. And I think that was the number that was quoted in E01. So I look at that and I say, I welcome the transparency. I think that's very helpful for us as a company. .

And from a performance-based rates, we started the prepared comments as we do always with financial but move quickly into operational because we are very proud of the operational results that we have as a company. And so from a performance-based rate standpoint, we welcome that. So I kind of tie those 2 pieces together, and I think the path that we see are all positive. I think we have all the devils of details, and we'll work through that with policymakers, but I feel pretty good about where we are. And I think that our final of a base rate case shows our willingness to be aligned from a timing standpoint with the next steps that we'll see in this process.

Okay. That makes sense. And then I think that kind of gets to my second question. Power is a big portion of the cost increases. And we have this RBP structure and the cost is kind of allocated down to the state basis. How do you think about the process there and the time line for states, I guess, specifically New Jersey to create this cost allocation basis? And what -- is it kind of favorable in that regard that it is down to the states? And then I guess on the flexibility procedures, how are you thinking about the mandatory flexibility down to the transmission owner tariff versus PJM just dictating it?

Yes. Look, I think that there's still -- again, we got to look for a little more detail. We got to see what comes out of FERC when they finally approve everything. But the state will be involved because the VP will have some time lines that they'll have to meet right now, I think it's set up at 12 months, but we'll see how that changes over time, and I don't want to be locked into anything specific there until we see what comes out of FERC. But I do think that working together with the BPU, we can be very helpful here.

And I'm going to point to something that recently happened, which is the transmission cost allocations process where we had -- I think it was in, again, in our prepared remarks, where we talked a little bit about how some of that cost allocation was done in working with the state, we now, as recently as, I guess, the last 2 days, we saw that, that filing that we have made for the cost allocations was improved by FERC. And the result is going to be a $65 million a year savings going forward, that's not just a onetime that's every year going forward for our customers. So we've proven we can work with the state in that particular case. That cost allocation was something we really advocated for strongly as a company ourselves. And then we worked with the state to get over some of the last-minute hurdles here. And I think we can do the same when we get into this -- in the RBA. I think we'll be able to figure out exactly the right way to do this to help from a customer cost standpoint as best we can.

Next question is from the line of Sophie Karp with KeyBanc.

It's been discussed already from several angles, but maybe let me try this one. Are you guys seeing attractive opportunities to contract bilaterally for new builds like outside of the PGM construct, like not as a part of the immediate bilateral auction, but on your own with customers to facilitate their large load build-out in the PGM footprint, some of your peers are trying.

Yes. So I'm going to give that to Dan. I just want to say PJM isn't the only process that's being stood up right now to go through these bilateral contracts. So it's a great question. I'll give it to Dan.

Yes. I think to the extent that you are new load, you're going to end up getting pushed into that. But I also think that there's states that are seeing their supply-demand balances not necessarily where they want them and may be looking to do something to prompt some generation there. And so I think that's got some potential as well.

I think to your question, it sounded like, are you seeing folks come in and in particular, new load looking for new generation, I think that will get caught up into that RVP process though. So I think there are other venues, and I think we've got one of the best sites that are out there with respect to the infrastructure in place, but we'll see what happens throughout as we go forward through a couple of different processes as they move forward.

And maybe just to build on that, as you consider these types of investments, how do you think about the target IRR or return that you would need to jump on to that, like what's your thinking process here?

Yes. Sophie, I'm going to, again, just kind of give -- reinforce something Dan said earlier, it all depends upon the risk, right? And we have said we don't want to be in a high-risk market. I would consider PJM marketplace to be high risk. We're looking for utility-like returns. So I think in saying that utilities like investments, we're saying utility-like returns because we're looking for a utility like risk and I don't want to go much further than that other than just to reinforce utility-like, utility-like, utility-like.

The next question is from the line of Ryan Levine with Citi.

Given given the New Jersey BPU and other PJM stake level discussions around virtual power plants, how are you thinking about the opportunity for PEG?

Yes, Ryan, thanks. Listen, I think from a PEG standpoint, again, it's an opportunity for us to show alignment with the state policy. There's not a tremendous financial opportunity on the VPP side that we see, I think, maybe nationwide, if you were in that game or you're doing other things. But for our New Jersey customers, it's more about aligning with policy and enabling that policy than it is about a financial return.

Okay. But are there any initiatives that you have underway to address that alignment?

Yes, we have some -- I think we've worked with BPU on a couple of different items where we've put forth some pilot programs. And I think they're going to initiate more of a process there. So again, we'd be front running them if we got ahead of that curve. But we've done that more through the regulatory conversations than we have with actual implementation of programs. But we do have some pilots that we've proposed.

Next questions are from the line of Paul Patterson with Glenrock Associates.

Just wanted to sort of follow up on the expected rate case and what have you. And sort of get your -- and I apologize if I missed this, but the energy efficiency order that came out and how you see that, what is that -- it seems a little unusual in terms of their return and what have you. I'm just wondering if you could sort of give me a better feeling for what -- how you see that in the whole context of the regulatory environment there?

Yes. Look, I look at that as a very specific piece of the regulatory process, not overarching. I think, again, the state is looking for affordability. So understand the goals that were put forth in that framework. But it is a framework, it's not mandated. So we have the opportunity to talk about how our programs differentiate from others. I think one of the biggest ones for us is our use of union labor and the percentage in which we use unit labor to achieve the goals that were put forth for all of the -- for us by the BPU. So I do think we have some differentiating factors and we're in a work discussion.

I also think that it's important to note that this is prospective from an asset standpoint. This is dealing with the extension assets, the dollars that we're putting forth to support that investment, not for all the investments. So that's also important. And I think it's also a reflection of the amount of, I'd say, the loan program, the on-bill financing that we're doing and the perceived risk around that specific part of the program. So there's a lot of specifics in what I just said to you, which makes it kind of unique and it's consistent from an affordability standpoint, but it's unique from an investment standpoint as we think about it.

Okay. Great. And then just back on nuclear, I just -- I'm wondering if you could give a flavor for what stakeholders actually think or what their comprehension about what the affordability impact of nuclear might be. I mean, this is around the country. There seems to be bipartisan buy into this, and I understand its appeal. But I'm just wondering, when you're speaking to policymakers, et cetera, or maybe you can tell me if there's been a big change in the cost of nuclear, I mean I know there's this SMR technology, et cetera. But I mean, is there -- do you think there's a full understanding about I mean, with respect to this buy-in about what cost of new nuclear might be? Do you follow what I'm saying?

Yes. Look, I think there's plenty of levelized cost of energy reports out there that give policymakers a clear line of sight into what the costs are going to be. I think there's a question about the timing of the projects coming online and when -- what the cost will be at that point, right? So that's always a conversation that you have with policymakers. I think the biggest open item for everyone is, while there's bipartisan support for building new nuclear, there's also bipartisan support to protect rate payers from cost overruns. And so the question comes down to where do we -- how does that risk get adequately allocated amongst the players in any given project. And that's why whenever we've talked about it, we've talked about enabling new nuclear because of the concern that we have about how does that become utility like if there's high risk associated with it.

So more to come on that. I think we're, again, very well positioned. I think our site is very well positioned, and we look forward to doing what we can to enable new nuclear in New Jersey. But I think to your specific question, is there a line of sight for policymakers on the cost. I think there's plenty of studies out there, and I think there's plenty of conversation about where these costs are and more importantly, where they could go to.

Our final question is from the line of Travis Miller with Morningstar.

You answered most of my questions, a lot of the details. I appreciate it. Just one quick follow-on. E01 in the process from here, is the ball now in your court in terms of putting together proposals best ideas, stuff like that to present to the BPU? Or are you still waiting for some more guidance either from government's office or BPU or some other entity before you start putting filing up?

Yes, Travis, there's a clear phase 2 that the Board of Public Utilities will go through as the next step in this process. So we'll participate in that. We'll have comments. There's plenty of stakeholder meetings that have been scheduled by the Board that we will participate in and others. So it's more at this point, still an open item that we wait for finalization of the orders from the Board of Public Utilities.

Okay. So you think in terms of putting together actual proposals and stuff that comes after the base rate case, give or take?

Well, no, I think we said we filed by the end of the year. There's a time line associated with that. If you kind of play it out, there'll be some sort of a framework that will come out for a VO1. I would expect that to happen in the last quarter, beginning of next year, put that framework together, and now you've got your base rate filing that's been recently approved or is out to be approved, that's for any utility in the state. And then you can start to move efficiently into the next framework because you've got that base to work off of.

Okay. That makes sense. Well, a lot of work to do in '27, stay busy. .

Thanks, Travis. .

At this time, I'll turn the floor back to Mr. LaRossa for closing comments.

Well, thank you. Just a couple of things. I appreciate all the interest. As always, just want to reinforce the way we started, which was on the great work by the teams here in New Jersey and in Long Island to respond to the storms over the July 4 holiday season and just the fact that people were away from their families and from their barbecues and from everything that they wanted to be doing otherwise during that weekend. Without that operational excellence, we couldn't even be having conversations about what we can potentially do moving forward.

And I think as I look forward, we've continued to get more regulatory clarity, both at PJM with some of the steps that they've taken and how that might play out on the generation side, and here in New Jersey on the distribution side as we move through E01 process and ongoing conversations there. So regulatory clarity is starting to take place. And then I think on top of that, there's opportunity sets that remain in front of us that are presented both by the regulatory clarity of PJM and in New Jersey as it pertains to that last mile and getting the system ready for the solar and batteries that we know we need in the near term. So I'll put all those pieces together, and I feel pretty good about where we are.

So I look forward to the next time that we're together, and I'll just end by wishing Carlotta a belated happy birthday for all of you that are on the call and interact with them all the time. When you give abuzz next time, just make sure you say happy birthday. Thanks for dialing in.

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

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 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.

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 Shar 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 [ Konstatin ], 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 [ RBA ]. 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 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 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.

Ladies and gentlemen, thank you for standing by. My name is Rob, and I am your event operator today. I'd like to welcome everyone to today's conference, Public Service Enterprise Group's Fourth Quarter and Full Year 2025 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, today's conference is being recorded today, February 26, 2026, and will be available for replay as an audio webcast on PSEG's Investor Relations website at https://investor.pseg.com. I would now like to turn the call over to Carlotta Chan. Please go ahead.

Good morning, and welcome to PSEG's Fourth Quarter and Full Year 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-K 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 all for joining us to review PSEG's fourth quarter and full year 2025 financial and operating results, our financial outlook for the year ahead and our long-term projections through 2030. But before I dive in, I'd like to thank our employees who once again this past week, prepared and restored our system from yet another intense combination of winter weather that brought over 2 feet of heavy snow, single-digit temperatures and 60 mile per hour winds to our service areas in New Jersey and Long Island.

I can't say enough about our crew's dedication throughout this entire winter season, working in freezing conditions to keep the lights on and our customers warm. Now starting with our financial results. PSEG reported net income of $0.63 per share for the fourth quarter and $4.22 per share for the full year of 2025. Our non-GAAP operating earnings were $0.72 per share for the fourth quarter and $4.05 per share for the full year of 2025.

Also earlier today, we announced our dividend declaration for the first quarter of 2026, setting the indicative annual rate at $2.68 per share. This is a $0.16 per share increase, an increase of approximately 6% over last year's dividend and higher than last year's increase of $0.12 per share, all reinforced by our confidence in our long-term projection. Starting with operations.

On February 7, 2026, we hit a seasonal gas send-out peaks when temperatures dipped below 10 degrees Fahrenheit, registering the fifth highest send-out in our history. During that same cold snap, PSE&G's appliance service business responded to nearly 2,000 no heat calls per day compared to an average of 600 calls on a typical winter day. And our electrical systems also performed well with a comparatively small group of customers affected and PSE&G was able to restore service to virtually all customers within 24 hours.

Beyond the storm seen in 2026 to date, PSEG's full year results for 2025 were achieved while facing multiple severe storms and extreme weather events throughout the year that stressed our electric and gas systems. PSE&G's response guided by our operational excellence model achieved excellent results in safety, reliability and customer satisfaction measures. I'm also very proud of the work PSEG is doing in support of New Jersey's efforts to minimize utility bill increases.

Last July, we implemented several summer relief initiatives in cooperation with New Jersey regulators to help our customers manage the impact of PJM-related electric supply costs that PSE&G passes through to customers. The latest example of our efforts occurred on February 1 when PSE&G held its residential gas rate flat for the remainder of the winter 2025 through 2026 heating season.

Extending the stability of our gas rates further highlights PSE&G's favorable residential gas build profile which is not only the lowest cost in the state, but also the lowest in the region. And there's more good news to report on the customer front. Earlier this month, the New Jersey Board of Public Utilities approved the results of the latest electric supply auction, known as the Basic Generation Supply Auction or BGS, which will result in a 1.8% reduction in the average monthly bill for PSE&G residential electric customers starting June 1 when seasonal electrical use is at its highest.

Over the next several months, we will introduce even more ways to help our customers manage and save on their utility bills with increased budget billing education, new time of use rates and more energy-efficiency solutions. PSE&G also received approval to extend its 3-year GSMP III program, which will continue our efforts to reduce methane emissions of powerful greenhouse gas.

We note that our cumulative progress from these programs has reduced our methane emissions by over 30% system-wide from 2018 levels. And recent winter weather has validated how effective our gas system investments have been by reducing both the number of pipe breaks and low-pressure issues compared to similar low-temperature events in the past. Our operating performance continues to be a positive differentiator in the state and the region.

PSE&G received the 2025 ReliabilityOne Awards outstanding system resiliency, outstanding customer engagement and for the 24th year in a row, outstanding reliability performance in the Mid-Atlantic region. PSE&G ranked #1 in customer satisfaction among large electric utilities in the East region according to the J.D. Power 2025 U.S. Electric Utility Residential Customer Satisfaction Study, marking the fourth consecutive year PSE&G has earned the top position in this segment.

And PSEG Long Island, yes, PSEG Long Island ranked #1 in customer satisfaction among large electric utilities in the East region according to the J.D. Power 2025 U.S. Electric Utility Business Customer Satisfaction Study, capping an 11-year rise from the bottom of the ranking since PSEG Long Island took over the operation of the electric grid on Long Island. And by the way, PSE&G was #2 in that same study.

Finally, PSEG Long Island was awarded a 5-year contract extension to continue as the electric transmission and distribution operator on Long Island and the Rockaways through 2030. We look forward to continuing our constructive partnership with LIPA that has enabled us to become the best-performing overhead electric service provider in New York State and like PSE&G in New Jersey, a top performer nationally for reliability and safety.

2025 was a successful year for our company, both operationally and financially. PSE&G executed on its capital plan, investing approximately $1 billion in the fourth quarter and approximately $3.7 billion in total for the year in regulated capital spend. On the generating side, PSEG Nuclear posted a 91.2% capacity factor for the full year, producing approximately 30.9-terawatt hours of 24/7 carbon-free baseload power for the grid, including during the intense June 2025 heat wave when New Jersey needed it most.

PSEG's non-GAAP operating earnings for 2025 were at the high end of our narrowed guidance range of $4 to $4.06 per share, extending management's track record of delivering results that either met or exceeded our earnings guidance for the 21st consecutive year. Turning to our outlook for 2026. First, we initiated a non-GAAP operating earnings guidance in the range of $4.28 to $4.40 per share, an increase at the midpoint of 7% over 2025 results.

Our 2026 guidance is based on our investment program at PSE&G and expected nuclear output realizing market prices that exceed the nuclear PTC threshold, and we are approximately 95% hedged for the remainder of 2026. We will also keep to our long-standing practice of stringent cost control and continuous improvement to support affordability and benefit our customers.

Second, we updated PSEG's capital program to $24 billion to $28 billion for the 2026 to 2030 period, with over 90% focused on regulated investments. Regulated capital spending is forecasted in the range of $22.5 billion to $25.5 billion and supports a rate base CAGR of 6% to 7.5% over the same period. And our solid balance sheet supports execution of this robust 5-year capital plan, still without the need to issue equity or sell assets.

With these updates, we are raising PSEG's long-term non-GAAP earnings growth outlook to 6% to 8% through 2030. This higher growth rate is supported by our best-in-class utility operations executing on a customer-focused infrastructure modernization and energy efficiency investment programs. This regulated growth is supported by nuclear generation ownership, a significant cash flow generator and therefore, a differentiator among our peers.

Potential growth beyond our forecasted 6% to 8% CAGR range could be achieved through opportunities to contract existing and additional generating output and through incremental regulated capital investments. The supply-demand dynamic we are seeing in New Jersey has prompted executive orders to be issued to explore supply options, including the development of an additional 3,000 megawatts of community solar and battery storage.

We have been cooperatively working with policymakers since last November, and we look to help New Jersey achieve the high priority goals of these executive orders, which include the exploration of regulatory reform. The executive orders also direct the BPU to provide for residential universal bill credits to again offset electricity supply rate increases. We look forward to constructive dialogue with the BPU on these issues.

Now turning to the legislative front. In the past few days, a bill was reintroduced in the state legislature to establish a new natural gas power plant procurement program at the BPU and incentivize the development of new natural gas power plants in the state. This gas bill pairs with an earlier bill that establishes a new nuclear procurement program also within the BPU that was introduced at the start of this legislative session.

We look forward to working with policymakers to advance energy strategies and resources that secure affordable, reliable and diverse energy supplies and support legislation that would increase competition for generation supply should New Jersey decide to pursue new in-state generation. And as we have previously mentioned, we are well positioned to help meet that need.

We have sites with grid connection capability and pipeline supplies as well as the in-house expertise to build new supply here in New Jersey with prevailing wage labor. I will now turn the call over to Dan, who will walk you through our 2025 financial results and the outlook for 2026 and then rejoin the call for Q&A.

Thank you, Ralph, and good morning, everyone. PSEG reported net income of $4.22 per share for the full year of 2025 compared to net income of $3.54 per share for 2024. Non-GAAP operating earnings for the full year of 2025 were $4.05 per share compared to $3.68 per share for 2024. For the fourth quarter of 2025, net income was $0.63 per share compared to $0.57 per share in 2024 and non-GAAP operating earnings were $0.72 per share in the fourth quarter of 2025 compared to $0.84 per share in 2024.

Slides 8 and 10 detail the contribution to non-GAAP operating earnings per share by business segment for the fourth quarter and full year of 2025. Slides 9 and 11 contain waterfall charts that take you through the net changes for the quarter-over-quarter and full year periods in non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported fourth quarter net income and non-GAAP operating earnings of $352 million for 2025 compared to $378 million in 2024.

For the full year, PSE&G had net income and non-GAAP operating earnings of $1.75 billion in 2025 compared to $1.55 billion in 2024. Utilities results for the full year were driven by the implementation of new electric and gas base distribution rates that took effect in mid-October 2024 to recover a return of and on previous capital investments totaling more than $3 billion and higher working capital balances.

Compared to the fourth quarter of 2024, distribution margin increased by $0.07 per share, mostly reflecting incremental gas margin from the third quarter GSMP 2 roll in, an increase in the number of customers and higher gas demand. Higher investment in energy efficiency also contributed to distribution margin in the quarter. On the expense side, distribution O&M increased $0.04 per share compared to the fourth quarter of 2024, primarily due to higher reserves and operational costs.

Depreciation and interest expense rose by $0.02 per share compared to the fourth quarter of 2024, reflecting higher levels of depreciable plant investment and long-term debt at higher interest rates. And lastly, distribution-related taxes were $0.05 per share higher due to plant-related taxes and lower write-offs related to bad debt compared to 2024. Weather during the fourth quarter, as measured by heating degree days, was 9% colder than normal and 23% colder than the fourth quarter of 2024.

And as a reminder, the Conservation Incentive Program or CIP mechanism decouples weather and other economic sales variances from a significant portion of our distribution margin, all 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 the residential customer growth for both segments was approximately 1% in 2025.

On the capital front, as Ralph mentioned, PSE&G invested approximately $1 billion during the fourth quarter. And for the full year 2025, our capital spending totaled approximately $3.7 billion with continued investments in infrastructure modernization, energy efficiency and supporting growing customer demand. For 2026, our planned capital investment program for the regulated business is approximately $4.2 billion.

We also rolled forward our 5-year regulated capital investment plan through 2030, amounting to $22.5 billion to $25.5 billion, and that compares to our prior plan of $21 billion to $24 billion. The $1.5 billion increase in regulated investments is primarily driven by anticipated load growth due to data centers and other new customers plus other incremental distribution reliability and resiliency investments.

Our 2026 to 2030 regulated capital investment plan is expected to produce a compounded annual growth in PSE&G's rate base of 6% to 7.5%, starting from a year-end 2025 balance of approximately $36 billion, which includes construction work in progress. These investments help us maintain our best-in-class reliability and customer service as well as meet New Jersey's energy savings goals.

Earlier this month, the BPU certified the results of the annual New Jersey BGS auction that was held to secure electricity for customers that have not selected a third-party supplier. And based on the competitive auction results, the cost of electricity supply on PSE&G residential electric bills will decline by 1.8% starting June 1, 2026. This decrease reflects the net impact of a lower overall 2026 BGS price that will replace the 2023 auction result that contained higher energy costs.

Moving to PSEG Power and Other. For the fourth quarter of 2025, PSEG Power and Other reported a net loss of $37 million compared to a net loss of $92 million in the fourth quarter of 2024. Non-GAAP operating earnings were $10 million for the fourth quarter compared to non-GAAP results of $43 million for the fourth quarter of 2024.

For the full year, PSEG Power and Other reported net income of $366 million in 2025 compared to $225 million in 2024, and non-GAAP operating earnings were $284 million in 2025 compared to $292 million in 2024. Referring to the fourth quarter waterfall on Slide 9, net energy margin was flat compared to the prior year quarter as higher gas operations were offset by the absence of zero emission certificates and lower generation volume due to the scheduled refueling at our 100% owned Hope Creek nuclear plant.

O&M was $0.04 per share higher compared to the fourth quarter of 2024, mostly driven by that Hope Creek refueling outage. As Ralph mentioned, PSEG Nuclear also completed work during the Hope Creek refueling outage to transition the unit from an 18-month to a 24-month refueling cycle going forward, which will yield additional megawatt hours as well as O&M savings over the long term.

Depreciation expense was $0.01 per share favorable and interest expense rose by $0.04 per share, reflecting incremental debt at higher interest rates. Nonoperating expenses were $0.02 per share higher, driven by a contribution to the PSEG Foundation and taxes and other were $0.01 per share favorable compared to the year earlier quarter.

On the operating side, the nuclear fleet produced approximately 7.2 terawatt hours during the fourth quarter of 2025 compared to approximately 7.3 terawatt hours in the fourth quarter of 2024. And for the full year 2025, nuclear generation was approximately 30.9 terawatt hours, up slightly from 30.6 terawatt hours in 2024. Capacity factors for the nuclear fleet were 83.7% and 91.2% for the quarter and full year of 2025, respectively.

Touching on some recent financing activity. As of the end of December, PSEG total available liquidity remains strong at $2.8 billion, including approximately $130 million of cash on hand. Liquidity was supported by solid cash from operations during 2025. On the financing front, in December, PSEG Power amended its existing $400 million 364-day variable rate term loan, which increased the balance to $500 million and extended its maturity to December of 2026.

PSEG's variable rate debt at the end of December consisted of the 364-day term loan at Power for $500 million, which matures in December this year and commercial paper. As of December 31, our level of variable rate debt represents approximately 6% of our total debt. Looking ahead, our balance sheet supports the execution of PSEG's 5-year capital spending plan through 2030, which is dominated by regulated CapEx without the need to sell new equity or assets and provides the opportunity for continued dividend growth.

Funds from operation to debt is projected to be in the mid-teens through 2030, comfortably above our minimum threshold. Now before I conclude my remarks, let's review some earnings drivers for 2026 as outlined on Slide 5. First, we're starting with higher rate base of approximately $36 billion at year-end 2025, and that's up about 7% over year-end 2024. In addition, clause-based recoveries for investments in distribution infrastructure and CEF Energy Efficiency II are expected to contribute to utility margin.

And as we discussed on the third quarter call, PSE&G's annual FERC transmission formula filing was implemented on January 1 with an $82 million increase in annual transmission revenue subject to true-up. On the distribution side of the business, electric base rates for 2026 are projected to be stable. At PSEG Power & Other, our expected generation output for 2026 is approximately 95% hedged.

Like last year, we do not expect to book nuclear PTCs in 2026 due to the higher price environment. And just as a reminder, the zero emission certificate amounts earned by our New Jersey nuclear units concluded in May of last year. Our nuclear refueling cycle for 2026 includes a spring refueling at Salem Unit 2 and fall refuelings at Salem Unit 1 and Peach Bottom Unit 2.

Hope Creek is scheduled for its next refueling in the fall of 2027, following the completion of fuel cycle extension work in the fourth quarter of 2025 and a shift to a 24-month refueling outage schedule. As we continue to stringently manage our controllable costs, we will see interest and depreciation expense that will rise with a higher investment balance at PSE&G and higher interest expense at PSEG Power and parent related to refinancing maturities at higher current interest rates.

In closing, we are proud to have delivered on our 21st year in a row of meeting or exceeding our earnings guidance, and we carry that confidence forward to our full year 2026 non-GAAP operating earnings guidance of $4.28 to $4.40 per share, 7% higher at the midpoint over 2025 results.

We increased our dividend by over 6% and updated our long-term non-GAAP operating earnings CAGR to 6% to 8% using a higher baseline for the second year in a row. Earnings growth beyond our forecast is achievable through opportunities to contract our existing output and planned upgrades as well as from incremental regulated capital investments. That concludes our formal remarks, and we are ready to begin the question-and-answer session.

[Operator Instructions] The first question is from the line of Shar Pourreza with Wells Fargo.

Ralph, just on the legislative side, I mean, you've been kind of front and center around this for some time around new gas. Can you just maybe talk about the timing of the bill, so next steps? Will there be like an IRP process? Could there be like a PPA structure where you earn a return on the PPA, assuming a generator wins the RFP? And how do we like work through things like air permits and kind of turbine queue backlogs? I guess, just how do you think about this whole process?

Boy, there's a lot there. But you also answered your own question a little bit as you went through it, Shar. Much of it's in play, right, as you said. And many of those variables that you laid out are the exact variables that policymakers need to come to grips with. right? So there's a couple of bills that are floating down in Trenton right now that will help enable new nuclear and potentially new gas.

I think the governor already has the ability to move on a lot of solar and potentially battery storage. So the way we've been thinking about it is trying to help policymakers think through and then enable the opportunities for gas or for new nuclear, right? And we've talked about that in quite a few different settings.

And that's really what we've been trying to do is help them think through that at this point. But all the items you mentioned, whether it be turbine backlogs, air permits, so on and so forth, all of those items are still variables that are out there that policymakers have to work through the challenges they may face on any of them.

And you can structure an IRP process relatively quickly for this?

Yes. I mean, look, we can help out with an IRP for PSEG. We can help out with an IRP for New Jersey. But I think that process, again, just informs the output. It doesn't drive the output because the policymakers will be the ones that really kind of own that as they go forward. The IRP will make recommendations as we do all the time on Long Island, but they're not going to be definitive decisions. They don't carry the weight of the law, right?

Got it. And then just lastly, can you just maybe help us quantify like what level of hedges and upside versus the PTC you're kind of embedding in that 6% to 8%? Is the bottom end of that CAGR kind of anchored in PTC level assumptions? And is there kind of an expectation of future updates to include above PTC earnings?

Yes. I'm going to give it to Dan to walk you through that. I talked about where we are for '26 in the prepared remarks, but Dan can give you a little bit more about that and be consistent with what he has spoken to before.

I think the way to think about it, we talked about the prompt year being about 95% hedged, and we're pretty well hedged through the next couple of years, but certainly less so in the out years. And so I think you're looking more at a market view to try to get you to what that out year looks like. I think that, that market view is supported by some of the fundamentals that you're seeing out there. And if and as that moves over time, which we would expect that it would, we'll take that into account as we're making our comments and updating what's going on. But I think that's the way to think about it.

Our next question is from the line of Nick Campanella with Barclays.

So I guess in the past, when you had a 5% to 7%, you kind of talked about it being nonlinear and now you have the 6% to 8%, which is great to see. And I just recognize you have things like refueling outages and timing of rate case outcome at some point in this plan. So just maybe can you kind of talk to whether this CAGR is linear or not and where you may fall within the CAGR '27, '28 and just the kind of critical drivers that people should be paying attention to here?

Yes. So I think we -- look, we have talked about for the last 3 years about being more predictable. So with that is our effort to be as linear as possible. That doesn't mean we won't be 100% linear, but we work really hard to do that, right? There will be structural changes that happen where we have to modify.

And right now, I think the structural change has been the supply-demand curve, and we've seen that, and it's taken us above the PTC floor pretty clearly as we look forward. So we adjust it. But I think our goal remains the same is to be a predictable investment for folks. And I think we've been able to achieve that by delivering the results that we said we were going to deliver. So we feel confident in the plan that we put forth today. And yes, our goal remains to be as linear as possible.

And I recognize that you forecasted the base off a higher midpoint of '26 as well. Maybe just -- you also kind of talked about nuclear contracting -- you talked about nuclear contracting to kind of put you above that range. Just maybe what's the latest thoughts on that at this point? I know the prior state administration was very focused on bringing data centers to the state. How is that kind of looking under this new administration? And just maybe anything you can kind of offer and what your conversations have kind of been with customers on that?

Yes, I think the story is fairly consistent. I think that, obviously, the most near-term things that you ought to be able to think about as this administration comes in and settles in on their views on this is the facilities that we do have in Pennsylvania, where I think there's been a more firm view over time and more stability with respect to who has been in the governor's office there as well as some of the smaller opportunities that we have more locally within New Jersey.

And we've talked about a lot of the applications that the utility has seen. And so there's, I think, less opportunity for something of a sizable scale in New Jersey just from the standpoint of where the administration has been. To the extent that, that changes and the receptivity has increased there, there could be incremental opportunity. But I think for the time being, the more fertile ground right now would be Pennsylvania for something larger and some of the smaller New Jersey locations. And I think those discussions have progressed well.

Yes. And I would just add just from a normal rhythm of transition for an administration like this, the way it works in New Jersey, there'll be -- there's a real focus now. First of all, let's staff up. And I think the governor has done a great job of getting a number of people in place, not just in our industry, but in other areas that matter to the state running well. And I think the second thing they need to do is really focus on the budget for New Jersey.

And so that's where my understanding from conversations we've had is the focus of the governor right now. Once she gets through that process, I think economic development will be right behind that as an area of focus. And we are already having conversations on that organization that I chair choose New Jersey about the role we'll play and the areas of focus, but that has not been finalized yet.

Okay. And then if I could just throw in one follow-up on Shar's question regarding kind of the nuke assumptions. I understand that this RBA process is going on right now and there's discussions around extending the RPM collar for another 2 years. And a week or 2 ago, a 420 per megawatt day number was kind of thrown out there. Just what are your kind of thoughts on extending at the current cap rate through 2030? And then what's kind of embedded in the plan right now?

Yes. Look, I think embedded within your question is the fact that you've got a market out there where you can see what things are looking like, but it will remain somewhat dynamic as you step through time. And that's the best information that we have as well. And so what we're doing is trying to look at what that looks like. I think that arguably, you could have stayed at 5% to 7%, been at the PTC and been more firm, but I honestly think you'd be less realistic.

And so what we're trying to do is take a realistic view as to what things will look like as we step out over the longer term. I think we feel good about where we are and how it all fits together within the plan. But I think it's those same market signals that we see that you're seeing out there. I mean, as a reminder, I would highlight the fact that the location of our facilities is in the PECO zone.

So if you're thinking about pricing and trying to do math to figure out what this means in the out years, that zone is most highly correlated to the actual generator buses where we run. So West Hub trades north of that. We said it trades about 20% above what we would be seeing from where our generator bus is. And so it's those market points that we look at to try to drive where we're headed within the plan and what we put forth to you. And so I think we're in a really good place against that backdrop, but that's what we look at as we go forward.

Our next question is from the line of Bill Appicelli with UBS.

Rob, maybe you want to go to another one and see if Bill rejoins.

Sure. The next question will be from the line of Tanner James with Jefferies.

It's Julien Dumoulin-Smith. Look, let me follow -- and by the way, nicely done on the CAGR increase. I got to hand it to you guys. If I can follow up on the gist of what Shar and Nick were asking us about here. Let's talk about the overlap between the BPU here and legislative process just a bit here in terms of what next steps are from both and how they might overlap, right? Because clearly, there's a certain degree of mutual alignment between the 2 in theory. Can you comment a little bit on -- maybe even more oriented towards time line? I know Shar was kind of pressing at that as well here.

Yes. Look, I think that you're going to have a little bit of give and take that will continue as people find their footing in this new administration, right? And not from the administrations finding their footing, but how the legislator is going to work, legislative area is going to work and how the regulator is going to work. So these 2 bills that were introduced recently kind of direct the BPU to do certain things.

The BPU has the ability to do certain things today, go out and procure gas, could go out and procure new nuclear, right? We had the ZEC process in the past, but they are limited in what they can do. So they need some more -- they could use a little more direction to make the process a little cleaner for them by some legislative changes. So I think that's just an open process that exists out there.

It's something that's going to be -- I can't tell you it's going to happen in the next 30 days, and I can't tell you it's going to happen in the next 6 months. But the level of interest and the engagement by folks is pretty high. And it all comes out of the back end of the last 12 months of discussions about higher electricity costs from a supply standpoint and the need for us to change that balance somehow.

The scarcity is there, and we've got load increases that have taken place across PJM, even if we don't have a data center in New Jersey, and we do have. We have the smaller ones as we've been talking about. But the load increases are happening right across the river, and it's impacting the pricing here in New Jersey. So I think the BPU has recognized that they do not want to be in the same level of import that they are. I think policymakers feel the same way, and they want a little more control over the pricing of the product that ultimately, the residents of New Jersey hold us all accountable for.

Got it. And if I can zero in a little bit, guys, on the '26 guide here, and thanks again for your help earlier. How do you think about what the breakdown is between the regulated utility side of that year-over-year increase versus what's reflected in power? And then even within power, can you comment a little bit about where you guys are hedged? I know you said you're 95% for this year. Just comment a little bit about where you are relative to that floor, if you will, just as a starting point, I just want to make sure we're all on the same page here.

Yes. I mean, obviously, we're north of it because that's how we described it and how we put it out there. I think to go much beyond that, we would start to kind of break down the pieces beyond what our overall guidance is. And so I think just maybe repeating a little bit what I said before, Julien, if you think about what the market signals are that are out there, that's what we're leaning on. I would say that '26, we gave you a 95% hedged, '27, I think we're -- fair to say that we are largely hedged for that year.

And in '28, I think -- if you think about a ratable approach over 3 years that we've talked about, mainly, we would say that because the most liquid part of that curve is over those 3 years. And so we have leveraged that liquidity to be able to hedge up a fair bit of '27 and '28, but '29 and 2030 remains more subject to market forces as we go forward.

Or let me try this differently. How do you think about earned returns in the current year here for the utility and/or kind of what's implied year-over-year growth on an EPS basis?

Yes. Look I think we've been pretty clear about the fact that where there are structural changes, we'll make changes. And when the changes aren't structural, we'll look at what opportunity sets we have for maintenance activities that might be in a 4-year cycle and try to look at that from a predictability standpoint for the investment community. So we look at our plans every year. We adjust to that.

And again, I just want to reinforce that really happy with the top end of the 5% to 7% that we've been running for the last couple of years, but we thought it was struck the scarcity issue of power was enough to structurally change our thought process to be in that 6% to 8% based upon where prices are driven by both the capacity and the energy side. So it is -- I know you're trying to push us into a little bit of a conversation about ROEs in the utility and that. And we just feel comfortable talking right now about that predictable pattern that we've talked about from an earnings standpoint.

Yes. No, but I hear you. The increase here is principally predicated on the power side of the business for sure in future years.

The next question is from the line of Bill Appicelli with UBS.

Apologies for that technical problem. Just maybe building on some of these other incremental regulated capital investments, and forgive me if you already addressed it and I missed it, but I guess where in the spectrum would those fall? And what types of projects are we talking about there?

I think they come in really 2 buckets, right? There's incremental transmission in the PJM region. We've been active in that process, and we're successful as we've talked about a bunch of times in Maryland. And we continue to look at those opportunities when they present themselves.

There's a very specific effort going on in the state of New Jersey right now about being ready for solar and the need for us to make sure that our distribution system is ready. That's been an ongoing process down at the Board of Public Utilities, and there were comments received on that in the last couple of weeks down there, if I recall correctly, that we submitted and others did.

So that could drive some incremental investment for us as we continue to make sure that this focus on solar and batteries can be enabled by the distribution system that they're going to be interconnecting to. And then the third bucket is the opportunity for us to participate on the generation side, again, depending upon where policymakers land on that front. So I would say all 3 of those are the areas that we talk about around the table on a regular basis.

And then on top of that, I would just add that embedded within kind of the base plan that we have in front of us, which the things that Ralph mentioned could add to that. I would still characterize what we put out as the updated capital forecast as there's nothing in there that's a single project that's a huge part of the capital.

It's going to require a whole bunch of permits to be able to get done. It's all stuff that sits in front of us and is shorter term in nature, and we can kind of knock out without a whole lot of red tape that we got to get through or challenges we got to get through. It's just kind of a basic set of capital that we know we can achieve.

Yes. No, it's a really good point that Dan is saying. I mean everything I just said is above and beyond. We're not building in a percentage of any one of those buckets as we put out this capital forecast. These are small projects that are really 90% of them are being based upon end of life on the regulated side.

So we -- I kind of -- I've been telling my family anyway, if you think about what we do every day in replacing the infrastructure, it's just like the portal bridge for those of you that are in the New Jersey region and see New Jersey transit delays right now as they upgrade that. The infrastructure in New Jersey is old, and we have an opportunity to make upgrades as a result of that.

All right. That's very helpful. And then just one other one. On the O&M side, I guess what's embedded in the plan in the 6% to 8% on that front, just at the utility level?

Yes. As we build our plan, and Ralph has often described it this way, we take a look at what's in front of us and whatever kind of an inflationary assumption we have there, and then we look to the to the businesses to try to pull back on that to end up in a more reasonable place from a cost-cutting perspective and overall cost management perspective.

So if you've got a 3% inflationary assumption, you can pull that back down to 2% to 2.25% as everybody is looking for opportunities within those budgets to try to move to a better place. So that's kind of how we structure and how we move forward on it. We know that we do have our labor agreements that are running out through '27 and those will get re-upped and that will have an effect as well. But we kind of lay out a baseline plan and then pull back some efficiencies to get to where our final plan land.

I mean relatively flat with some inflation and then we back it off, as Dan said. I know some people think we were -- we talk about finding pennies in the couches, which is -- which I actually like. My wife and I still have a little bucket that we put our pennies in. So it's not the worst thing in the world to go looking for them because they all add up at some point.

Okay. But some assumption on the re-upping of those labor agreements is reflected in this plan.

Yes. That's all in there. There are no expectations of major dislocation there.

The next question is from the line of Michael Sullivan with Wolfe Research.

Ralph, I think for a while now, you all have had in your slide deck over the forecast period, 90% regulated earnings. Is that still true under this updated plan? Or any sense you can give us of what the mix is?

No. I mean what I would tell you is I hope that number goes down a lot because that means power prices are going to go up, we're going to do better. I would think about the utility side of the business continuing to do what it does. And to the extent that we see some movement up from a power price perspective, given the demand supply dynamic that you're seeing, you might see a modest shift there.

And again, my kind of tongue-in-cheek way of saying it is I hope it goes down a lot because that means that we're doing better on the other side of the business. But I wouldn't think about any major shifts that compared to what we've seen in the past. It's going to be more modest as we step through time.

I may even be a little bolder than that. I almost -- and we've said this also for many -- long time in our decks. The PTC floor is a regulated type return. And so when we think about it from that perspective, you could argue that the merchant is only above the PTC floor, right? Because the federal government has regulated that PTC floor as the return for the nuclear plants. So I know it's not traditional regulated, but when we think about it from a risk profile standpoint, it sure feels a lot like that.

Okay. No, that's totally fair. But it just sounds like you're not going to tell us what your merchant assumption is above the PTC floor out in time.

We're going to tell you what our earnings projections are, and we're going to meet them as we have done.

Okay. Okay. And then on the utility side, I just think historically, the rate base kind of rebase of the CAGR has been a bit higher than we saw this past year. Anything to make of that? Or what's kind of driving that? I think last year, and the year before might have been double digits and then you grew 6% to 7.5% off of that.

[indiscernible] you're talking about from the standpoint of the baseline. Look, I would think about that rate base as growing the 6% to 7.5% that we've put out for the past couple of years. And I think that, that's still consistent. I would say, to our credit, that has been on a growing base that for some years has been above that.

And so continuing to grow, I guess, it embedded within your question, 6% to 7.5% has been a consistent CAGR growth to the extent that what you're implying is correctly that, that rate base has grown more than that the last few years. We've continued to grow 6% to 7.5% off of that higher base, which implies a little bit higher growth.

The next question is from the line of Anthony Crowdell with Mizuho Securities.

Ralph, you were at the Devil game last night. I hear the opening ceremony is really exciting.

We did not make it down there last night, but our esteemed CFO did.

It was fantastic.

Was he the fan applauding in the beginning? I know there was some booing going on of some of the elected officials.

All I heard was USA chants and they were deafening. It was fantastic.

That's awesome. I just have a cleanup question. I believe that BPU is in an 180-day pause right now coming from the Governor's executive order. If you could talk about, one is maybe thoughts of what happened at the end of the 180-day pause, maybe some of the outcomes you think. But -- and then also, I believe it's an 180-day pause of no increase in rates. Just curious if that includes any of the rate riders.

No. So the pause that they put in place was on regulations that were passed from the prior administration. And so they paused them. I don't know if it's 180 days or 90 days, but they basically said, hey, listen, if we were going to change the speed limit on the turnpike, and that was a change that was put in place by the prior administration. That won't go into effect for another 90 or 180 days.

And so there were a few things there that were on the fringes to our business, but nothing after we did the review that would impact our business. And I mean that from a labor wage standpoint, from a benefit standpoint, from any of the above. So no impact on that as a change. But those regulations were regulations that were changed by the prior administration in the months leading up to the election.

And I think that was a 90-day time frame.

I didn't want to correct.

No, that's fine. I know you're looking for pennies in a couch, but do you know when the 90-day ends?

Yes. No, it's 90 days after she took office. So I want to say it's -- I think she took office on the 12th of January, if my memory serves me right.

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

Just one last question for me. As we think about future generation in the state of New Jersey, you've talked about the ability to host SMRs in the past. I'm just wondering any updated thoughts you might be able to provide on how likely that is to, I guess, come to fruition or just thoughts on the topic in general?

Yes. I would put our -- look, if we were advocating, we're advocating for -- on the nuclear front for big nuclear. We think that, that makes the most sense based upon our property and our footprint. But there could be other places where the -- it makes sense for people to put small SMRs and to try that technology out.

I think also from a gas facility standpoint, we've said that we have a site that makes a ton of sense where we have pipes and wires ready to it as well. So yes, I would -- SMRs from our standpoint would not be the highest and best use of our property, but one that we would be open to if people -- if that was really what folks wanted us to enable. Remember, our early site permit is technology agnostic. So we could go in any direction on that.

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

I would hold on to those pennies because there's probably some scarcity value associated with them.

Exactly, exactly. They get added up. They add up.

So I actually wanted to kind of continue down the nuclear rabbit hole here, if we could, for a little bit. Just as we think about kind of the nuclear fuel availability and how you guys are hedged out through -- over the course of the capital plan and just knowing that Russia is kind of going offline in 2028, how are you guys kind of -- are you guys kind of front-loading or kind of prebuying any type of nuclear fuel just to ensure that affordability kind of doesn't go too haywire?

Yes. We -- look, when I start thinking about nuclear fuel, the first thing I think about is the fuel in the reactor because that's most of what we're going to be using for the next couple of years. Then I look to where we have contracted and we're contracted out for the next few years for most of what we're going to need. And it's only when you get to the tail end of that 5-year period when things are going to change.

I also think just not to get too deep into world markets, but I think conceptually, the fuel that's being produced is the fuel that's going to be produced. And if Russian fuel doesn't come here, Russian fuel will go somewhere, and that will displace what's going to be purchased from places where we're going to purchase from. And so you could see some modest movements with respect to supply-demand pricing, but I don't think anything that's going to be all that dramatic.

And if I think about prices that sit somewhere around $50 and fuel that sits somewhere around $7, $8 on the overall scheme of things, it's -- the availability is a critical aspect for us, and I have no question that we're going to continue to see availability of fuel, and you could see some modest movement in prices, but I think we're hedged out for the next couple of years in pretty good shape.

Got it. Great. And then if I just -- if I could as well, I know, Ralph, you've been kind of a big proponent on more large nuclear relative to SMRs. But I think if I understand correctly, Governor Sherrill is more -- just given our naval background, more in tune with SMRs. But is there anything -- any kind of, I guess, appetite from her just given that we did have the -- a couple of months ago, the Brookfield Westinghouse DOE type of procurement of the 10 AP1000s. I mean, is there any opportunity for you guys to partake in those allocations?

Yes. Look, I think we have said probably ad nauseam now that we want to help enable exactly that. And so we will continue to educate and advocate on behalf of the state for something like an AP1000. I don't want to predetermine that selection. I think that's one that it appears that DOE has firmed up on, but I also hear that all the I's are being dotted and T's crossed. So we'll be there advocating, but that's as far as we're going right now. And I think the education that's ongoing for the incoming administration is something that we're also trying to help with.

Our last question is from the line of David Arcaro with Morgan Stanley.

This is Amanda on for Dave. So maybe lastly, just on the executive orders, how are you thinking about the scope of the current BPU study? And are there any financial impacts currently contemplated in the long-term plan based on any potential changes? Or do you think it's still too early to assess those changes?

Yes. I think it's too early right now. There's a lot of conversations going on. But I know we have looked at a number of different ways that things have changed from a regulatory standpoint and how utilities have been compensated. You can look across the country and see many of those. And I think many of those at the end of the day have worked out for the utilities that have been involved.

It's just a different way of thinking about things and providing those returns for those utilities. So we have not changed -- we haven't put any different regulatory process in place in the projections that we've made. But we fully expect that the outcome is going to be an outcome that makes sense for both us and for the customers.

Great. And maybe just a quick follow-up. With the 2 new commissioners in the BPU, any, I guess, initial comments on conversations with them just based on the first few months of their appointment?

Yes. No, our team has continued to meet with folks, but our conversations have been limited to, I would -- best way to put it, meet and greets at this point.

That is all the time we have for questions. I would like to turn the floor back to Mr. LaRossa for closing comments.

Thank you, Rob. So I had a couple of comments prepared, but I actually started this call, as you heard, talking about the great work of our team during the last storm. And our facilitator here today, Rob, actually started our morning off by thanking us for the work that was done and the way that we responded and communicated during the storm. So I just want to reinforce the thank you to the team.

We could talk all we want about finances and the outcomes that we have here. But if we don't deliver on our operational mandate's day in and day out, no regulatory construct is going to matter for us, and our plants won't run. So I thank the employees every day. And when I get comments like we just received from Rob when we opened up this call, it makes it all worthwhile.

So Rob, thank you, not only for facilitating the call but for reinforcing for all of us that what matters is the work that's being done day in and day out by our employees in the field. And with that -- thank you, Rob. And with that, I'm going to close and look forward to seeing you. We're going to be out quite a bit over the next 1.5 months and look forward to the in-person conversations.

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

Ladies and gentlemen, thank you for standing by. My name is Rob, and I'm your event operator today.

I'd like to welcome everyone to today's conference, Public Service Enterprise Group's Third Quarter 2025 Earnings Conference Call webcast. [Operator Instructions] As a reminder, this conference is being record today, November 3, 2025, and will be available for replay as an audio webcast on PSEG's Investor Relations website https://investor.pseg.com.

I would now like to turn the conference call over to Carlotta Chan. Please go ahead.

Good morning, and we welcome to PSEG's Third Quarter 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 estimate that are subject to various risks and uncertainties.

We will also discuss on 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 all of you for joining us to review the results we announced this morning and to discuss our outlook for the business over the remainder of the year.

PSEG reported solid third quarter and year-to-date operating and financial results, reflecting the expected positive impact of new rates from the October 2024 distribution rate case settlement that benefited the full third quarter. Our results through the first 9 months enabled us to narrow our 2025 non-GAAP operating earnings guidance to the upper half of the range at $4 to $4.06 per share from prior guidance of $3.94 to $4.06 per share.

At PSE&G, we invested approximately $1 billion in the quarter and $2.7 billion over the first 9 months of 2025, all part of our planned full year $3.8 billion regulated capital spending program. This program is focused on replacing and modernizing New Jersey's energy infrastructure, meeting load growth and expanding energy efficiency programs that lower energy demand and customer bills.

During the quarter, PSEG Nuclear supplied the grid with 7.9 terawatt hours of reliable, carbon-free baseload energy, while providing PSEG with the financial flexibility to fund our regulated investments.

Our 100%-owned Hope Creek unit completed a 499-day continuous run since its last refueling outage, and we recently completed work to extend its fuel cycle from 18 to 24 months, positioning the unit to produce more megawatt hours going forward.

Also during the past quarter, the Board of Trustees of the Long Island Power Authority approved a 5-year contract extension for us to continue as the operations service provider for the electric service on Long Island and in the Rockaways through 2030.

We are executing on PSEG's growth plan with a focus on operational excellence and rigorous cost discipline to maintain reliability and provide value for our customers.

The need for our investment in leadership has never been more evident than now with the significant and growing supply-demand imbalance in New Jersey and the entire PJM region. To address this resource adequacy imbalance, which will adversely impact both reliability and affordability for customers in the future if it's not addressed, we are actively collaborating with current and potential future policymakers to develop real solutions in New Jersey and ensure we can affordably meet our customers' energy needs.

The next governor of New Jersey will be faced with addressing a broad set of rising costs and implementing practical solutions to get to the root cause of these cost pressures will be a focus. These cost pressures have many sources. For example, the latest Rutgers-Eagleton Poll showed that 36% of likely voters cited taxes as the top problem facing New Jersey, while 21% said it was affordability. Other topics trail these 2 leading concerns with 6% pointed specifically to housing affordability and 5% saw utility costs as the top problem in the state. We stand ready to work with the incoming administration to do our part to keep rates as low as possible in the short term and work on longer-term solutions to add supply.

While the supply-demand imbalance remains a significant and growing problem, we expect the capacity market impact on customer bills next June will be limited by 2 factors. First, the FERC-approved price collar that will extend to at least the upcoming capacity auction in December; and two, the gradualism of the basic generation supply mechanism that feathers in changes over a 3-year period here in New Jersey. This assumes other supply-related costs remain the same, preserving the reduction from other charges expected to come off the bill.

One energy topic where there is broad common ground is that New Jersey needs to add generation supply to reduce its over reliance on the PJM capacity market and ensuring continuing reliability and affordability for customers with imports having grown to over 40% of our generation consumption.

Legislation has been introduced that allows electric distribution companies to compete to participate in offering supply solutions. We are supportive of legislation that would increase competition for generation of supply should New Jersey decide to pursue new in-state generation. In addition, we have sites with grid connection capability and pipeline supplies as well as the in-house expertise to build new supply here in New Jersey with prevailing wage labor.

Now turning to PSEG Nuclear. We continue to implement projects designed to optimize our plants and increase megawatt production. In addition to the Hope Creek fuel cycle extension I mentioned earlier, our Salem uprate project will bring an incremental 200 megawatts to the grid during the 2027 to 2029 time frame as this kind of baseload carbon-free dispatchable power continues to increase in scarcity value.

We also note the potential significance of the recent Department of Energy notice, which has now become a FERC rulemaking, seeking to accelerate interconnection of large loads in a way that is timely, fair and affordable for customers. The notice is requesting that FERC take final action by April 30, 2026. There are many positive elements to this proposal, but it will take a while before we see the ultimate impact of the rulemaking.

So to summarize, we delivered a solid operating quarter for our customers, and our financial results through the first 9 months enable us to narrow our full year 2025 non-GAAP operating earnings guidance to the upper half of the range at $4 to $4.06 per share from our prior guidance of $3.94 to $4.06 per share. We are also reaffirming PSEG's 5-year non-GAAP operating earnings growth outlook of 5% to 7% through 2029 as we continue to pursue incremental opportunities to our long-term forecast, including the potential to contract our nuclear output under multiyear agreements and potential utility investments to address near-term need for additional supply due to the growing customer demand.

Notably, our balance sheet continues to enable us to fund PSEG's 5-year capital investment program of $22.5 billion to $26 billion without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth.

Before I conclude, I would like to recognize the outstanding performance of both our transmission and distribution system as well as our nuclear business over the last quarter. Both demonstrated exceptional reliability and resiliency for our customers. This collective achievement reflects the hard work, dedication and technical expertise of everyone at PSEG.

Now as you know, tomorrow is election day in New Jersey. Let me say this clearly, PSEG has been around for over a century, and we have worked successfully with every New Jersey administration on both sides of the aisle with aligned objectives for the state's advancement. Based on our meetings with both candidates for governor, I have every confidence that we will do so again with the new incoming administration.

I'll now turn the call over to Dan, who will walk you through our financial results and the outlook for the remainder of 2025 and then rejoin the call for Q&A.

Thanks, Ralph, and good morning to everybody. For the third quarter, PSEG reported net income of $1.24 per share in 2025 compared with $1.04 per share in 2024 and non-GAAP operating earnings were $1.13 per share in 2025 compared with $0.90 per share in 2024.

We've provided you with information on Slide 7 and 9 regarding the contribution to net income and non-GAAP operating earnings by business for the third quarter and 9 months ended September 30, 2025.

Slides 8 and 10 contain waterfall charts that take you through the net changes for the quarter and year-to-date periods over the prior year and non-GAAP operating earnings per share also by major business.

Let's start with PSE&G, which reported third quarter net income and non-GAAP operating earnings of $515 million for 2025 compared to $379 million in 2024. Utilities results were driven by the implementation of new electric and gas base distribution rates that took effect in October 2024 to recover a return of and on previous capital investments totaling more than $3 billion and higher working capital recovery.

Beginning on Slide 8 with the PSE&G column. Our distribution margin increased by $0.30 per share compared to the year ago period, largely reflecting the impact of the rate case plus recovery of and return on PSE&G's capital investments.

On the expense side, distribution O&M costs were $0.02 per share higher compared to the third quarter of 2024. And depreciation and interest expense rose by $0.01 per share and $0.02 per share, respectively, compared to the third quarter of 2024, reflecting higher levels of depreciable plant investment and long-term debt at higher interest rates.

Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to zero over a full year, had a net favorable impact of $0.02 per share in the third quarter compared to the prior year period.

Following severe heat storms in June when PSE&G hit its electric system peak for the year, weather conditions during the third quarter, as measured by the temperature-humidity index, were 3% cooler than normal and 7% cooler than the third quarter of 2024.

As a reminder, the Conservation Incentive Program, or CIP program 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 is the primary driver of distribution margin, and each segment grew by approximately 1% over the past year.

On the capital front, as Ralph mentioned earlier, PSE&G invested approximately $1 billion during the third quarter, totaling $2.7 billion for the first 9 months. Our plan for the full year of 2025 regulated capital investment remains approximately $3.8 billion, and our 5-year regulated capital investment plan of $21 billion to $24 billion through 2029 is unchanged.

In the first quarter of 2025, PSE&G began deploying the new energy efficiency programs. We anticipate investing up to $2.9 billion over a 6-year period under that program. This program total includes approximately $1 billion of on-bill repayment options to help our customers finance their energy efficiency equipment and appliances and provides customers with energy information and options to manage their energy use and lower their bills.

Now moving on to PSEG Power & Other. For the third quarter, PSEG Power & Other reported net income of $107 million in 2025 compared to $141 million in 2024 and non-GAAP operating earnings were $50 million in 2025 compared to $69 million in 2024.

Referring again to the third quarter waterfall on Slide 8, net energy margin rose by $0.01 per share compared to the prior year quarter. While generation was down in the quarter due to the Hope Creek refueling outage, overall power pricing and market revenues were higher than in the third quarter of 2024.

O&M was $0.05 per share unfavorable compared to the third quarter of 2024, mostly driven by the scheduled refueling of our 100%-owned Hope Creek nuclear unit. As Ralph mentioned, our Hope Creek unit has successfully transitioned from an 18- to 24-month refueling cycle going forward, which is expected to yield additional megawatt hours as well as O&M savings over the long term.

Depreciation expense was $0.01 per share favorable and interest expense rose by $0.02 per share, reflecting incremental debt at higher interest rates. And taxes and other were $0.01 per share favorable compared to the third quarter of 2024.

On the operating side, the nuclear fleet produced approximately 7.9 terawatt hours during the third quarter compared to approximately 8.1 terawatt hours in the third quarter of 2024. For the 9 months ended September 30, 2025, nuclear generation was approximately 23.8 terawatt hours, up slightly from 23.3 terawatt hours for the same period of 2024. Capacity factors for the nuclear fleet were 92.4% and 93.7% for the quarter and 9-month period ended September 30, 2025, respectively.

In July, PSEG Nuclear declared approximately 3,500 megawatts of its eligible nuclear capacity in PJM's base residual auction at the market clearing price of $329 per megawatt day for the energy year June 1, 2026, through May 31, 2027.

Touching on some recent financing activity. As of the end of September, PSEG had total available liquidity of $3.6 billion, including approximately $330 million of cash on hand. And on the financing front, in August, PSE&G issued $450 million of 4.9% secured medium-term notes due August 2035. And later in August, PSEG redeemed at maturity $550 million of notes that carried a coupon of 0.8%. Overall, PSEG had significant liquidity at the end of the third quarter, which remained relatively unchanged from the end of the second quarter.

PSEG's variable rate debt at the end of September consisted of a 364-day term loan at PSEG Power for $400 million, which matures in December of 2025, and commercial paper. As of September 30, our level of variable rate that represents approximately 4% of our total debt. And in October, Moody's published updated credit opinions on PSEG and PSE&G with no change to either credit ratings or outlook.

Looking ahead, our solid balance sheet supports the execution of PSEG's 5-year capital spending plan dominated by regulated CapEx without the need to sell new equity or assets and provides for the opportunity for consistent and sustainable dividend growth.

In closing, we are narrowing PSEG's full year 2025 non-GAAP operating earnings guidance to 4$ to $4.06 per share from $3.94 to $4.06 per share. This updates PSEG's solid results through the first 9 months of 2025. And we are also reaffirming our long-term 5% to 7% compound annual growth and non-GAAP operating earnings through 2029, supported by our capital investment programs and the nuclear PTC threshold. We expect to introduce PSEG's 2026 non-GAAP operating earnings guidance, roll forward our capital investment plans, update our rate base on long-term earnings CAGRs and discuss this outlook call during our year-end call in February of 2026.

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

[Operator Instructions] First question is from Shar Pourreza with Wells Fargo.

Who's that? Welcome back, Shar. And just like we did with many of your peers over the last 12 months, welcome back to hear you.

I appreciate. You almost had me tongue tied and that never happened. So I appreciate that. So Ralph, just obviously, the elections could be kind of this key threshold for data center deals in the state. We've seen data center customers walk away from local politics issues in kind of both the regulated and even deregulated markets. Artificial Island is obviously -- it's a great asset. So kind of curious if there's any pressure points forming there? And then, obviously, one of your favorite questions is any updates on potential time lines?

Yes. Thanks, Shar. I'll let Dan, as we have been doing over the last couple of calls here, answer the time line conversation. But look, I would say this, and it's more of a generic answer to you on the election and what we can expect post Tuesday. And that is, we will see. But as I said in my -- kind of my closing comments, we fully expect to be able to work with both sides of the aisle. We've done it in the past. It's a proven track record by this company, and we feel really, really confident that, that's going to continue as we move forward here in 2026.

Specific to data center opportunities in New Jersey, they really haven't slowed down. We have some information in the deck about how that has continued, and we expect it to continue. A few of those jobs have moved a little bit further along in the queue, depending upon whether you look at our queue or PJM's queue as an example. And I'll just point you to one that showed up today, it's public information. There's a TEAC meeting that's taking place tomorrow at PJM, and there is some additional load that's been identified for a job in Kenilworth that is our supplement -- one of our supplemental projects.

So they continue to arrive here in New Jersey. We haven't seen it at the hyperscale level. And we have talked about that for many times, and we expect these to be smaller, not ones that we're making big announcements about, and we don't expect those smaller, less in size announcements to be something that we're talking about, whether it's at the utility or at Power.

Dan, do you want to talk more about the time line?

No, I mean, I think Ralph covered it. I think we'll get a little bit more color from both of the candidates. There's been a whole bunch of stuff they've talked about during the campaign. This hasn't been the highest topic with respect to data centers as much as with respect to affordability generally on things that have touched us. But we'll get more color as the election ends and we find out where they're going to go. But in the meantime, I think it's everything that Ralph said, and we're continuing to move forward.

Okay. Great. And then just lastly -- that's helpful. And then just on the 11 gigawatts, the large load pipeline that's obviously growing. Just -- I know I don't want to front run the CapEx update on the roll forward, but let me attempt anyway. But just on the grid capacity, just Dan, talk about -- Ralph, just the grid capacity that's there to convert into signed agreements versus how much transmission and distribution needs you're going to have as you start to convert?

Well, again, I think a little bit of that is front-running some policy that will exist here in New Jersey, right? So the first -- and I talk a lot about the fact that the new governor will need to make some policy decisions that will help us plan the grid for the long term. Right now, we have capacity on our grid. That's based upon the current topology. If we see new generation come in, large-scale 1,000-megawatt plants that are showing up, that may change the grid topology a little bit. If we see more solar and more batteries, that may change the topology a little bit. So I'd be front-running to say that I could tell you that, which is why we're going to give you that full -- roll forward in February.

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

Just wanted to pick up on the conversation with regard to potential data center contracting here. And wondering if you might be able to comment, I guess, on the flavor of conversations between your New Jersey versus Pennsylvania assets. Is there any discernible difference, I guess, in the tone of those conversations?

I wouldn't say difference in the tone of conversations, Jeremy, but I think that you're seeing different types of entities being involved between the 2 states. I think you have more of a forward-leaning appetite in Pennsylvania, which is enabling more to happen and more to happen on a bigger scale. And I think in New Jersey, I have not seen that as much with respect to the incentives. And so what you're seeing is still some interest in the state and some sizable interest in the state, but at a smaller scale. So I think that's probably the biggest differentiation between the 2 locations.

Got it. That's helpful. And as it relates to, I guess, supply additions and working with stakeholders in the state, just wondering if you might be able to expand a little bit more beyond that, I guess, as far as what type of constructs Pega be interest in, be it regulated generation, unregulated generation or just any other color in general on this topic?

Yes. So Jeremy, it's a great question. Look, we have said for many months, and we have indicated in public settings that we are more than willing to help the state achieve its goals in a regulated capacity, right? We absolutely think that we could provide some solutions for gas generation that's in a regulated manner. We also think we can continue. We've done large-scale solar on some brownfield sites, some landfill sites in the past. So we could do more on the solar front. We think there's an appetite now for some regulated storage and we're looking forward to taking part in that, see how that plays out over the next few months. And we know that many -- both candidates have been talking a lot about new nuclear.

Now on new nuclear, we have also been very, very pointed in our responses in saying that we're not looking to put our own capital to work, but we want to enable solutions for the state. And that's where our site comes in. And we think that long term, that will provide us with some revenue opportunities, whether it be for our operating and maintenance activities or security activities, spent fuel storage. There's many, many things that we can do on that front without putting our own capital to work.

And so that's the way we've been approaching it, and that's the way we'd like to see things play out. More opportunities for us in baseload generation from a gas standpoint that would be regulated. And certainly, more we can do on a solar and the battery fronts as well.

And I think if you look at both candidates and their platforms, you really see one -- they all -- they're both talking about everything, right, that they're looking at all these options that are out there. The real question is to what degree. And I think you will see one -- with one candidate that might be leaning a little more towards the gas-fired units and another candidate that leans a little more towards solar and batteries. But both candidates are talking about all of the above strategies, which we support and we will be part of.

The next question is from the line of Nick Campanella with Barclays.

So look, just the contracting discussion, we did see the multistate kind of proposal advocating for Bring Your Own Generation and the need to kind of fast track and permit -- fast track the permitting for some of these data centers, but there just seems to be an overall stress on Bring Your Own Generation across the states in PJM. And how is that causing the conversation around the nukes to evolve? And is it fair to say that any deal at this point would now have to come with additionality commitments, whether that's upgrades, new gas, batteries or otherwise? Just maybe you can kind of talk to that a little bit if that's the right take?

Yes. Are you talking about the DOE, Nick, in that the DOE -- the letter from DOE?

I'm just -- I think there's been various calls by whether it's been Pennsylvania, New Jersey or Maryland on just the need to -- for data centers to bring their own generation now. And I'm just wondering how that impacts incumbent generators that were interested in potentially signing front-of-the-meter deals.

Yes. Nick, I would say that, if I'm capturing your question right, that there has been more dialogue around it. There has not been anything from the standpoint of requirements related to what must happen. And so I think from that perspective, I think it almost does tie in a little bit to what Ralph is talking about with respect to the DOE letter, which is trying to set some standards and trying to, I'm going to say, fast-track things, but get things moving where there is a little bit of a logjam.

There's been a discussion about a whole host of topics. BYOG is one of them. But there's nothing that's mandatory from that perspective. And there's nothing about additionality that's mandatory from that perspective and different counterparties have different environmental profiles that are important to them, but not against the backdrop of anything that is required either. And so I think what you're seeing is continued dialogue around some topics that are of interest, but are not precluding anything from happen one way or another.

Okay. All right. I appreciate that. And then there's been a lot of EPS CAGR updates this quarter. And I guess maybe you can kind of help position to the Street, you're doing 9.5% year-over-year growth, '25 through -- off of '24. I see that on Slide 5. I noticed the [past] 5% to 7% CAGR, that's not linear. But just from our perspective, we know where the capacity auctions have cleared at, we know where prices have gone. Just what are some of the negatives that we should be thinking about that kind of put you back within the 5% to 7% range as we kind of think through what you can deliver on in '26?

Yes. Nick, what I would tell you is our update is coming in February, and we're not going to piecemeal elements of it before we get there. So we'll give you a fulsome update when we give you the update.

The next question is from the line of David Arcaro with Morgan Stanley.

One quick clarification or maybe an additional piece of data. I was just wondering what the level of mature applications would be in that data center activity that you've quoted in the past.

Yes. So I think we moved that from 2,600 to 2,800. I think that's the information that is in the deck. But that's the right number, 2,600 to 2,800.

Great. Okay. Perfect. And then as you sketch out the utility growth outlook and roll forward, I was just curious if you could give your perspective now on how do you manage the affordability concerns maybe outside of just the generation front as you're planning the next iterations of your utility CapEx programs and looking at the T&D rate outlook. How are you weaving in just considerations around affordability?

Well, look, we always think about affordability, no matter what we do here from a company standpoint, whether it's -- I could point you to our O&M slides that are in the deck and how we held O&M relatively flat over a longer period of time. I could talk to you about the way we're implementing our AMI system right now and how we've done that, not only from a standpoint of cost and keeping rates down, but also from the impact on employees and the just transition of those folks into different positions.

So affordability is not something new to us. I appreciate it's a hotter topic in different circles, but it's the way we've operated. And you've heard us many times talk about the fact that we're not making any big announcements about expense savings. We normally just operate in that manner, and we'll continue to do that.

That said, we've also, in the past, worked through different mechanisms with the regulator to spread costs out differently, and I'll go back 20 years when the decision was made to change the depreciable life of our gas assets. And those -- that cost was recovered in a different way from customers. So there are things that we can do working with the regulator to come up with solutions to keep T&D rates flat. We've done that recently. We'll continue to look at options for that. But this is not just an affordability issue, right? This is quickly becoming a reliability issue and the resource adequacy is going to drive us to solutions that are going to increase supply as the demand comes online. We have to find supply.

David, I don't know any other way to say it. And I think both of the candidates for governor in New Jersey recognize that. They've both said that. Again, their solutions might be a little bit different, but how we get there is the only question. It's not if we're going to get there. We need more supply in the state.

The next question is from the line of Bill Appicelli with UBS.

Just following up on some of those comments you just made about finding supply. I mean there would be a sense of urgency I think, behind that, right? So is there an opportunity here in the veto session to push for some legislation that could support this? Or do you think this is more likely something has to be dealt with under a new administration?

Look, there's been a lot of things that have happened in the state in the past, not just from an energy standpoint, but other topics that have been handled in lame duck. And so I'm not sure whether or not that will be the approach that's taken here or it will be one that's taken in '26. But I do know it's going to be a hot topic one way or the other. And so I personally would like to see us move faster from a state standpoint. I think it would help us both from an affordability standpoint, but also from an economic development standpoint.

We -- as I mentioned earlier, we've been -- we've got some headroom in the system today, and we've been using that up. But if we're going to continue to grow the state and again, both candidates would like to see us continue to grow the state, then one of the fundamental things we'll need is enough supply. And that's where I put my economic development hat on, and I say, "Let's get moving sooner than later. And boy, if we could have those discussions starting on Wednesday, it couldn't be soon enough."

Right. And then just along those same lines, I mean, how do you evaluate the framework for that, right? Would this be in terms of evaluating how much generation you potentially would need from a regulated basis? Would there be sort of an RFP approach that you could then bid on? I mean I'm not sure if you guys could sort of describe how you would envision such a mechanism coming out?

Yes. Look, I think that the BPU could hold some sort of an auction. I think we could go to some sort of an FRR. I think, again, I don't want to front-run anybody. I think it would be rude to do that, so I won't. But I will tell you, what it all starts with the same four questions that we've been banging the table about, right? One, we've got to figure out what load we're going to supply, right? Two, we got to figure out what the reliability targets are going to be. Three, it's going to be emissions, right? And what are the emissions profiles we're willing to accept both if we're in a -- build our own generation or import it from our neighbors. Both of those have different impacts and how that plays out.

And then the last thing is the definition of affordability. We talk about affordability, but we rarely define it, whether it's at the state level or at the federal level, to be honest. Is it going to be CPI? Is it going to be regional CPIs? Is it going to be state CPI? What is it going to be? And I think as we move forward, answering those four questions is fundamental to putting together an integrated resource plan.

And then just lastly on the outlook for the forward curves. I mean can you maybe just speak to where you see those relative to maybe your fundamental view or at least relative to where the PTC floor is that's embedded in your outlook?

Yes. I'm going to let Dan answer that one. He sees that a little bit more, but I mean -- we look out 4 years the way others do. So I'll give it to you, Dan.

Yes, Bill, I think you've seen some recent strength within the market, and we've been saying for some time that if you just think about all the fundamentals that are going on and the discussions that everybody is having, it's been pretty tough to try to land the plane on exactly what's going to happen from a load perspective, but the numbers are a little bit staggering. And so even a lower end of the range would imply a need for incremental supply.

And then if you think about the supply discussions, those have always moved towards the concept of we need to move quickly because at the end of the day, it generally isn't going to come out all that fast. You just think about time for turbines and everything else. And so all of that leads you to a little bit of a more bullish place. And if you look at the forward curve, you haven't seen quite as much bullishness. So we've seen some of that come up. And so I think that feels a little bit more like a fundamental move than just some interim period of time, although we do end up having some of those, too. It seems like every time we go into winter and we get a cold day, you see a little bit of movement out the curve. But I do think fundamentals should support a stronger price as we go forward, but the forwards are the forwards.

The next question is from the line of Nick Amicucci with Evercore ISI.

I think you'll get a welcome as well. I think this is our first quarterly call with you asking a question.

I appreciate that. I just wanted to dig in to a little bit on Hope Creek, just kind of the extension of the fuel cycle there. Kind of what undertakings were done? I mean, was that kind of an enhanced fuel offering? Or how should we kind of think about that? Is there opportunities to kind of extend that even further?

Yes. No, Nick, it really is a lot simpler than people might make it out to be. It's just shuffling of the fuel, some different changes in the fuel design. But we didn't change to a new fuel supplier as a result, right? So this is something that's been done in the industry quite a bit. And we joked a lot about it. We had a CFO that always gave us a hard time about doing upgrades at a plant that we only had a visibility for 3 years of a life for, but he did the right thing and held us accountable a little longer-term life before we make long-term investments. So while Dan did that, we were getting smart about the changes that we could make there, and we're following what the rest of the industry has done.

I will tell you, though, we also, at the same time, did a lot of other things at that plant to continue to reinforce both the asset itself, but also some efficiencies. And I talk about things that you might not pay attention to, but we changed out some of the insulation in the cooling tower, which just changes the efficiency of that -- of the cooling tower, and it just allows us the draft that the cooling tower is going to increase, which allows you to keep the megawatts up in the middle of the summer when at other times, the heat and humidity might reduce the draft flow through that stack.

So we were looking all the time for it. And in that case, no big announcements, but I know we're running more efficiently in the summer months, which, by the way, is at the same time that we have the higher prices, right? So lots of different things that we're doing down there and the team is doing a nice job for us in identifying those opportunities. But specific to your question, on the fuel, not a big change compared to what others have done in the industry and no real opportunity at Hope Creek to make an additional change. But maybe at Salem, and I know there are some operators that are looking at moving from a 12- to 18-year cycle at PWRs. The PWR -- I'm sorry, 18 to 24 months. The BWR is what we just did at Hope Creek.

The next question is from the line of Paul Zimbardo with Jefferies.

Dan, just to follow up on the conversation on the forward curve. Obviously, there's been a pretty big move even as of late. Could you share some light on kind of what the hedging profile looks like at Power for the next few years? And just if there's been any changes? I know we had the nuclear PTC a little bit ago. Just any overall thoughts you could give on the positioning would be great.

Yes. And Paul, it isn't much and it's not very different from the characterization that we've provided in the past. I mean we said we were historically -- this goes back pre-PTC to fairly ratable 3-year hedging cycle. The PTC changed that because if you're taking a look at an overall hedging portfolio that you're trying to manage risk with, you have a risk protection from the PTC. So we said we varied from that a little bit because of the PTC. But the way we've described it is just not radically different from that ratable method. And I think if you think about it generally in those terms, you'll be in the ballpark of where we are. And that's how we've been describing it, and I think that's still a good way to describe it for you.

Okay. That makes sense. And then on the capital refresh, just to make sure I understood correctly, it sounds like you will have kind of a bigger capital refresh when we do that fourth quarter roll forward. Is that a fair interpretation? Or do you need some of that political and regulatory clarity and just it's not a fourth quarter event, but sometime later in 2026?

No. We will be doing a normal roll forward of everything on our fourth quarter call. I think that's the simple way to think about the messaging.

The next question is from the line of Carly Davenport with Goldman Sachs.

Just one quick one for me on the utility side. Just as you get towards kind of the end of the GSMP II extension period, can you just share sort of the latest there in discussions about refreshing that program as we near 2026?

Yes. We're continuing to have those discussions, Carly. And I wouldn't -- again, I wouldn't want to front run any of that, that's taking place right now. But we're in continuous negotiations that are ongoing with the BPU.

The next question is from the line of Anthony Crowdell with Mizuho.

Thanks for squeezing me in with all the welcome greetings.

Anthony, my only question was, am I welcoming you to the Devil's bandwagon? It's a big question. But we'll talk about it...

I'm on it. I agree. I'm on it. Much better than my Rangers. I guess two questions. One is, I'm sure you guys have met with both candidates. When they talk about affordability, do you think they're focused on the supplier generation side or the wire side? Do they understand the differences in the PJM impact versus just investing in the grid infrastructure? And then I have a follow-up.

Yes. No, Anthony, great question. They absolutely understand the difference. They also understand that the customer gets one bill. And so what we need to work together with whoever is successful is working on that one bill. And so that's why we keep talking about supply. It's not our traditional lane. We're here to help on that. But we are really pounding the table about the integrated resource plan no matter what happens going forward because without that, we'll just continue to flounder. We lived on the backs of some excess capacity in the area for quite some time. And now we have this challenge here. But I don't want to at all give anybody an indication that either candidate doesn't understand the issue. They absolutely understand the issue, and they know where it is.

And then the follow-up, kind of the same topic. Your company is the only company with both PJM wires exposure, but also merchant generation PJM. And as we're all looking for, whether it's a data center contract or a large load customer contract, is it possible that both segments of your business, the wires company and the generation, given the backdrop of affordability and everything else, that they actually both could win or outperform at the same time? The worry is when you see this election going on and a very high attractive price on a generation if something came about on the data center or any type of large contract would actually hurt the wires business or vice versa. I'll just leave it there.

No, it's a very fair question, Anthony, but it's one that we think about every day because we're -- at the end of the day, we're hired by the shareholders, and that's where our head's at. And we do think that there continues to be an opportunity to benefit from having both of the assets. I'll say it in that term from a generation standpoint and from a utility standpoint. I think it showed up in the way we've been able to finance the utility. That was the reason we originally talked about holding on to nuclear. It helps us in the state in conversations. It helps us with our unions, having a common union there. So just to remind everybody of that is key.

But we are laser-focused on adding value for the shareholder, and we're trying to look at that balance every day to get that optimization. So I think there is a win-win. And how it plays out will be based upon a lot of different factors over the next couple of years here.

Our last question is from the line of Andrew Weisel with Scotiabank.

First question is on the balance sheet. You've obviously long touted the strength of that and the lack of need for external equity. But I am expecting in a few months, we'll see a pretty sizable increase to the capital plan. Maybe how are you thinking about that at this point? I don't expect specifics, but are you thinking that you'll be able to continue to stay no equity?

Look, I think I'm going to start off and give it to Dan. The way I've talked about this quite a bit, both Dan and his predecessors have handled our balance sheet extremely well, and I don't think any of that's going to change as we have more opportunities in front of us. But Dan can give you any more he wants to there.

And there's not a lot without going into what we would be saying in the fourth quarter. I think we've been able to manage the business pretty well and manage the needs that we've had pretty well. And I think we're going to continue to be able to do that. We'll provide the fulsome roll forward in the fourth quarter, which will include capital rate base and overall earnings growth.

Okay. Great. Next, on affordability. Obviously, it's been talked a lot about today, and I can't watch a World Series or football game without being reminded about it. But one different approach I want to maybe think about is, obviously, no one likes seeing their bills go up, and it's been a real hard slog to get new supply added. But New Jersey is a pretty wealthy state overall. How are you thinking about it in terms of not only overall affordability, but focusing on low and lower customers? There's a lot of existing programs and talk about expanding or adding new programs. Is that maybe a different strategy that maybe could be pursued both by you and the state overall?

Yes. No, it's -- again, a very good question. It is absolutely something I think it will depend upon who is successful and how this plays out. But both candidates talk about how they have to look at things a little bit differently dependent upon the customer or in their case, the taxpayer that they've -- that they're taking care of. So we have done that in the past, Andrew, and I'm going to give you one example here where Kim Hanemann and her team at the utility reaches that all the time.

And we are doing analysis over the past week, just to try to see where things might play out from a SNAP standpoint and the impact on our customer base. And we identified about 500,000 customers that could be impacted in how we could think about those customers and making sure that we take that into account as we are in a shut-off period now for collections and how that's all handled. So our team looks at that level of detail on a regular basis and very proud of them for doing that. And I think that, that, at the end of the day, brings us a lot of goodwill in the state, not only from our customer base, but also from our policymakers.

Do you want to add anything, Dan?

Andrew, the only other thing I would add is we show a percent of wallet slide in our deck that we have for a long time. And if you take a look at that slide, there's actually 2 lines on that. One of them is for the average customer. One of them is for a lower income customer. And given the lower income and given the share of wallet, you would think that it would be a higher percent of their income given the fact that the denominator is lower. And in fact, it's not. And that, I think, is a credit to the programs that are in place and the things that are done throughout the state and that we do ourselves to help some of those that are most in need. So that is always a focus and will continue to be as we go forward.

Great. Yes. I appreciate how much you guys have been proactive on that front. One last one, if I could, just on the large load inquiries, a pretty significant pickup there to 11.5 gigawatt. Can you detail how much of that is data centers versus manufacturers? And then just very roughly the timing of the ramp-up schedules? How much of that is kind of '26, '27 versus the outer years like '29, '30 or beyond?

Yes. No, I don't have the level of detail on each of the years for you. So I wouldn't have that. It is mostly data centers. I would say, almost exclusively data centers in that number. There were some electric vehicle loads that were coming on. It has not stayed up at the same level. So everything -- but it's also edge computing more than it is hyperscalers, again, just to reinforce that point.

And I think the other thing that's really telling about the load and the interest that's coming in, it's all sticking to around that 20% number that's actually coming to fruition, which we had talked about 3 or 4 calls ago. We thought that was going to be the way this would play out and it's shown itself in the numbers as the total inquiries come in, those that are actually moving to new business are staying around 20%. So again, proud of the team and the forecast that has been done there and give you a little bit of more flavor than maybe just looking at the due numbers.

Ladies and gentlemen, I'd like to turn the floor back over to Mr. LaRossa for closing comments.

Well, thanks. I got -- I have a planned comment. I'm going to add another one. I was told by Carlotta today that this Dan's tenth year as CFO, and so your 40th call, Dan. So congratulations on getting there.

I must be exhausted.

You must be. But listen, all joking aside, we said a lot of thank yous and good luck to people moving into new roles and no place is that more important in Trenton as we go through the next week. It's been a heck of a campaign. All the polls are saying it's close. We'll see how this plays out. But what will not be close is our ability to work with whoever is successful. We stand ready, talk about rolling up our sleeves. We'll roll up our sleeves, our trousers, whatever else we need to do to make sure that we are here to help out and we're ready to work.

So good luck to both candidates as they enter the last 24 hours of the campaign. And I look forward to seeing you all in Hollywood, Florida in the next 7 days or so. Take care.

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