Public Service Enterprise Group Incorporated (NYSE:PEG) Q4 2024 Earnings Call Transcript

Public Service Enterprise Group Incorporated (NYSE:PEG) Q4 2024 Earnings Call Transcript February 25, 2025

Public Service Enterprise Group Incorporated beats earnings expectations. Reported EPS is $0.84, expectations were $0.82.

Operator: Ladies and gentlemen, thank you for standing by. My name is Rob, and I am your event operator today. I would like to welcome everyone to today’s conference. Public Service Enterprise Group’s Fourth Quarter and Full Year Results. 2024 earnings conference call and webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session for members of the financial community. At that time, if you have a question, you will need to press the star and the number one on your telephone keypad. To withdraw your question, please press star and the number two. As a reminder, this conference is being recorded today, February 25, 2025, and will be available for replay as an audio webcast on PSEG’s Investor Relations website at https://investor.pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Carlotta Chan: Good morning, and welcome to PSEG’s fourth quarter and full year 2024 earnings presentation. On today’s call are Ralph LaRosa, 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-Ks 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 differ 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 LaRosa.

Ralph LaRosa: Thank you, Carlotta. Thank you, everyone, for joining us this morning to review PSEG’s 2024 results and our outlook for the business going forward. Let’s start with our strong results. PSEG reported net income of $0.57 per share for the fourth quarter of 2024 and $3.54 per share for the full year. For non-GAAP operating earnings, PSEG reported results of $0.84 per share for the fourth quarter and $3.68 per share for the full year, which was at the top of our 2024 guidance range. Our reported results for 2024 also marked the twentieth consecutive year that we have met or exceeded management’s non-GAAP operating earnings guidance to investors. We are proud of this track record and confident that our team will continue to build on it.

We were also successful in achieving our strategic and regulatory objectives for 2024. First, we settled PSE&G’s first electric and gas rate case with a balanced outcome that recovers prudent investments, maintains our favorable affordability profile, and mitigates variability for our customers. Second, PSE&G received approval to invest $2.9 billion in its Clean Energy Future Energy Efficiency II program over the upcoming six-year period. This second phase of the BPU statewide energy efficiency framework has resulted in a meaningful increase to the program, which will enable us to make investments at more customer premises to reduce energy usage, improve affordability, and reduce carbon emissions. Third, we efficiently executed the utility’s planned $3.6 billion capital spending program and notably completed the advanced metering infrastructure program on time and on budget, installing approximately 2.2 million smart meters in customers’ homes and businesses.

And fourth, and I am very happy to say, we implemented new deferral mechanisms for pension and storm costs. This increases the predictability of PSE&G’s future financial results and stabilizes rates for customers. Speaking of customer rates, the new base rates that were placed into effect last October represented an annual increase of about 1% per year since our last rate case in 2018. Also, last October, PSE&G lowered its gas commodity charge to $0.33 per therm for the winter of 2025, the third supply charge reduction since January of 2023. All of these steps will serve to moderate the outcome of the BGS auction result, which will increase customer electric bills this June 1. PSE&G’s record reliability, affordability, and customer satisfaction continue to be a valuable combination.

We were recently named number one in customer satisfaction with residential electric and gas service in the East among large utilities by J.D. Power in 2024. The utility also received the PA Consulting 2024 ReliabilityOne Award for the Mid-Atlantic region for the twenty-third consecutive year. I want to take a moment to recognize and thank all of our over 13,000 employees for the incredible teamwork and individual efforts that delivered 2024 strategic objectives and financial results. So let’s turn to our outlook for 2025, starting with slides five and six. For the current year, we have initiated PSEG’s non-GAAP operating earnings guidance at $3.94 to $4.06 per share, which is up by 9% at the midpoint over our 2024 reported results. Our 2025 guidance midpoint is the new base year for PSEG’s 5% to 7% non-GAAP operating earnings CAGR at the nuclear production tax credit threshold for the 2025 to 2029 period.

I would also note this CAGR, while unchanged as we pursue incremental revenue opportunities at PSEG Nuclear, starts from a $4 midpoint of 2025 guidance that is 9% higher than our 2024 non-GAAP results. For 2025, we plan to invest $4 billion across the enterprise, driven by regulated investments. We also raised PSEG’s 2025-2029 capital spending plan to $22.5 billion to $26 billion. This increase is largely comprised of incremental investments at PSE&G to meet growing customer demand, modernize infrastructure, and further execute on previously mentioned energy efficiency programs. Please see slides fourteen and fifteen for the updated regulated capital spending plan and rate-based projections for the 2025 to 2029 period. This updated five-year capital spending program is expected to support a PSE&G rate base CAGR that continues its 6% to 7.5% over the upcoming five-year period, which grows from a starting point of approximately $34 billion, which is notably 12% higher than the year-end 2023 balance.

Something new for PSE&G this year has been a significant increase in inquiries from large load and data center customers. Last year at this time, these totaled under 400 megawatts. Today, the interest has grown to 4,700 megawatts, which includes both mature leads and initial inquiries. This pipeline represents an over twelve-fold increase over the last year. The average size of these project leads is in the 100-megawatt range, which can often fit within PSE&G’s existing robust utility transmission infrastructure. We are responding to these inquiries in under four months on average. Approximately 25% of the 4,700 megawatts of new business leads have been incorporated into PJM’s 2025 system peak load forecast. As I mentioned earlier, the basic generation service auction results will raise the residential bill starting June 1.

This increase is being driven by the significant rise in the capacity prices coming out of PJM’s latest RPM auction conducted last July, which reflects growing energy demand combined with the need for new power generation. As a reminder, electric supply is a pass-through cost that PSE&G does not earn a profit on. Even with this upcoming BGS increase, our combined bill still compares favorably to all other utilities in New Jersey, and we remain a leader across the nation on our low share of wallet comparison. PSE&G’s bill remains at about 3% of total income for medium-income customers and even lower, still approximately 2% for low to moderate-income customers that take advantage of payment assistance programs. Turning to PSEG Power and Other, while the PTC threshold provides sufficient support to meet PSEG’s 5% to 7% long-term growth outlook, we continue to pursue nuclear revenue growth opportunities at PSEG Nuclear that would be incremental.

These opportunities to contract portions of our nuclear output under long-term contracts can also benefit the economic development interests of the state in helping to attract AI hubs to New Jersey. We had an exceptional year in 2024, continuing to execute on our business plan and, in doing so, have made our businesses more predictable and our earnings growth more visible. These benefits will enhance our ability to drive our future performance that prioritizes maintaining our financial strength, making disciplined investments, and delivering operational excellence. Another PSEG distinction we are proud to extend is our ability to continue supporting another robust five-year capital program without the need to issue new equity or sell assets through 2029, even with the latest $3.5 billion increase over the prior plan.

Before I conclude, I want to highlight that our Board of Directors recently announced a $0.12 per share increase in PSEG’s annual common dividend to an indicative annual rate of $2.52 per share for 2025. This is PSEG’s fourteenth consecutive annual increase, made possible by a long-standing commitment to financial discipline that has enabled us to pay a common dividend to our shareholders for 118 consecutive years. I’ll now turn the call over to Dan to walk you through the results for the quarter and our outlook for the 2025 through 2029 period, and then rejoin the call for Q&A.

Dan Cregg: Thank you, Ralph, and good morning, everybody. As Ralph mentioned earlier, PSEG reported net income of $3.54 per share for the full year of 2024, compared with net income of $5.13 per share for 2023. And non-GAAP operating earnings for the full year of 2024 were $3.68 per share compared to $3.48 per share for 2023. For the fourth quarter of 2024, net income was $0.57 per share compared to $1.10 per share in 2023. And non-GAAP operating earnings were $0.84 per share in the fourth quarter of 2024 compared to $0.54 per share in 2023. Slides eight and ten detail the contribution to non-GAAP operating earnings per share by business segment for the fourth quarter and full year of 2024, and slides nine and eleven contain waterfall charts that take you through the 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 2024 net income of $0.75 per share compared to $0.58 per share in 2023. PSE&G had non-GAAP operating earnings of $0.75 per share for the fourth quarter of 2024 compared to $0.59 per share in 2023. Utility results were driven by the implementation of new electric and gas-based distribution rates. The new rates went into effect on October 15. And the fourth quarter results reflect the impact of seasonality of gas revenues during winter months. 2025 comparisons will benefit from a full year of new rates for both gas and electric revenues. Compared to the fourth quarter of 2023, transmission margin was a benefit of $0.02 per share due to higher recovery of investment. Distribution margin increased by $0.16 per share and reflects the impacts of the rate case on gas revenues in the fourth quarter.

Distribution O&M expense was a penny per share favorable compared to the fourth quarter of 2023, primarily due to the timing of spending. Depreciation and interest expense rose by a penny per share and $0.02 per share, respectively, compared to the fourth quarter of 2023, reflecting continued growth in investment and higher interest expense. Lower pension and OPEB income resulting from the cessation of OPEB-related credits, which ended in 2023, resulted in a $0.02 per share unfavorable comparison to the year-earlier quarter. And lastly, the timing of taxes recorded through an annual effective tax rate, which nets to zero over the full year, and other taxes had a net favorable impact of $0.02 per share in the fourth quarter compared to 2023.

And for the full year, PSE&G results reflect higher earnings from increased investment in infrastructure replacement and energy efficiency, as well as the rate case, partially offset by higher interest and depreciation expense from higher investment balances. Weather during the fourth quarter, as measured by heating degree days, was 12% warmer than normal but 3% cooler than the fourth quarter of 2023. As I’m sure you know, weather variations have a minimal impact on PSE&G’s utility margin because of the conservation incentive program. This decoupling mechanism limits the impact of weather and other sales on electric and gas margins while helping PSE&G promote the widespread adoption of its energy efficiency program. Under the CIP, the number of electric and gas customers is what drives margin, and each segment grew by approximately 1% in 2024.

Capital spending, as Ralph mentioned, PSE&G invested approximately $0.9 billion or $900 million during the fourth quarter, and for the full year 2024, our capital spending totaled $3.6 billion, slightly higher than our original plan of $3.4 billion based on the continued execution of our electric system reliability programs, including Energy Strong and last-mile spend in the IAP, our ongoing gas infrastructure replacement spending, as well as our energy efficiency program. For 2025, we plan to invest approximately $3.8 billion in regulated investments focused on infrastructure modernization, energy efficiency, and meeting growing demand and electrification initiatives. We’ve rolled forward our five-year regulated capital investment plan through 2029, amounting to $21 billion to $24 billion compared to our prior plan of $18 billion to $21 billion.

The $3 billion increase in regulated under PSE&G’s existing infrastructure programs and the CEF-EE II Program. Our 2025 to 2029 regulated capital investment plan is expected to produce compound annual growth in rate base of 6% to 7.5%, starting from a year-end 2024 rate base of approximately $34 billion, and as Ralph mentioned, an increase of approximately 12% over the same number for year-end 2023. Moving to PSEG Power and Other. For the fourth quarter of 2024, PSEG Power and Other reported a net loss of $0.18 per share compared to net income of $0.52 per share in the fourth quarter of 2023. Non-GAAP operating earnings were $0.09 per share for the fourth quarter compared to a non-GAAP operating earnings loss of $0.05 per share in the fourth quarter of 2023.

For the fourth quarter of 2024, net energy margin rose by $0.18 per share driven by higher recontracting prices at nuclear, which includes the net impact of the nuclear PTC that took effect January 1, 2024. As anticipated, we realized a significant portion of the increase in the 2024 gross margin over 2023’s gross margin during the second half of the year, based upon the shape of our underlying hedges. O&M was a penny per share unfavorable, interest expense was $0.02 per share higher, reflecting incremental debt at higher rates, and lower pension income and OPEB credits were $0.01 per share unfavorable versus the fourth quarter of 2023. Taxes and other were a penny per share favorable compared to the year-earlier quarter. On the operating side, the nuclear fleet produced approximately 7.3 terawatt-hours during the fourth quarter and approximately 31 terawatt-hours for the full year, running at a capacity factor of approximately 86% and 90% for the quarter and full year, respectively.

Touching on some recent financing activity, as of the end of December, PSEG had total available liquidity of $2.6 billion, including approximately $100 million of cash on hand. Through December 2024, cash from operations was strong, though well below the 2023 level, which was substantially helped by the return of cash collateral. Our cash collateral balance was approximately $250 million as of December 31. We’ve supported our strong liquidity position. Last November, PSE&G repaid its $250 million 3.05% secured medium-term notes or MTNs upon maturity. And in December of 2024, PSEG Power entered into a new 364-day variable rate term loan for $400 million, supported by the strength of its cash flow. And also in December, PSEG Power amended its existing $1.25 billion variable rate three-year term loan agreement to extend the maturity from March to June of 2025, which just helps manage our cash position during the upcoming year.

At the end of 2024, Power had $1.65 billion of debt outstanding, with $1.25 billion swapped to a fixed rate, mitigating fluctuations in interest rates through March of 2025. And given our swaps, we continue to have a low level of variable rate debt, approximately just 7% of total debt at year-end. Looking ahead, our solid balance sheet supports the execution of PSEG’s five-year capital spending plan dominated by regulated CapEx without the need to sell new equity or assets and provides for the opportunity for consistent and sustainable dividends. Now before I conclude my remarks, let’s review some earnings drivers for 2025, and those are outlined on Slide five. The most impactful driver will be the implementation of new distribution base rates in effect for the full year.

Recall that the fourth quarter of 2024 is a seasonal peak for gas, which comes into play in a projection of the new base rates over a full year. Also note electric seasonality will produce a similar impact from the third quarter of the year. In addition, clause-based recoveries for investments in GSMP, the Infrastructure Enhancement Program or IAP, and the CEF-EE II program will also add to the 2025 utility margin. Partly offsetting these positives are higher O&M, interest, and depreciation expense, reflecting higher investment balances of PSE&G, as well as higher interest expense at PSEG Power and parent related to refinancing maturities at higher current interest costs. At PSEG Nuclear, our 100% owned Hope Creek nuclear unit has a scheduled refueling set for the fall of 2025 that will include the fuel cycle extension work to extend its next scheduled refueling in 24 months, for the fall of 2027.

And as a reminder, the zero-emission certificate amounts earned by our New Jersey nuclear units will conclude in May of 2025. In closing, we delivered our twentieth year in a row of meeting or exceeding our guidance. And we carry that confidence forward to our full-year 2025 non-GAAP operating earnings guidance of $3.94 to $4.06 per share, approximately 9% higher at the midpoint over 2024 results. We also expanded our 5% to 7% non-GAAP operating earnings CAGR through 2029, starting with 2025 as the base year. As Ralph mentioned, we’re continuing to pursue incremental revenue opportunities at PSEG Nuclear, which could enhance our long-term growth CAGR relative to the range that we provided based on the PTC. That concludes our formal remarks, and we are ready to begin the question and answer session.

Operator: Thank you. Ladies and gentlemen, we will now begin the question and answer session for members of the financial community. If you have a question, please press the star and the number one on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing the star and the number two. If you are on a speakerphone, please pick up your handset before entering your request. One moment, please, for the first question. The first question comes from the line of Shar Pourreza with Guggenheim Partners. Please proceed with your questions.

Q&A Session

Shar Pourreza: Hey, guys. Good morning.

Ralph LaRosa: Morning, Shar.

Dan Cregg: Hey, Shar. Morning, Shar. Morning, Dan. So just, Ralph, starting off on the nuclear side with Artificial Island, do you see sort of commercial discussions being delayed with the recent actions at FERC? Does the complexity of, like, behind-the-meter deals change the deal structure to potential opportunities around the side of the meter? And any sense on timing, especially given the governor’s ambitions? Thanks.

Ralph LaRosa: Yeah. Thanks, Shar. So I’m gonna let Dan give you some details on that. But since you mentioned the governor, I would just say this on that front. You know, he, well, the New Jersey Economic Development Authority has made a few comments about their wind port and specifically that they’re looking at alternative uses for that wind port. So that’s one thing that we just want to point out. The governor has also mentioned that he has, in a recent call-in show, that they’re looking at alternate uses for it. So you kind of put those pieces together, and we know that there’s some interest from the governor’s standpoint and from New Jersey’s standpoint to continue for us to look to pursue these opportunities. And, you know, as far as the timing issue that you hit on the back end, and then we’ll kind of address generically the upfront piece.

Dan Cregg: Yeah. I think, Shar, our messaging there is really fairly consistent. I think we’ve continued to see interest, we continue to have discussions with multiple parties for various elements of what we’re talking about, and that interest remains strong. So I think, you know, on FERC as well, I think that, while it would have been great to have complete answers throughout everything from what FERC said, I don’t know that we necessarily expected that, and we gotta wait for some, but I think directionally what they said was favorable for the flexibility to do what you want to do, and those details are yet to come. So we’ll continue to see what happens there, but I think our messaging is really consistent with respect to what’s going on related to nuclear.

Ralph LaRosa: And the glass half full on deferred charges to reinforce that. But the timing of it is pretty aggressive, and it was a clear message from FERC on their need to get to a solution here. So we took that as a positive. We certainly could have been in a different place. At least for the number one potential solution behind the meter. It’s still in front of the meter, and there’s still other offload opportunities there.

Shar Pourreza: That’s a fair point. I appreciate that, Ralph. And then just, well, I just want to make sure. Does the PSE&G pipeline of opportunities and inquiries you just highlighted that’s over four gigawatts, does that negate any of the Artificial Island opportunities? Like, in other words, any chance that a potential deal with Artificial Island kind of shifts towards the front of the meter with PSE&G, or are the Artificial Island counterparties completely separate from the PSE&G conversations you just highlighted? Thanks.

Ralph LaRosa: Yeah. So I think the message on the 4,700 megawatts, which includes other things besides data centers, we were clear, and there was data centers plus large load, and believe it or not, we’re still seeing some large electric vehicle interconnections that are taking place. So it’s a number of items. I think there’s two takeaways, though. That we want to make sure, first of all, from a data center standpoint, there’s interest from the industry in New Jersey. When you see a 4,700 megawatts showing up, that’s a request that is showing up. So that’s part one. And part two is, the state’s marketing in this area has been working. They’ve got a helix that they’ve announced in New Brunswick, their number Nokia of Bell New Jersey Bell Labs just announced that they’re gonna be in New Brunswick. So there’s a number of efforts that are taking place or taking hold, and we just look forward to the momentum continuing.

Shar Pourreza: Fantastic. Thank you guys so much. Appreciate it and great execution.

Operator: The next question is from the line of David Arcaro with Morgan Stanley. Please proceed with your question.

David Arcaro: Hey, thanks. Good morning.

Ralph LaRosa: Morning, David.

Dan Cregg: Hey, David. How are you doing?

David Arcaro: Let me see. I guess the PJM auction has been getting a lot of attention recently. FERC is gonna be, you know, relooking at auction structures, and a number of changes are underway now. I was wondering if you could comment on how you’re thinking about the outlook for the PJM market, you know, what could change? Are there possibilities of structural changes here? And how do you navigate that, maybe both from a customer impact and for your nuclear fleet?

Ralph LaRosa: Yeah. So I think the way we are specifically addressing this is by setting all of our targets off the PTC floor. We’ve been very clear about that and the impacts there. Well, from a customer standpoint, we will do everything in our power to help keep customer costs down from an affordability standpoint. We have done that. We will continue to advocate on that behalf. I just don’t know whether or not the premise of the question of the PJM market is valid because I don’t know if there is a PJM market anymore, and we’ve been talking to that for quite some time. So, you know, my concern there is mostly from a reliability standpoint. Are we gonna be able, in this construct, to attract generation to the PJM region as a whole?

And if so, is it gonna be in a timely enough fashion for everything that we have going on in the region? So those are the questions at hand that’s really focused on reliability and affordability for us. Gonna keep advocating on customers’ behalf in both of those areas.

Dan Cregg: Yeah, I think, you know, just to add on to that a little bit, David, I think those are the longer-term elements that are going to be really important for resource adequacy, and it’s vital to get that right, and I think there’s still work to be done there. I think for the nearer term, you know, to the extent that this collar in pricing ends up being put forward for a couple of years, it can give you a little bit more stability as to where things are going to turn out. But I go back again to Ralph’s first comment that what we’re basically putting out from a financial standpoint is the PTC floor. So to the extent that things move below that, that floor is there. If it moves above that, then there could be some potential benefit for us. But I think job one is getting resource adequacy right.

David Arcaro: Yeah, absolutely. I appreciate that color. And maybe somewhat related, I guess, you know, is the uncertainty a deterrent broadly looking at the market? You know, there’s been, I guess, with all these changes being considered for the auction construct and looking at the resource adequacy challenges ahead in the market, are you seeing that, you know, lowering the interest levels from some of these customers? Any perspective there would be helpful.

Ralph LaRosa: Yeah. No. I point you back to the data in the prepared remarks where we talked about the increase from 400, I think, megawatts to 4,700 megawatts of interest in large load in New Jersey alone. So really can’t talk for the other jurisdictions, but certainly in New Jersey, we’re still seeing that uptick that we reflected in those remarks.

David Arcaro: Yep. Got it. That’s fair. Great. I’ll leave it there. Thanks so much.

Operator: Our next question is from the line of Nicholas Campanella with Barclays. Please proceed with your questions.

Nicholas Campanella: Hey, good morning, everyone. Thanks for taking the time.

Ralph LaRosa: Morning, Nick.

Nicholas Campanella: Hey. So I just want to put a finer point on Shar’s question just in terms of bringing a, you know, maybe a commercial deal forward for the nuclear fleet. Are you still watching and waiting for the state at this point, or is it really waiting on FERC? And then just a follow-up to that is just as we kind of think about the timeline, if a large load customer was to be able to connect to the facility, what’s the timeline for ramp? And can that affect earnings in 2027, or is it more later dated towards the end of the decade? Thanks.

Dan Cregg: Yeah, Nick, I think that we’re not waiting on anything on the state, and I think we’re not waiting on anything either from the standpoint of FERC. I think that some of the details with respect to what flexibility there can be may come out of where that goes. But I think there’s the ability to continue work, and we are continuing. You know, it’s interesting. I do think that there was some expectation by some that we might see something more definitive come out of FERC. I will say that they did highlight thirty days and another thirty days that they seem to have understood the urgency in what they said, even though we didn’t get complete clarity in what they did. So I think that urgency will be helpful as we continue to go forward, but it’s not stopping anything. I think, from the standpoint of some final details as to how some things can be done, it may add some flexibility.

Nicholas Campanella: Okay. And then just, like, the ramp for a customer, just it does take time for these data centers to ramp up, it seems like. And I’m just wondering, is this something that you think can impact the outlook on the five-year plan, or is it more longer dated than that?

Dan Cregg: Yeah. Think about it in a couple of different ways, Nick. I would say that to the extent that there is a sale of what exists today, then something could happen quicker. To the extent that somebody needs to build a data center for that power to flow to, it’s gonna take a little bit longer. So I think depending upon the nature of where things go, and there’s a couple of things that we’re working towards, that’s gonna dictate the timing as to when you might see some impact on the bottom line.

Nicholas Campanella: Okay. I appreciate that. And then just following up on the capacity auction commentary. Just wanted to try to understand, you know, if we kind of continue to clear near the $270 level, how does that kind of impact your gross receipts calculation at the $27 and where you are in the range? Thanks.

Dan Cregg: Yeah. So I would say, you know, as you go out in time, you’re going to have to take a look at what’s in place from the standpoint of hedging and where the market goes, and then you’re gonna lay that capacity price on top of it. I’ll remind you that at least in the structural formation of how the capacity auction is set, it’s based upon a net cone, which is net of energy. And I think that as you do see one price rise, the other price should react in the opposite direction, the prices being energy and capacity. So we saw some of that when we saw the last clear go up. We saw a temporary decline in energy prices, and so there is a relationship there. I think that if I were you and I was looking out in time, I think to the extent that you saw increases in energy, and you thought that we were gonna clear higher, it would move us higher in the range or above the range depending upon where you go with it.

Right? We have the comfort of the floor. I think the stability of that is really important to us and should be to you to think about how the results are gonna go. But that upside is there to the extent that markets move up.

Ralph LaRosa: And the only thing I would add is not to forget in those calculations that you make there’s an inflation adjustment to that floor. So in the out years, that will impact where those lines cross into, which I think was the root of your question.

Nicholas Campanella: Absolutely. Absolutely. And I appreciate the commentary on the range. That’s helpful. Thank you.

Dan Cregg: Thanks.

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

Paul Fremont: Great. I guess, first question, can you give us sort of any color on hedges that you have at PSEG Power? Normally, I guess, you would be at ninety percent for this year. How should we think about sort of, you know, past guidance versus where you are right now?

Dan Cregg: Paul, what we have done and what we have said that we’ve done is try to balance the existing uncertainty of the definition of gross receipts in order to try to make sure that we’re going forward in a way that minimizes our risk of results, understanding that we do have a PTC floor. What I would tell you directionally is that has not resulted in kind of radical shifts from the standpoint of what those hedging percentages would have been back when we had more of a three-year ratable. So, you know, to your point, if you want to think about being somewhere in the nineties in 2025 and maybe two-thirds in 2026 and a third in 2027, that’s what we would have told you based upon a more ratable approach, and while we’ve made some movements to that, don’t think of that as being very radically different than the ratable approach.

Paul Fremont: Great. And then I guess you used to provide sort of a breakout of net income guidance between the utility and PSEG Power and Other. Is there a reason why you’ve not done that for this year?

Ralph LaRosa: It’s just I think we made that change a year or two back, Paul, and we’re comfortable with leaving it at the enterprise level. It’s ninety percent utility. We’ve been pretty consistent about that. So give or take in that range, but we’re comfortable discussing this at the enterprise level.

Paul Fremont: And then just to sort of follow-up on Nick’s question, the gross margin sensitivity that you provide includes capacity prices to the extent that the auctions continue.

Ralph LaRosa: That’s a little bit of a question in there.

Paul Fremont: Oh, the question is, should we, in other words, do you give a dollar per megawatt hour as sensitivity? Yep. Does that include the dollar per megawatt hour equivalent of the capacity auction?

Dan Cregg: Yeah. Think about that as an all-in price that you would see for a megawatt hour. And, yes, you’d have to variableize that fixed charge, but, yes, that’s right with me. Yep.

Paul Fremont: Great. Thank you very much.

Ralph LaRosa: Thanks, Paul.

Dan Cregg: Thanks, Paul.

Operator: The next question is from the line of Paul Zimbardo with Jefferies. Please proceed with your question.

Ralph LaRosa: We might have lost Paul. Might have lost him.

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

Paul Patterson: Hey, Paul. We’re on a four-roll right now, so we’ll keep it going.

Ralph LaRosa: Hey, Paul. Good to go. He’s a charm. So just, I mean, it’s back to the survey. I’m sorry, back to the original question about the timing on the colocation. I noticed the language that the chair reiterated on Friday and what have you. But what does that actually mean in terms of when you think that actual order might come out?

Dan Cregg: Well, I have to take it at their face value and that they said they want to come out shortly thereafter. I think it was the words that came out in the last statement. So, you know, I mean, we could guess at what shortly means, but I think they’ve been pretty consistent in delivering on what they’ve said they’re gonna do. So I wouldn’t expect it to be much beyond the sixty days if that is the path that’s taken.

Paul Patterson: Okay. And then you also said something that was interesting about the PJM market or the lack thereof. This is something that obviously is being, you know, there’s just a lot of activity, a lot of discussion, a lot of apprehension, I think, about reliability and pricing and what have you. Do you have anything you’d like to share in terms of what potentially might, what you might be looking for, I mean, in terms of maybe a longer-term setup or something, or just what are your thoughts about it? I mean, I’d just be curious as to what you think might come out of all the examination of this market, quote-unquote, and how it might evolve.

Ralph LaRosa: Well, I think it’s gonna depend upon what state you’re in and what the economic policies of that state are. You know, you certainly hear certain positions being taken in Pennsylvania. You see positions being taken in other states. I’ll just talk specifically to New Jersey. You know, we have the BGS, which is the law of the land here from a generation standpoint, and the utilities are not involved in that process. We do have PSEG Nuclear, which is involved right now in the generation side of the business. But New Jersey is at a crossroads. And I think right now we’re all trying to figure out the best way to move forward. I don’t think there’s a clear answer on it. So I don’t want to front-run any policy decisions that are being made in the state. But it’s certainly something we need to continue to discuss for the two reasons that we stated upfront: affordability for customers and reliability.

Paul Patterson: Absolutely. Any idea when we might see something of a proposal or…

Ralph LaRosa: Yeah. There’s some talk about it. There’s actually a master plan coming out, but look, Paul. To be honest about all of this, I think there’s some decisions that have to be made that will probably bridge administrations here in New Jersey. Right? So I think what we’re trying to do as a company is continue to educate everyone on the issue and try to help people think through, you know, different opportunities that the state of New Jersey could pursue.

Paul Patterson: Okay. Great. I really appreciate it. Thanks so much.

Operator: The next question is from the line of Carly Davenport with Goldman Sachs. Please proceed.

Carly Davenport: Hello.

Ralph LaRosa: Hey, Carly.

Carly Davenport: Hey. Thanks for taking the question. Sorry to put a stop to the Paul train there. But thanks for all the color so far on the power side. Maybe just one from me on the GSMP III filing. Do you still expect to revisit that this quarter? And then would that be upside to the plan in 2025, or are there already assumptions kind of baked in after the GSMP II extension kind of runs itself out?

Ralph LaRosa: Yeah, Carly. Yeah. We are starting to have those conversations, and it is in the plan. It’s a simple answer to both of those things. So, you know, that work is part of our core business activities and something we expect to continue. So those conversations have started.

Carly Davenport: Great. Thank you for that. I’ll leave it there.

Ralph LaRosa: Thanks, Carly.

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

Paul Zimbardo: Can you hear me? Hopefully, we’re on the train.

Ralph LaRosa: We got it. Yeah. We got it. We got it. There we go.

Paul Zimbardo: Yeah. No. Thank you. The neighborhood reception is not always the best. But no. Thank you very much. I wanted to follow up on a little bit just on the balance sheet side. I saw the no additional equity in the outlook even with the CapEx increase. Could you level set what was the actual 2024 FFO to debt and kind of where do you envision the credit metrics going throughout the plan?

Dan Cregg: Yeah. Paul, I don’t have that at my fingertips, and I think you’ll be able to pull that together when the K comes out, so I won’t jump that. But, you know, we continue as we look forward and as we’re putting forward, you know, the forward-looking guidance for the next few years, we continue to be in that mid-teens range and are in a pretty good place from that perspective, which is the reason it gives us the comfort to say exactly what we did say within our prepared remarks.

Paul Zimbardo: Okay. Got it. I’ll follow up on that one. And then shifting a little bit on going back to the BGS, looking at the one-year results for commercial industrial, for your zone, it was very high on a dollar per megawatt day basis, almost $700. And I know that you did not purchase a date and not with your, you know, unregulated fleet. Just is there any thoughts or kind of takeaways of what that indicates to what New Jersey could look like without robust supply response to customers?

Ralph LaRosa: Yeah. So, Paul, we were, I think, around $17 per megawatt day all in, in the numbers that were generated by the state and published. And I think that there were other ones that were up in the twenties. These are residential provider of last resort rates that are in that BGS. Right? So first of all, customers certainly have the opportunity to shop. I would expect some of that to happen from third-party suppliers. But for those customers that are relying on BGS, it is something that we have to lean in on, certainly from a payment assistance standpoint, which we’re working on, and then also from, you know, our energy efficiency program and continuing to get the energy efficiency message out for customers and helping them gain access to those programs. So those are the two pieces that I would say it means to us in the state of New Jersey. But we are higher but not as high as some other areas in the state.

Dan Cregg: Yeah. I mean, just a reminder on that BGS contract that that’s not something that we profit from. That’s a pass-through coming from the supply providers, and, you know, the biggest element related to the increase that we are seeing is coming from the auctions that happened at PJM. And so I do think you probably will see more interest in shopping, but I think at the end of the day, the providers are gonna have to go back to that same well, which had some higher prices in the last auction.

Paul Zimbardo: Okay. And did you go by what’s this, like, commercial and industry? Like, there I saw it cleared at $696 a megawatt day for PSE&G. Just give you any call time on that. Thank you.

Dan Cregg: Yeah. I mean, I think it’s still coming from the same supplier base, just with a different calculation going to them, and I think the same ability to shop is gonna exist there. So I think you’ve got a parallel dynamic that’s going on within that sector as well.

Paul Zimbardo: Okay. Thank you very much.

Dan Cregg: Thanks, Paul.

Operator: Thank you. Our final question is from the line of Anthony Crowdell with Mizuho. Please proceed with your question.

Anthony Crowdell: Hey. Good morning, Dan. Good morning, Ralph. Just a follow-up quick follow-up to Paul Patterson and kind of the comment you’re making about maybe the PJM market. I don’t know if you said it doesn’t exist or whatever. Just is the state of New Jersey in a net long position on generation? And if so, what’s the reserve margin there? Or do you have a reserve margin?

Ralph LaRosa: Yeah. So the state of New Jersey does not have an integrated resource plan. So there is not a, you know, there’s not a reserve margin set for the state of New Jersey that anybody, you know, could quote you. But we are short. Right? So if you look at some of the information that’s out there, New Jersey is a net importer, especially on the peak days. So we look to PJM, and PJM has still, the last numbers I saw were we had about 2% more margin than what their target was. Right? If the question is, as this load comes in, where do we move to and how and where does that reserve margin get to, which is the need for the additional generation of a resource adequacy conversation we keep having.

Dan Cregg: Right. So as Ralph said, you know, peak times are gonna be different. Off-peak seasonal, it matters a lot when you are talking about it, but across the year, we are a net importer.

Anthony Crowdell: Options and this is just a question. You know, obviously, you said they need a resource adequacy plan. But is it similar to maybe other states that have gone maybe like a, I’ve got the acronym, I think maybe FRR, just pulled out the generation and the load? Is that one of the multitude of options that the state could face, or should I be thinking about something different?

Ralph LaRosa: Yeah. No. I absolutely believe that that’s something that the state could consider. Right? The state could go in a bunch of different paths, but BGS is the, you know, I keep referring back to that from, you know, back in 2000 time frame. When we deregulated and the rules were put in place, and we count on PJM. Right? And that’s the market that’s out there. So when I say I’m not sure about what kind of market it is, it’s a market that has been influenced by and by a number of factors. And so they’re trying to balance affordability and reliability with a free market, and that’s a tough thing to do. So we’ll see where it goes. But it’s certainly something that from a state of New Jersey standpoint, the desk about because we’ve gotta get it right as we participate in that market.

Anthony Crowdell: Great. Thanks for taking my questions.

Dan Cregg: Thanks, Anthony.

Operator: Thank you. I’d like to turn the floor back to Mr. LaRosa for closing comments.

Ralph LaRosa: Well, thank you, Rob. So look, I think we had a lot of conversation about where we expected it to be, which was on a lot of the nuclear output and the potential data centers and so on and so forth. But I don’t want to lose sight for one minute of all the good work that was completed back in 2024, and that’s not a complaint about what we talked about, but simply a statement of a fact that the team executed on everything that it had in front of it last year, not the least of which was the rate case, the storms that came through this area, the cold weather snaps that we had, and so on and so forth. So I want to end with a comment that was made in the beginning of, in the middle of my prepared remarks, which is a thank you to the employees that are here at PSEG. They do a fantastic job day in and day out, and that shows up in a multitude of areas. So thank you. Thank you. Thank you. We look forward to seeing you at one of the roadshows.

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