Ladies and gentlemen, thank you for standing by. My name is Rob, and I’m your event operator today. I’d like to welcome everyone to today’s conference, Public Service Enterprise Group’s Third Quarter 2024 Earnings Conference Call and Webcast. At this time, all participants are in listen-only mode. Later, we’ll conduct a question-and-answer session for members of the financial community. As a reminder, this conference is being recorded today, November 4, 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 LaRossa, Chair, President and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today’s discussion are posted on our IR website at investor.pseg.com and our 10-Q will be filed later today. PSEG’s earnings release and other matters discussed during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income as reported in accordance with Generally Accepted Accounting Principles or GAAP, in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today’s material. Following the prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Thank you, Carlotta. 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 the 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. PSEG’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 the 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 $3.60 per share to $3.70 per share to a range of $3.64 per share to $3.68 per share. This updated and narrow range reflects the implementation of PSEG’s new base distribution rates that went into effect on October 15th 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. PSEG met its 2024 summer peak load of 10,152 megawatts on July 16th with temperatures of 98 degrees Fahrenheit, and 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 24/7 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 are 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% to 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 multiparty 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 fallback 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’ll 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 lift 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, focused 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 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 EE 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 PSE&G’s five-year $19 billion to $22.5 billion capital plan through 2028, with the regulated portion representing $18 billion 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 6% to 7.5% over the 2024 through 2028 periods. Switching to regulated competitive transmission solicitations, the BPU selection of the winner or winners of the pre-billed offshore wind infrastructure is expected by year-end. We also submitted bids into PGM’s 2024 Regional Transmission Expansion Plan Window 1. The solicitation took place in September. PGM 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 part of an annual submission to PGM 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 could 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 center 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 to New Jersey, consistent with state policy. In addition, we are pursuing thermal inefficiency upgrades at 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 LIPA 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 balanced rate case outcome consistent with the approved settlement recently implemented. We approved EE program and used 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. PSEG 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 billion 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. We’re a special shout-out to the PSEG 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, PSEG 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. Slides 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 PSEG, which reported third quarter net income and non-GAAP operating earnings of $0.76 per share for 2024, compared to $0.80 per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth in 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 $0.01 per share favorable on higher investment, and distribution margin increased by $0.06 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. Depreciation and interest expense rose by $0.01 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 $0.02 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 a utility margin because of the Conservation Incentive Program or CIP 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 CIP 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 billion to $21 billion, as well as our rate-based CAGR over the same period of 6% to 7.5%. Moving to PSEG Power and Other. For the third quarter of 2024, PSEG 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 $0.14 per share for the third quarter of 2024, compared to non-GAAP operating earnings of $0.05 per share for the third quarter of 2023. For the third quarter of 2024, net energy margin rose by $0.16 per share, driven by higher re-contracting prices at nuclear, which includes the net impact of the nuclear PTC that took effect January 1, 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 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 $0.01 per share favorable compared to the third quarter 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, PSEG had total available liquidity of $3.4 billion, including $200 million of cash on hand. Through September 30, 2024, cash from operations was strong and our cash collateral balance was below $200 million, supporting our strong liquidity position. PSEG’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 PSEG’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 PSEG’s full year 2024 non-GAAP operating earnings guidance to $3.64 per share to $3.68 per share from $3.60 per share to $3.70 per share prior. This update reflects PSEG’s solid results through the first three quarters of 2024 and PSE&G’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 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 figures 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.

The first question is from Shar Pourreza with Guggenheim Partners. Please proceed with your questions.

Good morning, guys. Good morning, Ralph. Good morning, Dan.

Good morning, Shar.

Hi, Shar.

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

Hey, Shar. 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 3-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 going to provide and we like the additional megawatt hours that we’re going to 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?

It's been about 72 hours since the news broke. I believe there are several potential paths towards a resolution. In our case, as I mentioned earlier, there could be a request for a rehearing to seek a different outcome. We might also see developments from the technical conference or the 205 proceeding that Exelon is involved in. Additionally, someone could create a new interconnection agreement that differs from the existing one, leading to a solution that receives support from the FERC. All of these possibilities are on the table, and our main focus remains on aiding New Jersey's economic development objectives.

And lastly, Ralph, I don’t want to pressure you, but could you share any insights on the timeline? In our previous discussions, we mentioned hopefully having something by the end of this year, especially with the governor leaving next year and this being a significant initiative for him. Can you provide an update on the timing and the status of the discussions? Thank you.

Yeah. Sorry if that was misunderstood or I misspoke, but we always have said in our conversations that we would like to get this done during this governor’s term. He turns out at the end of the 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. Thanks for that.

Thanks, Shar.

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

Hey. Thanks so much both. So I wanted to ask, when you kind of outlined the prior kind of 5% to 7% growth rate, we talked about it not being linear and 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 positions you within that 5% to 7% and any drivers we should kind of consider as we get to 2025? Thanks.

Yeah. Sure. I’m going to let Dan give you some details there.

Yeah. Nick, and I’m not going to give it 2025 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 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 prudently 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 5% to 7% 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, 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 $1 per megawatt basis or otherwise? I appreciate it.

Well, Nick, so a couple of things there. Let me go back to the capacity auction for a second. And Dan correctly said we’re sorry to see that the auction didn’t proceed, right? But we’re also happy that the PJM is going to take a step back and get that right. So we filed some comments 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 some of the filings that were made around that RMR complaint that went in. There were some pieces there about Brandon Shores that might be helpful for people to take a look at. And then, look, from a pricing standpoint, if you just take a look at the transmission rate that exists within the ACE service territory. It’s just under $7 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 caller. I’ll see you in a few days here. Thank you.

The next question is from the line of Paul Zimbardo with Jefferies. Pleased to see you with your questions.

Hi. Good morning. Thank you, team. If I could…

Hey, Paul.

Hi, Paul.

Hi. Thanks. If I could follow up on Nick’s question, I don’t mean to nitpick, but when you answered, 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 being a little lumpy, the rate case dynamics. So do you expect to be within that range every year? 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 it as 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 PSEG, but just any other perspective or transmission needs would be helpful? Thanks.

Yeah. I mean, 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 1, 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 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 Tonet 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 megawatts in the past, but that was predicated on a certain pricing outlook and maybe that’s changed. So just wondering, given everything that we have in front of us now, how you think about that?

Yeah. No. We’re still in that 200 megawatts 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 just thinking more broadly as well, is time to power something your customers 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 believe it's a combination of factors that varies by customer. Some are primarily focused on clean generation, while others prioritize timing, speed, and market conditions. There are also customers concerned about the reliability of the units and their operation. Overall, we feel confident about our position regarding these aspects, which is why we have not signaled any intention to reduce our commitment.

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

The next question is from the line of Durgesh Chopra with Evercore ISI. Please proceed with your questions.

Hey, team. Good morning and thank you for your time.

Hey, Durgesh.

Ralph, good morning, and good morning. Hey. Just, Ralph, you kind of went through the tariff implications of the FERC order 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 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, Durgesh, I don’t think we could really state anything there with any sense of 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. 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 of 2003 and after Superstorm Sandy. But I don’t want to tell you for sure that there won’t be any upgrades. It’ll be needed until I know how a lot of the other generators are going to play out in that part of PJM.

I mean, it’s a guess that just is, I think, important to keep sight of and it came out of some of Friday’s discussions. The data center stuff in the aggregate is a pretty important element for a whole host of reasons and I know national security is 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.

I appreciate the discussion, whether it's in front of or behind the meter. The supply-demand challenges remain the same. Can I follow up with you, Ralph? Constellation mentioned advocating for co-location deals in their earnings call. What is your stance on that? Would you prefer to maintain the option of co-location next to your nuclear plants? I'm trying to understand your thought process. Would you be supportive of co-location moving forward?

Yeah. So, Durgesh, 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 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. So, we have a very healthy tax refund plan in place right now. There are 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 or over co-located either. It’s really what’s going to bring to bear the solution that’s going to bring that, those entities to the State of New Jersey.

But thank you, Ralph. I appreciate the discussion. Thanks again.

Thanks, Durgesh.

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

Hey. Good afternoon.

Hi, Michael.

Hey, Ralph. I appreciate the discussion and some of the numbers you shared. You all just updated your PJM large load forecast. How should we interpret Exelon's figures for ACE and their relevance to what you're doing at Artificial Island? Will the load you're working with there be reflected in any of their data yet?

No. I don’t want to comment on what ACE 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 could say from an overall footprint standpoint, I was very happy to see the realistic load forecasts that came in, but specific to ACE, I wouldn’t want to comment on.

Okay. Sure. No worries there. And then maybe simply just how we think about 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?

I don’t believe they will choose a publicly owned solution. Instead, we continue to hear that they plan to maintain the service provider model. We have identified a potential risk there of $0.07 to $0.08, which we have been clear about over the past six months. We should have more clarity by the end of the first quarter of next year. I anticipate that we will find out early in the year since the transition needs to be completed by the end of 2025. While it’s possible that we might get more information sooner, my expectation is that by the end of the first quarter, we will have a better understanding of where we stand. A lot of this will depend on how the contract is structured and how it aligns with the goals of the LIPA Reform Act established 10 to 12 years ago.

Okay. Great. Thanks so much.

Our next question is from the line of David Arcaro with Morgan Stanley. Please proceed with your questions.

Hey. Good morning. Thanks so much.

Hey, David.

Hi.

Thanks for that data on or that update on the new data center demand and just what you’re seeing with inquiries and feasibility studies. I was wondering, would there be any utility investment opportunities, potential higher CapEx given that incremental load that you’re seeing?

Yeah. So it’s not driving us to a different solution, but as Dan said in his prepared remarks, we’re going to roll all that forward 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 are some decent facilities there, but there’ll need to be some upgrades done and how those upgrades are done are 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.

Yeah. 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 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 CETO/CETL analysis that’s put out by PJM and how that all translates. Again, that changes based upon 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 where the excess capacity exists.

Our next question is from the line of Anthony Crowdell with Mizuho Securities. Please proceed with your questions.

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

Hey, Anthony.

Good morning, Anthony.

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, $0.07 to $0.08, it’s not incremental or instrumental to PEG’s earnings, but do you think that’s going to be more competitive to just go around given how successful it’s worked for you for the last, whatever, 10 years?

Yeah. I don’t want to, any reaction to that could be read as being a little bit too arrogant on the issue. I think we’ve done a great job. 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 we’ve done all of that. We’ve met all of our commitments and prices have remained from an affordability standpoint, where the expectations were. So I think we have a very good story to tell. I just want to make sure that our story meets the needs of LIPA 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 Anthony on that and we’ll definitely have it in the deck that comes out for EEI.

The next question is from the line of Paul Fremont with Ladenburg Thalmann. Please proceed with your questions.

Hey. Good morning. Congratulations.

Hi, Paul.

I just wanted to maybe get a little bit more detail on the CoreWeave 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, is about 125 megawatts initially and it’s going up to over 300 megawatts eventually when it’s all completed. From who they’re going to buy their power, I wouldn’t comment on that. We’re 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 PSEG process. But 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?

We could potentially be involved, Paul. We have merchandise and a retail license, so we could participate in that area, but they haven't made any announcements yet, and I don't want to speculate on their plans.

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. My involvement is primarily at a personal level. I dedicate my time to Choose New Jersey, which is one of the governor’s economic development initiatives, and I collaborate closely with them on their projects and initiatives. Many of the discussions about data centers occur between Choose New Jersey and the New Jersey Economic Development Authority. From PSEG's perspective, our customer operations team engages directly when leads are received and requests come in, while Dan and his team focus on it from a commercial operations perspective. That's where our interactions occur, rather than at an enterprise level with the Governor’s Office.

Got it. And then lastly, 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 falls. 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 question is come from the line of Carly Davenport with Goldman Sachs. Please proceed with your questions.

Hey, team. Good morning. Thanks for taking the questions.

Hey, Carly.

Hi, 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 years 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 at it a little bit further and see what can be done there. So 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 up rates. When you’re having conversations with potential data center customers, are those up rate volumes a part of those conversations or is that something that would be kind of incremental?

They are included in the discussion. The overall output of the facilities is certainly important, along with the concept of additionality. There is keen interest in understanding what the complete facility would entail. As we saw with the Microsoft deal, additionality is also a key consideration for people, making it an important part of the conversation.

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

Yeah.

Thanks, Carly.

Thank you. Our final question is from the line of Paul Patterson with Glenrock 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, etc. And that’s just the $7 of transmission cost that in theory would be in play or a portion of that associated with being behind-the-meter in New Jersey. Is that the way to think about it?

That is…

Yeah.

Okay. Do you know why the two commissioners chose not to participate in the order?

We just know that they recused themselves, so I would have to refer you back to FERC on that one.

Okay. As you may know, the OPSI, which includes NJBPU, has been exchanging letters with PJM representatives, and P3 has been addressing their concerns about the capacity market and pricing. I understand that you're focused on affordability, as highlighted today. Considering the history of LCAP and the current market situation where new generation isn't appearing—at least not the right kind—and with these high prices, how should we interpret the concerns expressed by state regulators and consumers? What thoughts come to mind regarding this situation?

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, 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, we’ve mentioned earlier in the call, and I’ll just reinforce here, that we thought it was the right thing to do to 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 don’t think they’re weighing in just when they should, and I think that it’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 management for closing remarks.

Great. Yeah. So, let me just take a couple of 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 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, which 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 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. Let me disconnect your lines at this time. Thank you for your participation.