Public Service Enterprise Group Incorporated

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 Third Quarter 2024 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we'll conduct a question and answer session for members of the financial community. At that time, if you have a question, you'll need to press star and the number one on your telephone keypad. To withdraw your question, please press star and the number two. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded today, November 4th, 2024, 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.

Good morning and welcome to PSEG's third quarter 2024 earnings presentation. On today's call are Ralph LaRosa, Chair, President, and CEO, and Dan Craig, 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 10Q 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 the prepared remarks, we will conduct a 30-minute question and answer session. I will now turn the call over to Ralph LaRosa.

Thank you, Carlotta. Good morning to everyone, and thanks for joining us on the call to review PSEG's third quarter results and update you on two important regulatory filings that we successfully resolved through the settlements that were approved by the New Jersey Board of Public Utilities last month. Let's start with our financial results. PSEG reported net income of $1.04 per share for the third quarter of 2024, bringing results for the first nine months to $2.97 per share. This compares to net income of $0.27 per share and $4.03 per share for the third quarter and first nine months of 2023, respectively, which was impacted by the pension lift out that occurred in August of 2023. Our results for the quarter and year-to-date periods are summarized on slides 7 and 9 in the webcast slides. BSEG's non-GAAP operating earnings were $0.90 per share for the third quarter of 2024 and $2.84 per share for the first nine months of the year. This compares to non-GAAP operating earnings of $0.85 per share and $2.94 per share for the third quarter and first nine months of 2023, respectively. As a reminder, our non-GAAP results exclude the items shown in attachments 8 and 9, which are included in the earnings release. Dan will provide a detailed financial review later in the call, but I want to note that the solid operating and financial results we have posted for the third quarter and year-to-date period enable us to narrow our original full-year 2024 non-GAAP operating earnings guidance from 360 to 370 cents per share to a range of 364 to 368 per share. This updated and narrow range reflects the implementation of PSEG's new base distribution rates that went into effect on October 15, and PSEG Power's realization of a significant portion of its 2024 gross margin during the second half of this year. On the operating front, during the third quarter, summer weather in New Jersey returned to normal following a second quarter that was the warmest we've experienced in more than 55 years. We have seen the devastating impacts of hurricanes and storms in many parts of the country. Fortunately, the hurricane season in our service territory has been quiet thus far, and we have been pleased to send mutual aid to some of our southern peers. PSE&G met its 2024 summer peak load of 10,152 megawatts on July 16th with temperatures of 98 degrees Fahrenheit that our transmission and distribution network operated as expected with high reliability and minimal outages. At PSEG Power, our merchant nuclear fleet continues to perform well, supplying New Jersey and the PGM grid with reliable 24 by 7 carbon-free energy. We also continue to pursue long-term growth opportunities in nuclear, including incremental output and long-term contracts at potentially higher prices. The attributes of these nuclear facilities is helping to attract new technology-based businesses to the state, and the results of those long-term opportunities would be incremental to PSEG's stated 5-7% long-term non-GAAP operating earnings growth rate. In October, PSEG nuclear began the coast down of Salem Unit 2, which had just completed a 527-day breaker-to-breaker run to begin its scheduled refueling. The Salem Station also recently received its third consecutive exemplary rating from the Institute for Nuclear Power Operators, the Peer-to-Peer Operations and Safety Benchmarking Group. Switching to regulatory activity, we are pleased to have successfully resolved two major regulatory filings last month, PSE&G's base rate case and the second phase of its Clean Energy Future energy efficiency programs. First, the BPU approved PSE&G's multi-party settlement of its first base electric and gas distribution rate case since 2018, with new rates effective October 15th. We appreciate the work done by all parties to achieve a balanced settlement that provides recovery of all of our prudent capital investments to reliably serve customers while also preserving affordability. The terms of the settlement provide for an additional $505 million in annual revenues, including recovery of previously deferred costs and an incremental flow back to customers of tax benefits due to accelerated deductions and prior federal tax rate changes. The updated revenue requirement is based upon a distribution rate base of $17.8 billion, a return on equity of 9.6%, and an equity ratio of 55% of total capitalization. PSE&G was also approved to implement new pension and storm deferral mechanisms going forward. This directly addresses one of our key objectives, which has been to increase the predictability of our financial results by reducing variability, benefiting both the customer and our shareholders. You will recall back in 2022, we identified three paths to address the accounting impacts of pension costs. Combined with a regulatory accounting order we obtained in 2023, along with a list out of a portion of the non-regulated pension obligations, this new deferral mechanism will provide for the recovery of annual pension and OPEB expenses and should help to mitigate most of the remaining pension variability going forward. The BPU also approved the settlement of PSE&G's energy efficiency filing that covers a commitment period from January of 2025 to June of 2027. The approval authorizes an investment program of $1.9 billion net of administrative expenses and an additional $1 billion program for customer on-bill repayment for purchases of EE equipment. Both programs will be treated as rate-based and will be completed through 10 energy efficiency programs over approximately six years. The second phase of energy efficiency programs will continue New Jersey's efforts to help all customers save energy, reduce utility bills, lower carbon emissions, and continue our EE-related job training, the focus on lower and middle income communities. Customer bill affordability remains a key focus alongside our energy efficiency and cost containment efforts. Following this past distribution-based rate increase, PSE&G retained its favorable bill comparison position versus regional peers on an electric and gas customer bills. A typical PSE&G residential customer will pay an electric bill consistent with the regional average and continue to have the lowest gas bill in the region. In addition, the BPU authorized on October 1st PSE&G's gas supply cost reduction. lowering the BGSS rate from $0.40 per therm to $0.33 per therm in time to help customers during the upcoming winter heating season. The BGSS gas cost reduction, when combined with the base rate changes that occurred in October, lowered the bill impact of the base rate increase for a typical combined electric and gas customer from 7% to an increase of about 5%. On the capital investment side, PSE&G invested approximately $1 billion during the third quarter and is projected to complete 2024 with capital spending at $3.5 billion, slightly higher than planned by about $100 million. This is driven by higher new business requests and EEE spend. Notably, within this year's capital expenditures, we are also on budget and on schedule to complete almost all of our AMI installations by year end. We continue to forecast PSCG's five-year $19 to $22.5 billion capital plan through 2028, with the regulated portion representing $18 to $21 billion of the total. With the energy efficiency settlement approved, we will begin commitments under this new program this coming January. These energy efficiency investments are already captured in our projections that produce the compound annual growth rate in rate base of to 7.5% over the 2024 through 2028 periods. Switching to regulated competitive transmission solicitations, the BPU's selection of the winner or winners of the pre-built offshore wind infrastructure is expected by year end. We also submitted bids into CGM's 2024 Regional Transmission Expansion Plan window number one. The solicitation took place in September. PJM is expected to recommend their preferred solutions in the next few months and then approve the selected projects in February of 2025. And as a reminder, none of these potential projects are included in our current capital investment forecast. PSE&G recently updated its load study as a part of an annual submission to PJM for use in its load forecast updates. Our existing data center peak load currently stands at approximately 350 megawatts and these sites are expected to expand by about 170 megawatts over the next 10 years. We have also received formal applications to initiate nearly 400 megawatts of new data center load and inquiries over 1,200 megawatts of data center feasibility studies in new business. These amounts do not represent firm commitments. but they provide an indication of the increase in interest. Last week, CoreWeave, a data center developer, announced plans to invest $1.2 billion to convert a 280,000 square foot facility to build its first data center in New Jersey. New Jersey has numerous locations that can be reutilized in a similar fashion, and the state's economic development efforts are focused on replicating this activity throughout the state. We are aware of the FERC technical conference and decision on Friday. We will continue to look for clarity on this issue going forward. That said, we believe that data-centered demand will continue to grow, and we anticipate the continued desire for carbon-free dispatchable power. As such, at PSEG Power, we continue to pursue contracting of our nuclear output at long-term attractive pricing with low execution risk that can also help attract new technology-based businesses consistent with state policy. In addition, we are pursuing thermal and efficiency upgrades in our co-owned Salem units that could potentially increase their combined output by approximately 200 megawatts, and we believe would qualify for the technology neutral tax credits for new carbon-free generation. Switching to the Long Island contract, as you know, our existing operating service agreement and power supply contract with LIFA runs through the end of 2025. LIPA began a process on the renewal and extension of both the OSA and fuel management contracts. We have submitted our proposals into LIPA's RFP process and anticipate an update on the status of both proposals during the first quarter of 2025. So wrapping things up on the quarter, today we are reaffirming our guidance for long-term non-GAAP operating earnings growth of 5% to 7% through 2028. which had incorporated an expected balance rate case outcome consistent with the approved settlement recently implemented. They approved the E program and uses the threshold price of the nuclear production tax credit to price the output of our nuclear units. In closing, through the first nine months of the year, solid execution is driving our expected results. We have settled four regulatory proceedings in the past six months. and we are also advancing our five-year capital investment plan focused on infrastructure modernization and energy efficiency initiatives. CSEG has continued to focus on increasing the predictability of our financial results as we prioritize a solid balance sheet. This has enabled us to fund our five-year capital investment plan totaling $19 to $22.5 billion without the need to issue new equity or sell assets and provides the opportunity for consistent and sustainable dividend growth. I'd like to close with a thank you to all our employees for all they do. With a special shout out to the PSE&G crews who went to Florida and Georgia on mutual aid to assist with service restoration after Hurricanes Milton and Helene. The mutual aid network is rather unique in our industry, and we are very pleased to reciprocate the help we received from mutual aid crews after Superstorm Sandy. I will now turn the call over to Dan to discuss our financial results and outlook in greater detail. And we'll be available for your questions after his remarks.

Thank you, Ralph. Good morning, everybody. As Ralph mentioned earlier, PCG reported net income of $1.04 per share for the third quarter of 2024 compared to $0.27 per share in 2023. Non-GAAP operating earnings were $0.90 per share in the third quarter of 2024 compared to $0.85 per share in 2023. Slide 7 and 9 detail the contribution to non-GAAP operating earnings per share by business segment for the third quarter and first nine months of 2024. Slides 8 and 10 contain waterfall charts that take you through the net changes for the quarter-over-quarter and nine-month periods in non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported third quarter net income and non-GAAP operating earnings of 76 cents per share for 2024 compared to 80 cents per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth and rate base from higher regulated investments that was more than offset by higher investment related depreciation and interest expense in advance of the October rate effective date of our distribution rate case approval. Compared to the third quarter of 2023, transmission margin was flat due to higher recovery of investment offset by the timing of a formula rate true-up. Energy efficiency margin was a penny per share favorable on higher investment, and distribution margin increased by six cents per share. Split between Energy Strong II and the Infrastructure Advancement Program, or IAP, recoveries, and the absence of storm cost amortization from a year ago. Distribution O&M expense was $0.04 per share unfavorable compared to the third quarter of 2023, primarily due to the timing of spending and higher Cyber and IT spend. Appreciation and interest expense rose by a penny per share and $0.03 per share, respectively, compared to the third 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 penny per share unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to zero over a full year, and other taxes had a net unfavorable impact of two cents per share in the quarter compared to 2023. Weather during the third quarter, as measured by the Temperature Humidity Index, was 5% warmer than normal, but 5% cooler than the third quarter of 2023. And just as a reminder, weather variations have minimal impact on our utility margin because of the Conservation Incentive Program, or SIP, mechanism, which limits the impact of weather and other sales variances, positive or negative, on electric and gas margins. while helping PSE&G promote the adoption of its energy efficiency programs. The number of electric and gas customers, which is the driver of margin under the SIPP mechanism, continued to grow by approximately 1% each over the past year. On capital spending, PSE&G invested approximately $1 billion during the third quarter, bringing year-to-date spend to $2.7 billion. For the full year 2024, our capital spend is expected to total $3.5 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 programs. We are reaffirming our 2024 to 2028 regulated capital investment plan of $18 to $21 billion, as well as our rate-based CAGR over the same period of 6% to 7.5%. Moving to PCG Power and Other. For the third quarter of 2024, PCG Power and Other reported net income of $0.28 per share compared to a net loss of $0.53 per share for the third quarter of 2023. The non-GAAP operating earnings were 14 cents per share for the third quarter of 2024, compared to non-GAAP operating earnings of 5 cents per share for the third quarter of 2023. For the third quarter of 2024, net energy margin rose by 16 cents per share, driven by higher recontracting prices at nuclear, which includes the net impact of the nuclear PTC that took effect January 1st of 2024. As a reminder for 2024, we mentioned that we anticipated realizing 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. This differs from last year when PSEG Power realized most of the step up in the annual hedge price in the first quarter of 2023. O&M was $0.03 per share unfavorable mostly driven by higher costs from the peach bottom units and the absence of a one-time benefit last year. Interest expense was $0.04 per share higher, reflecting incremental debt at higher interest rates, and taxes and other were a penny per share favorable compared to the third quarter of 2023. On the operating side, the nuclear fleet produced approximately 8.1 terawatt hours during the third quarter of 2024, in line with the year earlier period and ran at a capacity factor of 94.5%. Touching on some recent financing activity, as of the end of September, PCG had total available liquidity of $3.4 billion, including $200 million of cash on hand. Through September 30th of 2024, cash from operations was strong, and our cash collateral balance was below $200 million, supporting our strong liquidity position. CCG's variable rate debt at the end of September consisted of a $1.25 billion term loan maturing March of 2025, the entirety of which has been swapped to a fixed rate, which mitigates fluctuations in interest rates. As of the end of September, given our swaps, we had minimal variable rate debt. In August, PSE&G issued $1.1 billion of secured medium-term notes, or MTNs, comprised of $600 million of 4.85% MTNs due August 2034 and $500 million of 5.3% MTNs due August of 2054. A portion of the proceeds were used to repay the $250 million August 15th maturity of 3.15% MTNs. Looking ahead, our solid balance sheet supports the execution of PSCG's five-year capital spending program, dominated by regulated capex, without the need to sell new equity or assets, and provides the opportunity for consistent and sustainable dividend growth. In closing, we are narrowing PSCG's full-year 2024 non-GAAP operating earnings guidance to $3.64 to $3.68 per share from $3.60 to $3.70 per share prior. This update reflects PSEG's solid results through the first three quarters of 2024 and PSENG's new distribution base rates, which took effect October 15th. We are also reaffirming our long-term 5% to 7% compound annual growth in non-GAAP operating earnings through 2028, supported by our capital investment programs and the Nuclear PTC. With the rate case and energy efficiency filings now approved, we will look to finalize our annual business planning process, which will position us to update our financial guidance disclosures with our fourth quarter and full year 2024 earnings release. We will introduce PSEG's non-GAAP operating earnings guidance for 2025, We will refresh and roll forward our capital investment plans. We will update our rate base and long-term earnings CAGRs and discuss the details during our year-end call in February of 2025. That concludes our formal remarks and we are ready to begin the question and answer session.

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're on a speakerphone, please pick up your handset before entering your request. One moment, please, for the first question. The first question is from Char Perroza with Guggenheim Partners. Please proceed with your question.

Hey, good morning, guys. Good morning, Ralph. Good morning, Dan.

Good morning, Char.

Good morning. So just about starting off on the ISA issues at FERC and sort of the risks of behind the meter nuclear deals. Does this kind of change the calculus on your commercial discussions with artificial island? Does this push the conversations to more conventional deal with transmission interconnections? So any changes with your discussions there? And do you have the interconnection capacity to present a in front of the meter option to a potential counterparty? Thanks.

Hey, Char. Thanks. Yeah, so look, I'll try to hit on that whole interconnection agreement issue up front here a little bit. First of all, we think that was a very narrow decision that was made by FERC, so very specific to what was submitted by the parties there. We're not part of that. We were not party to that agreement, so I don't want to talk in a lot of details about it. But it has not slowed us down and will not slow us down from trying to help the state of New Jersey meet their economic development goals. There's a lot of different ways to come to a solution. I think Talon had one solution. We've seen Constellation with another solution. I think each individual customer and each individual site will bring a different solution to the table. We still think we're very uniquely positioned because of our three-unit site. and the redundancy that exists there. We like the additionality that our early site permit could provide to somebody else. We like the additionality that our upgrades are gonna provide. And we like the additional megawatt hours that we're gonna get from our Hope Creek facility when we change the fuel cycle. So there's a lot of things that are a little bit different about our site than others. And I think when we continue to have our conversations, all of those things will come to light and play itself out.

So, Ralph, it sounds like despite the FERC rejection, it doesn't sound like the messaging, the conversations, anything has changed from before the event happened.

Yeah, sure. Again, it's been 72 hours or so since that all came out. Look, I think... I think there's a number of different paths where we can see an ultimate solution come out. But for our specific scenario, I stick to what I said a couple minutes ago. Look, you could see somebody in that proceeding asking for a rehearing and trying to get a different solution there. You could see something coming out of the technical conference and what they have going on. You could see something coming out of the 205 proceeding. that Exelon has. Or you could see somebody put together an interconnection agreement that is a little different than the one that exists and comes out with a solution that the FERC supports. So any of those scenarios are possible. And I just think we're dead focused on supporting the state of New Jersey's economic development goals.

And just lastly for me, Ralph, I don't want to put you in a corner and just ask about timing, but maybe I'll give it a shot. Do you have any sense on the timeline? I know when we've had conversations in the past, it's been hopefully by this year, by the end of this year, governors, you know, obviously leaving next year, this is an important initiative for him. Can you just maybe give us a sense on timing and where you are with the discussions?

Yeah, sorry if that was misunderstood or I misspoke, but we always have said in our conversations that we, you know, we would like to get this done during this governor's term. He turns out at the end of next year. Obviously, there'll be an election in November and different policies will be discussed, but we've been focused on that timeline since we've started the discussions.

Okay, perfect.

and supporting his initiatives would make a ton of sense for us.

Got it. Looking forward to that. Appreciate it. See you guys in a few days in Florida. Thanks again.

Thanks, Char.

Our next question is from Nicholas Campanella with Barclays. Please proceed with your questions.

Hey, Nick.

Hey, thanks so much, Warren.

I wanted to ask, you know, when you kind of outlined the prior kind of 5% to 7% growth rate, we talked about it not being linear. And, you know, as we're kind of getting to the end of the year here, there's been a lot that's happened, right? Like you have new rates in New Jersey. Presumably you were under-earning your ROE there. We also kind of have this capacity auction print. Can you just kind of talk about how that positioned you within that 5% to 7% and any drivers we should kind of consider as we get to 25%? Thanks. Yeah.

Yeah, sure. I'm going to let Dan give you some details there.

Yeah, Nick, I'm not going to give it 25 or any particular year's guidance as we step forward. I think that range is where we are. I do think, to your point, you're looking at elements that will come into play. We had assumed all along we would see the result of this rate case in the second half of the year, so that kind of the timing is as expected. And one of the key elements that we looked at for that rate case was being able to fully recover the capital. that we had currently deployed during that period, and that was also where the rate case came out. So I think we got a good outcome, and I think it was where we expected it to be. But that's been baked into how we've been thinking about where we're going. To your point, I do think on capacity, it's unfortunate that we do have a delay, but we will continue to step through those auctions as we go through time. There's a little bit of a balancing for those auctions. If you think about the auctions may go up and down, they do split years, right, Nick? So you've got kind of a June to May timeframe. And so to the extent that you see some ups and downs throughout where those auctions may go, you will see a moderating effect on the year-over-year results that we see. So I think if you just think about that range of five to seven that we've given, you'd be in pretty good shape as you step through the timeframe that we talked about.

Okay, great. And then I guess just thinking about, like, if you were to move artificial island front of the meter in any scenario, you know, how impactful is that to the overall economics? Is there any kind of level that you would kind of guide to on what a grid charge actually looks like in that region on a dollar per megawatt basis or otherwise? I appreciate it.

Well, Nick, so a couple things there. Let me go back to the capacity auction for a second. And Dan correctly said we're know we're sorry to see that the auction didn't proceed right but we're also happy that the pgm is going to take a step back and get that right so we filed some comments to that to that effect and it was really just based upon getting the reference unit right and figuring out this rmr piece that i would encourage you all to take a look at the uh some of the filings that were made around that rmr uh five that are more complaint that went in there were some pieces there about Brandon shores that might be might be helpful for people to take a look at and then look from a pricing standpoint you know if you just take a look at the transmission rate that exists within the a service territory it's just under seven bucks a megawatt hour right now and I think if you step back and look at that full rate on a network service basis and net it, it could really put in context the amount of dollars that we're talking about here that is at risk in any way, shape, or form and how, whether it's made up in the pricing deal or tax breaks or something else, the state of New Jersey could still meet its economic goals.

Hey, that's super helpful. Thanks for the call. I'll see you in a few days here. Thank you.

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

Hi. Good morning. Thank you, team.

Hey, Paul.

Hey, Paul. Thanks. If I could follow up on Nick's question, I don't mean to nitpick, but when you were answering, do you expect to be within that 5% to 7% CAGR every year on an annual basis? Because I know we've talked about the production tax credits, a little lumpy, the rate case dynamics. So do you expect to be within that range every year, or is that more like a CAGR we should think of?

I think you ought to be thinking about it as kind of how the business will run on a go forward. Could we be in situations where we could move around within that period? Absolutely, Paul. But I think that's a good way to think about us longer term on a CAGR basis.

Okay. Understood. And then shifting to the transmission side of the house, Could you give a little scope or quantification of some of the PGM RTEP proposals? I saw there was that roughly 400 million greenfield project in PSAG, but just any other perspective or transmission needs would be helpful. Thanks.

Yeah, so I think I'd first start by just, if you go backwards, we were successful in Maryland and have a project that's moving along there. Ralph referenced on the call. In window one, we've got a proposal sitting in front of PJM that's kind of comparably sized, which we'll find out in short order. I think what you're going to continue to see, Paul, given the other topic that's been kicked around and will continue to be on the data centers, more of these opportunities that will come forward. I think we'll analyze them all. We'll try to figure out what makes sense for us to move forward on, but I can tell you that we do move forward with some confidence in our ability to to do the work and to put in competitive bids to continue to move forward. The other thing I would say is just as you take a look at the capital program, incremental competitively bid transmission is not in that program. So we don't need to be able to win some of these competitive programs to be able to hit the capital budget.

Yes, very clear. Thanks a lot. Thanks, Paul.

Our next question is from the line of Jeremy Tonette with JP Morgan. Please proceed with your question.

Hi, good morning. Good morning, Jeremy. Surprisingly, I want to come back to the data center conversation here. And just wanted to start off, I guess, when you look at the power market opportunity set, can you talk more about the potential upside related to thermal operates or other opportunities? I think you had mentioned 200 in the past, but that was predicated on certain pricing outlook, and maybe that's changed. And so just wondering, you know, given everything that we have in front of us now, how you think about that?

Yeah, no, we're still in that 200 range right now. Our teams continue to look at what opportunity sets might be out there and are going to continue to refine it, but we have not moved off that 200 megawatts at this point.

Got it. Understood. And then, you know, just thinking more broadly as well, is time to power something your customers, you know, care about the most, or is it about carbon-free and your objectives being to support the New Jersey State economic development here? And if it is time to power that's most important, does the FERC delay hurt those conversations?

No, Jeremy, I think it's, look, it's all of the above, and it depends upon which customer you're talking to. Some are really focused on additionality. from a clean generation standpoint. Some are focused on, you know, the time, the speed, the market. There's no doubt about that. And then I think you have people that are looking at the reliability of the units and how everyone operates them. So, you know, we believe we're in pretty good shape on all three of those factors, and that's why we haven't indicated at all that we, you know, we're backing down.

Got it. Understood. That's very helpful. Thanks.

The next question is from the line of Durgesh Chopra with Evercore ISI. Let's just hear their questions.

Hey, team, good morning, and thank you for giving me time. Ralph, good morning. Dan, good morning. Hey, just, Ralph, you kind of went through the tariff implications of the first quarter in a lot of detail. Thank you for that. Maybe just address grid reliability. I mean, that was one of the things that was brought up.

um in the order you just mentioned it but just maybe a little bit more color as to how do you overcome that this notion of taking power away from the grid and then giving it to the data center any color you can share that would be helpful thank you yeah so jakesh i don't i don't think we could really state anything there with any any sense of uh certainty right now right you've got so many different things that are going on with the topology and the grid down in that region um you know brandon shores As an example, it's a large unit. That unit stays on. It'll have one impact on the region. If it comes off, it'll have another. Where TMI ultimately connects into the grid in that region is going to have another impact on it. So I'd be getting way ahead of our skis if I was to tell you exactly what the grid reliability issues are. I can tell you this, from a stability standpoint on our system overall, we have extra capacity here in New Jersey. because of the work that we did after the blackout in 2003 and after Superstorm Sandy. But I don't want to tell you for sure that there won't be any upgrades that will be needed until I know how a lot of the other generators are going to play out in that part of PJM.

I mean, I guess that just is, I think, important to keep sight of, and it came out of some of Friday's discussions. You know, the data center stuff in the aggregate is a pretty important element for a whole host of reasons, and I know national security was referenced, and it's going to come. And a lot of the discussions related to whether it's behind the meter or in front of the meter doesn't ultimately change the supply-demand needs, right? I mean, that's been stated numerous times, but I think people can lose sight of that as you're looking at some of the details as to how some of this thing may come to pass. at the end of the day, you're going to have incremental demand and supply is going to be needed to meet it. And that's, I think, where Ralph was taking off from.

Yeah, no, I certainly appreciate that discussion, whether it's front or behind. I mean, the supply-demand challenges are the supply-demand challenges. So thank you for that. Just maybe can I quickly follow up, Ralph? I mean, clearly Constellation on their earnings call just before you had a preference for kind of advocating for these co-location deals? What's your stance on that? Would you rather preserve the option of having co-location next to your nuclear plants? I'm just trying to figure out if there's a fork process, would you be supportive of co-location going forward or how do you think about that?

Yeah, so, Dagesh, I tried to probably make this too simple for folks as we talk about it, but I'm sticking to it. I think it's a combination of, you know, what are you going to charge someone for energy? What are you going to charge somebody for transmission? And what are you going to charge someone in the way of taxes? And the combination of all of the above is the package that any state needs to bring to bear to attract that hyperscaler to the area. You know, we have a very healthy tax refund plan in place. Right now there's tax incentives that I think are in this $700 million range, maybe $500 million range in the state of New Jersey. So that's great and would be very, very helpful in attracting someone. Does it need a little bit of an additional kick on the transmission services? Maybe. Again, it depends upon whether that Data Center is going to be someone who's going to be on 24-7. Are they going to be able to respond to demand response and get another revenue stream from that solution? So there's multiple, multiple ways you can take a look at this. And so I don't want to lock into, hey, we really want co-located over in front of the meter, but I don't want to lock into in front of the meter over co-located either. It's really what's going to bring to bear the solution that's going to bring those entities to the state of New Jersey.

Thank you, Ralph. I appreciate the discussion. Thanks again.

Thanks, Rakesh.

The next question is from the line of Michael Sullivan with Wolf Research. Please proceed with your question.

Hey, good afternoon.

Hi, Michael.

Hey, Ralph. Appreciate the discussion, some of the numbers you put out there. You all just refreshed your PJM large load forecast. How do we think about what Exelon has out there for ACE and how that may pertain to anything you're pursuing at Artificial Island? Would the load you're trying to work with there be showing up in some of their numbers yet or no?

No, I don't want to comment on what they submitted. I don't really have any insight into how they made their calculations. So it kind of be, I'd be firm on that. I will say in general on the PJM footprint, there's quite a bit of load coming in and it's something that we've been talking about for quite some time. I think our numbers this year were more in line with what folks might have expected, but that was because we've been yelling for a few years in advance and so i see a couple of the other utilities especially to our west kind of catching up on that front and i i could say from a overall footprint standpoint i was very happy to see the realistic load forecast that came in but specific to ace i wouldn't want to comment on okay sure no uh no worries there um and then maybe separately just how we think about um

LIPA and the opportunity and, I guess, risk there, will you know enough by your year-end call to decide whether or not you include that in there? What's just the range of outcomes they're looking at, whether it be publicly owned or other?

Yeah, I don't think they're going with a publicly owned solution. What we continue to hear is that they're going to stick with the service provider model. What we have at risk there is $0.07 to $0.08. We've been pretty clear about that over the last six months or so, and we should know by the end of the first quarter of next year. I would expect sometime in the beginning of the year because that transition needs to take place by the end of 2025. So maybe we can find out something sooner, but my expectation is by the end of the first quarter, we would have a pretty good sense of where we stand with that. A lot of it depends upon how that contract's written and how aligned it is with some of the LIPA Reform Act goals that were put in place 10, 12 years ago now.

Okay, great. Thanks so much. Our next question is from the line of David Arcaro with Morgan Stanley. Please proceed with your question.

Hey, good morning. Thanks so much. Hey, David. Hey, David. Um, thanks for that data on, um, or that update on the new data center demand and just what you're seeing with inquiries and feasibility studies. I was wondering, um, would, would there be any utility investment opportunities, you know, potential higher CapEx, uh, given that incremental load that you're seeing?

Yeah. So it's, it's not driving us to a different solution, but as, as Dan said in his prepared remarks, we're going to roll that forward, uh, in our fourth quarter call. I haven't seen anything that would require us to build a new transmission line, that's for sure, based upon what exists. One of the largest data center developers, the CoreWeave that we mentioned earlier, is going on the site of a former pharmaceutical headquarters, so there's some decent facilities there, but there'll need to be some upgrades done, and how those upgrades are done is yet to be determined, whether it'll be customer-based or utility-based. But nothing that I would say is driving an astronomical change in our capital programs.

And the upshot of that is it's a reference to the system and the state that it's in and its ability to take on some incremental data centers. So that's a net positive.

Yeah, absolutely. Oh, got it. Thanks. And, yeah, I didn't really maybe appreciate the excess transmission capacity you might have in the state. Is there any way you might be able to quantify that? As you think about, I don't know if it's number of megawatts that you could, you know, handle without major upgrades. Or, yeah, some of your peers have talked about that transmission capacity. So just wondering if you have any way to frame that.

Yeah, David, I would encourage you to take a look at the CTO-CTAL analysis that's put out by PJM and how that all translates. Again, that changes based upon, you know, every year when PJM runs the process from a generator. and load standpoint. So, that'll be a pretty good indication when that analysis is completed as to, you know, where the excess capacity exists.

Okay. That works. Thanks so much. Thanks, David.

Our next question is from the line of Anthony Crowdell with Mizuho Securities. Let's just hear with your questions.

Hey, good morning, Ralph. Good morning, Dan.

Hey, Anthony. Good morning, Anthony. Welcome to hockey season.

Welcome to hockey season. The weather's right, and my voice is a little hoarse. I have a kid on my UA team, Ralph, who's also named Ralph, and he's a little extra attention. I don't know if it's the name. But just quickly, off of Mike Sullivan's question, I mean, the LIPA contract, again, seven to eight cents, it's not –

incremental or instrumental to pegs earnings but do you think that's going to be more competitive this go around given how successful it's worked for you for the last whatever 10 years yeah i don't want to i don't want to uh any any reaction to that could be read as being a little bit too uh arrogant on the issue i think we've done a great job uh we're very proud of the work that we've done there from a safety standpoint from a reliability standpoint and from a customer satisfaction standpoint so Um, we've done all of that. We've met our, all of our commitments and, and prices have remained, uh, you know, from an affordability standpoint, what, where the expectations were. So I think we have a very good story to tell. Um, I just want to make sure that our story meets the needs of, uh, of LIPA as they, as they look forward.

Great. And apologies if you've answered this already, just on the potential uprated Salem. Have you guys quantified the cost of that and how many megawatts you think you'll get out of it?

We were talking about 200 megawatts, but I don't know if we've given the latest numbers out. We'll follow up with you, Anthony, on that, and we'll definitely have it in the deck that comes out for EEI.

Great. That's all I had. Thanks for taking my questions.

Thanks.

The next questions are from the line of Paul Fremont with Ladenburg-Fallon. Please proceed with your questions.

Hey, good morning. Congratulations. I just wanted to maybe get a little bit more detail on the Corweave lease. Has there been any determination in terms of who's going to power that facility and how many megawatts are going to be needed to power the facility?

Yeah, I think the press release, if my memory serves me correct, was about 125 megawatts initially, and it's going up to over 300 eventually when it's all completed. From who they're going to buy their power, I wouldn't comment on that. Just from a utility standpoint, if they're with a third-party supplier, so be it. If not, we'll be prepared to handle it through the BGS process. I have not read anything about who they've contracted with.

I mean, could you be potentially involved in powering the contract with the merchant nuclear?

Well, we always could be involved, Paul. We have a retail license, and we could be involved in that stuff. But they have not announced anything, and I would not want to estimate or guess on what they might be doing.

And then I guess when you work in terms of with the governor's office trying to bring in additional data center developers into the state, are you also working with Constellation sort of in partnership since you're in partnership with them in various nuclear plants?

No. Paul, most of my involvement is at a personal level. I give my own time to Choose New Jersey, which is one of the governor's economic development arms. And so I work closely with them on their projects and what they may have. And a lot of the data center conversations take place between Choose New Jersey and the New Jersey Economic Development Authority. From a PSE&G standpoint, our James Meeker & customer operations team works directly when leads come in, and when we get requests and then on the power side. James Meeker & Dan and his team are looking at it from a commercial operations standpoint so but that's that's where our interactions take place and not necessarily from an enterprise level with the governor's office.

Got it. And then, lastly, in terms of the. In terms of the PTCs, is there a final interpretation out by the DOE in terms of how they're going to account for the PTCs and market prices?

I will give that one to Dan.

Yeah, we're still waiting on regs from Treasury, the exact definition of gross receipts, Paul. So the answer is no.

So for accounting purposes, how are you handling it?

Yeah, so we are taking our best internal estimate as to where things will land and moving accordingly. We have heard references that it's their intent to move forward on this by the time this administration is out. I don't know whether the election would have anything to do with it. I guess we'll have one day to wait to find out that and maybe a little bit longer to find out a result. But the sense we get is that it's near term, but we don't have it right now.

Great. Thank you very much.

The next questions come from the line of Carly Davenport with Goldman Sachs. Please receive your questions.

Hey, team. Good morning. Thanks for taking the questions. Hey, Carly. Maybe just wanted to start on the nuclear fuel side. I think you've updated the commentary that you're now essentially covered through 2027. Just as we think about some of the capacity addition announcements that we're starting to see in, call it, 2028 plus, is this timeframe of sort of contracting out two to three years the way that you plan to manage your fuel purchases going forward? Or just any thoughts on how you're thinking about that would be helpful.

Yeah, Carly, this is Dan. I think the way to think about it is in light of exactly what you are talking about, right? The market dynamics. have become a little bit more volatile, and we do continue to look out over time. So there could be some lengthening of the overall timeframes. It would depend upon striking the right commercial deal as well, right? So we're not going to go out in time just to go out in time if at the end of the day the commercial aspects of that deal don't make sense. But I think what you are referencing is the volatility that we are seeing in the market in a sensible approach is to look out a little bit further and see what can be done there. updates to follow as those deals come to closure.

Got it. Okay, that's helpful. Thanks for that. And then just a quick follow-up, I think maybe to Paul's question from earlier on the upgrades. When you're having conversations with potential data center customers, are those upgrade volumes a part of those conversations or is that something that would be kind of incremental?

Yeah, they are part of it. I mean, obviously the aggregate output of the facilities is of interest, number one, and additionality is of interest as well. And so there's definitely interest in understanding what the overall facility would look like. But I think as you saw from the Microsoft deal, additionality is also in folks' mind. And so that's definitely a part of the discussion.

Got it. Great. Thanks so much for the color. Yep.

Thanks, Carly.

Thank you. Our final question is from the line of Paul Patterson with Glen Rock Associates. Please proceed with your questions.

Hey, good morning. Hey, Paul. Just sort of to follow up on the co-location issue, if I was to understand the commentary and everything, it sounds like the tax issue is pretty much resolved by the state of New Jersey offering tax breaks, et cetera, and that's just the $7 of transmission cost that in theory would be in play or a portion of that associated with, with locating, with being behind the meter in New Jersey. Is that the way to think about it? That is the way to think about it. Okay. And then do you have any, do you know why the two commissioners declined to participate in the order?

Yeah, I know. We just noted they recused themselves. So I'd have to refer you back to FERC on that one.

Okay. And then finally, as I'm sure you're aware, that the, you know, OPSI, which NJBPU is part of, has been making letters back and forth with PJM correspondents and P3 has been responding and what have you about their concerns about the capacity market and the prices. I know you guys are very focused on affordability, as you guys outlined today as well. Just how do you think, I mean, you know, with the history of LCAP and everything else and, you know, it seems like we're maybe – you know, getting to a market situation in which we don't see a lot of new generation showing up, at least by kind of generation, and these high prices, how should we think about, you know, this apprehension that's being voiced by state regulators and by consumers and what have you? When you see that, what kind of thoughts go through your mind, I guess, if you follow what I'm saying?

Yeah, no, I do, Paul. Look, I think state regulators are doing exactly what state regulators should do, and that's looking out for the best things they can from a customer standpoint. I think they're also trying to balance a reliability issue, and I will tend to line on both of those issues. I will tell you what I worry about is 10 years from now. And as this continues to, you know, this industry continues to morph, I want to make sure that there's enough generation. And I worry that without having a good price signal, that's a long-term price signal, that might not take place. So I was, you know, we've mentioned earlier in a call, and I'll just reinforce here that, you know, we thought it was the right thing to do the pause. We want to get the reference unit right. We want to get the RMR contracts treated the right way. But there's a lot of detail behind both of those comments that I just made and making sure that that's done correctly and then done over a longer period of time than one-year price signals I think is where you're going to find the right solution. So from an OPSI standpoint, I think they're weighing in just when they should, and I think that's pretty well aligned with the same thoughts that we have from a reliability and affordability standpoint. Okay.

Thanks a lot. Much appreciated.

Thank you. There are no further questions at this time. And I'd like to turn the floor back over to Matthew for closing remarks.

Great. Yeah. So let me just take a couple seconds here. And I certainly understand and respect all the questions that we got on co-location today and specifically in light of the decision that was handed down from FERC on Friday. But I want to just take a second to focus on the outstanding results that the team put out last quarter. not only from a financial standpoint from an operating standpoint and the reliability that the utility delivered the reliability that the nuclear units delivered and i think the not to lose sight of the fact the mutual aid that we were able to support in the southern part of the state combine that with the outstanding results that were achieved with our regulators to find a solution that was both affordable and provided long-term reliability for our customers in our base rate case and helped customers achieve savings in our energy efficiency filing really sets us up for the long term in a very, very positive way. I understand of the long-term solutions for the data center and specifically the output of our nuclear plants is of concern, but again, I would put that in the context that we laid out here today in $7 a megawatt hour for transmission rates down in the artificial island area. So we continue to be very positive. Looking forward to speaking to everybody at EEI, in which time we'll give you even some more details on all those things we spoke about. So thanks for calling in and look forward to seeing you in Florida.

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