Public Service Enterprise Group Incorporated (NYSE:PEG) Q2 2024 Earnings Call Transcript

Public Service Enterprise Group Incorporated (NYSE:PEG) Q2 2024 Earnings Call Transcript July 30, 2024

Public Service Enterprise Group Incorporated beats earnings expectations. Reported EPS is $0.63, expectations were $0.623.

Operator: 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 Second 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. [Operator Instructions] As a reminder, this conference is being recorded today, July 30th, 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. Carlotta, please go ahead.

Carlotta Chan: Good morning, and welcome to PSEG’s second 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.

Ralph LaRossa: Thank you, Carlotta. Good morning to everyone and thanks for joining us to review PSEG’s second quarter results. PSEG reported net income of $0.87 per share for the second quarter of 2024, bringing results for the first half of 2024 to $1.93 per share. This compares to net income of $1.18 per share and $3.76 per share for the second quarter and first half of 2023, respectively. The 2023 GAAP earnings have reflected higher mark-to-market gains that benefited those earnings. Our results for the quarter and year-to-date periods are summarized on Slides 7 and 9 in the webcast slides. Non-GAAP operating earnings were $0.63 per share for the second quarter of 2024 and $1.94 per share for the first half of the year. This compares a non-GAAP operating earnings of $0.70 per share and $2.09 per share for the second quarter and first half of 2023, respectively.

As a reminder, our non-GAAP results exclude the items shown in attachments eight and nine, which are included with the earnings release. Dan will provide a detailed financial review later in the call, but I want to note that the results for the first six months of 2024 are on track with our full year expectations. These expectations reflect the anticipated resolution of PSE&G’s distribution rate case later this year and the realization of most of the increase in PSEG Power and others 2024 gross margin concentrated in the fourth quarter. Turning to operations for the second quarter. New Jersey has experienced what may turn out to be one of the hottest summers. The early and extended heat wave we experienced last month made June 2024, the second warmest June in our records.

Our electric transmission and distribution system performed exceptionally well, meeting the daily load requirements. In addition, our employees provided outstanding customer care, handling double the call volume compared to the same period in 2023, responding to requests for customer service and air conditioning repairs. PSE&G responded to the elevated coal volume and restored power to the electric customers affected by severe storms and heat related incidents, bringing them back online in under 24 hours, while responding to air conditioning service calls on average in nine hours. Our electric and gas systems also withstood a 4.8 impact earthquake in April, which resulted in required inspections, but resulted in no operational issues. At PSEG Power, we completed the scheduled refueling of our wholly-owned Hope Creek nuclear station on schedule, which lowered the fleet’s capacity factor from over 96% in the first quarter to 82.7% for the second quarter.

As expected, the refueling average also reduced total generation for the second quarter, but for the year-to-date through June, the two Salem units, which share the site with Hope Creek operated at a capacity factor of 99%, keeping us on track with our full year generation forecast of 30 to 32 terawatt hours. Switching to regulatory activity. In May 2024, the New Jersey Board of Public Utilities or the BPU, approved an additional extension of our clean energy future or energy efficiency program of approximately $300 million, covering a six month commitment period from July of 2024 through December of 2024. And in June, the BPU approved the recovery of PSE&G’s previously deferred COVID-19 costs over a five year period starting in June of 2025.

We continue to participate in confidential discussions with various parties to resolve both our distribution, base rate case, as well as the $3.1 billion Energy Efficiency II filing. These discussions are ongoing in parallel and we anticipate that both cases can be resolved later this year. We recently submitted the final update to the base rate case filing, with actual data for the full test year. As a reminder, the combined electric and gas distribution rate case filing is primarily to recover incremental capital spending. We have proposed an overall revenue increase of 9% with a typical combined residential, electric and gas customer seeing a proposed increase of 12%, or less than 2% compounded growth over the six year period. As a single state utility with dual regulatory jurisdictions, this distribution filing covers approximately 57% of our total rate base.

That said, customer affordability continues to be a priority. And we continue to compare favorably with our regional peers. PSE&G customers have a lower than average electric bill and the lowest gas bill in the region. Additionally, PSE&G recently filed with the BPU to implement another gas supply cost reduction this October, a third since January 2023, which will further help customer affordability this coming winter. Moving on to capital investments. We remain on track to execute PSEG’s five year $19 billion to $22.5 billion capital plan through 2028. The regulated portion represents $18 billion to $21 billion of the total, focused on infrastructure replacement and our award-winning energy efficiency programs. PSE&G has placed into service over 2 million of the 2.3 million smart meters planned through our AMI program, still on schedule for completion by the end of this year.

These investments are captured in our projections for a compound annual growth rate and rate base of 6% to 7.5% over the 2024 through 2028 period, starting from a year end 2023 rate base of $29 billion, which was up 10% over the prior year. We also continue to pursue potential incremental investment opportunities for future regulated growth. Along those lines, PSE&G is experienced an increase in new business requests and feasibility studies from potential data center customers across our service area compared with 2023 activity, which combined with increased electric vehicle charging is expected to drive load growth and system investment needs in the future. Switching to regulated transmission solicitations, which are scheduled for this summer, PSE&G expects that the BPU will announce the winner or winners of the pre-built offshore wind infrastructure during the second half of 2024.

Last month, the BPU postponed its second state agreement approach process to procure transmission to support offshore wind generation, while it evaluates the impact of FERC and PGM activity on long-term transmission planning, cost allocation and interconnection queue reform. The BPU may reevaluate this timing and the need for a second SAA solicitation in six months, which would be this coming December. PJM opened the 2024 regional transmission Expansion Plan Window 1 solicitation earlier this month, which reflects their higher load growth forecast on the 2029 to 2032 plan horizon. That has been influenced by increased electrification expectations and data center load growth throughout PJM. We are evaluating the Window 1 solicitation for potential opportunities to bid this September.

Now crossing the Hudson for a moment, and as expected, the Long Island Power Authority opened a request for proposal process to select the manager to operate their electric grid. Our existing operating services agreement and power supply contract with LIPA runs through the end of 2025. We intend to submit proposals into their RFP process and LIPA is expected to make selections early next year. At PSEG Power, we are also continuing to explore opportunities for the potential sale of electricity from our nuclear facilities pursuant to long-term agreements to supply large power energy users such as data centers and hydrogen producers. In addition, we are pursuing multiple growth plans that include thermal and efficiency upgrades at our co-owned Salem units that could potentially increase the combined output by up to 200 megawatts and qualify for tax credits under current rules.

Today, we are reaffirming our guidance for long-term non-GAAP operating earnings growth of 5% to 7% through 2028, which is based on the threshold price of the Nuclear Production Tax Credit, or the PTC that also provides these units with revenue stability through 2032. We continue to deploy the free cash from the nuclear business to help fund utility growth without the need to issue new equity or sell assets and this continues to be a differentiating factor for us. Importantly, our solid balance sheet supports the execution of our capital investment program of $19 billion to $22.5 billion through 2028 and provides the opportunity for consistent and sustainable dividend growth. In summarizing the first six months of the year, solid execution is driving our expected results.

We have settled two regulatory proceedings in the past quarter and we are working to resolve our pending base rate case and the EE II filings later this year. We are also advancing our five year capital investment plan focused on infrastructure modernization and energy efficiency initiatives. These investments will help prepare our system for grid electrification of transportation, homes and workplaces, while also reducing greenhouse gas emissions and helping to lower customer bills. Last but certainly not least, I want to thank our employees for all they do. Their tireless efforts have helped us to maintain best-in-class operating statistics and customer service, especially through the challenging heat wave we have seen this year. I’ll now turn the call over to Dan to discuss our financial results and outlook in greater detail and will be available for your questions after his remarks.

Dan Cregg: Great. Thank you, Ralph. Good morning, everybody. As Ralph mentioned earlier, PSEG reported net income of $0.87 per share for the second quarter of 2024 and that compares to $1.18 per share in 2023. Non-GAAP operating earnings were $0.63 per share in the second quarter of 2024, compared to $0.70 per share in 2023. Slides 7 and 9 detail the contribution to non-GAAP operating earnings per share by business segment for the second quarter and first half of 2024. Slides 8 and 10 contain waterfall charts that will take you through the net changes for the quarter-over-quarter and six month periods in non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported second quarter net income of $0.60 per share for 2024 compared to $0.67 per share in 2023.

PSE&G had non-GAAP operating earnings of $0.60 per share for the second quarter of 2024 compared to $0.68 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, offset by higher investment-related depreciation and interest expense, awaiting rate recovery in our pending rate case, as well as higher O&M costs due to regulatory, safety and weather-related activities. Compared to the second quarter of 2023, electric margin increased by $0.02 per share due to customer growth in the Conservation Incentive Program or CIP. And our final Energy Strong II recovery, an energy efficiency investment of $0.01 per share higher. Other distribution margin added $0.02 per share, while transmission margin declined by $0.02 per share due to timing of revenue and O&M, including our annual true up.

Ralph referred to the heat wave we experienced in June, and this warmer weather combined with greater storm activity led to higher corrective maintenance costs during the quarter. Distribution O&M expense increased by $0.04 per share compared to the second quarter of 2023, also due to higher gas meter inspections and safety costs. Depreciation and interest expense increased by $0.01 per share and $0.02 per share, respectively. Compared to the second 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 $0.01 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 $0.03 per share in the quarter, compared to 2023.

Summer weather in the second quarter as measured by the temperature humidity index was 42% warmer than normal and 99% warmer than the second quarter of 2023. In fact, the second quarter of 2024 was the warmest second quarter in our records going back 55-years, mostly due to that June heat wave. As a reminder, weather variations have minimal impact on our 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 broadly promote the adoption of its energy efficiency program. 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 $900 million during the second quarter and we remain on track to execute on our 2024 regulated capital investment plan of $3.4 billion. It’s focused on infrastructure modernization and decarbonization initiatives. These include upgrades and replacements to our T&D facilities, last mile spend in the infrastructure advancement program, ongoing gas infrastructure replacement spending and the continued lean energy investments across EE, smart meter installation and EV make-ready infrastructure. We are reaffirming our five year regulated capital investment plan of $18 billion to $21 billion from 2024 to 2028. The high end of this plan includes the $3.1 billion CEF, Energy Efficiency II filing made in December 2023 that would enable commitments from January 25 to June 27 based on the BPU’s EE framework.

As Ralph said earlier, this proceeding is expected to be resolved at the BPU later this year. Moving to PSEG Power & Other. For the second quarter of 2024, PSEG Power & Other reported net income of $0.27 per share compared to $0.51 per share for the second quarter of 2023. Non-GAAP operating earnings were $0.03 per share for the second quarter of 2024 compared to non-GAAP operating earnings of $0.02 per share for the second quarter of 2023. In the second quarter of 2024, net energy margin rose by $0.08 per share, driven by nuclear, including the net impact of the nuclear PTC that took effect January 1st, 2024. Partially offset by the anticipated reduction in generation due to the Hope Creek outage and capacity revenue. As a reminder, for 2024, there will be a shape to our quarterly results as we move through the remainder of the year.

We anticipate realizing most of the increase in the 2024 gross margin over 2023’s gross margin during the second half of the year, specifically in the fourth quarter 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 increased by $0.05 per share, mostly driven by the scheduled refueling at our 100%-owned Hope Creek nuclear unit. Interest expense was penny unfavorable reflecting incremental debt at higher rates, and taxes and other were $0.01 per share unfavorable compared to the second quarter of 2023, primarily reflecting the use of a higher effective tax rate in the quarter that will reverse over the balance of 2024.

On the operating side, the nuclear fleet produced approximately 7 terawatt hours during the second quarter of 2024 compared to 7.7 terawatt hours in the year earlier period and ran at a capacity factor of 82.7%. Nuclear generation in the first half of 2024 totaled 15.2 terawatt hours, which was impacted by the Hope Creek refueling, but also benefited from high capacity factor performance at our two Salem units, which operated at 98.9% for the quarter and at 99.3% for the first half of 2024. Touching on some recent financing activity. As of the end of June, PSEG had total available liquidity of $3.1 billion, including $113 million of cash on hand. Following the issuance of $1.25 billion of PSEG senior notes in March, during the second quarter, PSEG paid off $500 million of a 364-day term loan in April and $750 million of PSEG senior notes in June.

With the PSEG term loan redemption in March, PSEG variable rate debt at the end of June consisted of a $1.25 billion term loan maturing March 2025, the entirety of which has been swapped out from a variable rate to a fixed rate to mitigate the fluctuations in interest rates. At the end of June, given our swaps, we had minimal variable rate debt. On the credit ratings front, in June, Moody’s updated PSEG Power’s outlook to stable from positive. And this change is consistent with our future plans for leverage and our targeted credit rating. We continue to maintain a solid Baa2 investment-grade rating at PSEG Power. In closing, we are reaffirming PSEG’s full year 2024 non-GAAP operating earnings guidance of $3.60 to $3.70 per share. Which reflects continued rate base growth from ongoing regulated investments, offset by higher depreciation and interest as we await resolution of our pending distribution rate case later this year.

We are also reaffirming our forecast of 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. This concludes our formal remarks and we are now ready to begin the question-and-answer session.

Operator: Thank you. [Operator Instructions] The first question is from Julien Dumoulin-Smith with Jefferies. Please proceed with your question.

Q&A Session

Julien Dumoulin-Smith: Hey, good morning, team. Thank you, guys for the time. It’s nice to chat again. Back in action, as they say. Look, guys, nicely done. Seriously, a bunch of questions here, what you guys just said. First off, just talking about the data center opportunity, as is the buzz these days. Can you elaborate a little bit on what you’re seeing today about your co-located opportunities? And how do you think about the economic benefit criteria that you would and other stakeholders would like to see contribute to the local community here? Obviously, that’s a key element of bringing jobs to New Jersey here. So, can you elaborate on that? And then separately related, how would you characterize demand for data centers outside of perhaps co-located opportunities in New Jersey today? Any kind of quantifiable commitment numbers or soft numbers that you would kind of see today that you care to share?

Ralph LaRossa: Yes, that’s great. Thanks for that, Julien. And again, welcome back. Look, I would say a couple things to you. I’m going to answer your first question with purely my, choose New Jersey economic development hat on, and that is that it really has a couple of benefits of a co-located data center. And it’s not necessarily just that it’s co-located, it’s the fact that it’s a hyperscale data center. It’s going to provide a clear signal to AI companies that are looking to locate here in New Jersey and in the region, that the infrastructure is here up and running and ready to go for their businesses to thrive. So, there’ll be a lot of, I would say, trickle down opportunities that get created specific to the site. You obviously have your construction activities, but not the least of which would be driven by wire work that the IBWs here in New Jersey would benefit from.

So, there’s a lot of local opportunities that take place from the construction activities, they are one time. But as you’ve heard from others, they do grow over that one time. It’s not all done in one month, it’s over several years. They ramp up these data centers, and then there’s a lot of other opportunities that happen for edge computing, or AI infrastructure around the hyperscale data center, like a co-located one would be. Specifically, to our utility at PSE&G, we are seeing quite a bit of activity that’s taking place. We think about things and every utility is a little bit different as to what a commitment is. Some folks would count a commitment as only when they have a deposit for construction. Some would say a commitment is when you begin engineering work.

Some would say just getting a lead in with some other financing that you need to do to get the utility to respond might be a commitment. Well, the way we think about it is those that are actually have moved on beyond the engineering phase, and we’re seeing several hundred megawatts of data centers that are moving into that scenario here in New Jersey. And I would give you a little more breadth on that one, which is they all come in different sizes and shapes. Not only what the needs are at the location, from a power standpoint, it being different sizes, but actually the infrastructure that is required to support them are different based upon where they may be going, whether it’s a green field, a brown field, or an existing building that has enough capacity already run to it.

So, everyone’s a little bit different. Everyone’s a little different size, but it’s taken place and it’s significant for us.

Julien Dumoulin-Smith: Excellent, guys. And just quickly, if I can just to clarify on the excellent on efforts, should we say complaint with Talend here, does that shift at all, your thought process on any co-located opportunities just out here, but I’m just curious.

Ralph LaRossa: Yes, no, thank you, Julien. Again, look, that’s not shifting us in any way, shape or form. We’re committed to supporting the governor in his efforts on economic development. So, we are going to continue in that effort. I will say this to you, I’m a little bit concerned about co-located load as it impacts other industries. If you really think about co-located load, that doesn’t just apply to data centers, that’s for combining power plants, it’s for cogeneration units. So, depending upon where this goes, I’m much — while I’m concerned about data centers, I’m just as concerned about everything from rooftop solar behind a meter to co-generation that might be taking place.

Julien Dumoulin-Smith: All right, great. I’ll leave it there. Talk to you guys soon. See you soon.

Operator: Our next question is from the line of Shar Pourreza with Guggenheim Partners. Please see with your questions.

Shar Pourreza: Hey, guys. How are you?

Ralph LaRossa: We’re great. We don’t have to say welcome back to you.

Shar Pourreza: No, no, thank God. Rob, just to follow up on Julien’s question on sort of the protests at FERC against the Susquehanna ISA. Obviously it’s not gonna have a bearing on you pursuing a deal, right, with artificial island. But if the protest turns into a hearing, an NOI or an RTO process, do you kind of wait before signing a deal?

Ralph LaRossa: I think every deal is going to be very specific. And look, I think the way our nuclear facilities are configured, they’ll be different than a nuclear facility down the street. So, each one of those will be looked at differently, whether it’s by PJM in its current rules that exist for co-located load or FERC, when they come out with some sort of a process, if they do under the current challenge that’s there. So, no, I’m not really — I don’t think anything would hold us up. I think, again, I would just to reinforce, we’re here to support the governor of New Jersey. The governor of New Jersey is focused on building out AI, he just passed and signed — he didn’t pass, he just signed some tax incentives, up to $500 million to attract AI businesses here to New Jersey. That just happened last week. If there’s no more indication, and he’s all in, that would be it for me. And we want to be a company that’s supporting the policies of the state.

Shar Pourreza: Okay, perfect. Now that’s helpful. It’s a question we’ve been getting from investors. And then just last thing, obviously, you guys noted that the 5% to 7% growth rate kind of remains exclusive of upsides on kind of the nuclear business. So outside of kind of this data center opportunity, I guess, what progress have you made to implement some of the other upsides, right? So, any thresholds we should be thinking about on uprates as we head into sort of FIDs and some of these.

Ralph LaRossa: Yes, I don’t — I don’t think we’ve really published anything sure specifically. I think everything is on track. I will say that, there’s nothing that has raised a red flag for us in the process as we move forward, whether it be the fuel cycle changes at Hope Creek or the uprates that we mentioned in the prepared remarks at Salem, and certainly nothing on the long-term license extension. So, all three things are moving forward. And really, I have not seen a bump in the road from any internal analysis or anything that we’ve received externally.

Shar Pourreza: Okay, perfect. I appreciate it, guys. And big congrats on the execution. We’ll be seeing you soon. Thank you.

Operator: The next question is from Michael Sullivan with Wolfe Research. Please proceed with your question.

Michael Sullivan: Hey, good morning. Hey guys. Can you just comment, are you having discussions with your local transmission utility on an ISA for artificial island right now?

Ralph LaRossa: I don’t think anyone who has co-located load has to have a discussion with the transmission provider until they move forward with an interconnection agreement. So, I don’t. We have not at that. We have not stated that we’re at that stage, and we haven’t filed anything.

Michael Sullivan: Okay. And then just, I mean, you’re in maybe a little bit of a unique position, and owning both unregulated generation and regulated transmission in PJM. And I don’t think you all have kind of weighed in officially on the FERC docket, whereas it seems like the rest of the industry has. Any reasoning behind that or any thoughts you want to share on your views there?

Ralph LaRossa: Well, Michael, it’s not a contract that we’re privy to, so I really, I don’t think we feel that we have enough details to weigh in on what is there. There’s a process at PJM that we trust will be managed correctly by PJM. If FERC sees a challenge with that process, I’m sure that they’ll step in. We believe in following the rules, and so the rules that exist have some very specific steps in it. And if we were to go down that path, we would follow those rules. As far as weighing in on policy changes, again, I can’t tell you how much we’re trying to focus on supporting the governor’s economic development plans.

Michael Sullivan: Yep. No, that’s super clear. I appreciate that. And then just, like, pivoting over to along the same lines with the states goals. Any stance on offshore wind in the state. Just in light of the Nantucket news up there, is it still kind of full speed ahead from the governor’s standpoint?

Ralph LaRossa: It is from my perspective; I have not heard anything different. I know there were some challenges with the blades up there, but there was nothing that we’ve seen that would indicate there’s anything slowing down the process here in New Jersey. In fact, I think the governor, I keep talking about his economic development initiatives, and certainly offshore wind remains at the top of that priority list.

Dan Cregg: Yes. There’s an ongoing solicitation now, Michael.

Michael Sullivan: Got it. Okay. Thanks so much.

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

Nick Campanella: Hey, thanks. Hope everyone’s doing well. Hey, so just one more on the data center contract opportunity. Just, I know that you have the three different units and you can really cycle that as and market that as a kind of 24/7 offering, just given the refueling outage dynamics. But just thinking about kind of quantum of size here, does that conceptually mean that you’d be willing to sell up to a third of your total capacity? Are you trying to work to do something much more piecemeal and smaller than that? Just how should we kind of think about that?

Ralph LaRossa: Yes, I look again, and Dan, if he wants to add anything, is he’s a little bit closer to this in his, in his role with the development team. There’s nothing that’s that specific at this point for us. I think, look, there’s so many different factors that’ll be involved here. It’ll be the ramp up that’ll matter. It’s going to be whether or not — I’ve even heard some of these data centers are considering being a demand response resource. And that would certainly change the dynamics of any conversation. There’s just so much uncertainty now, Nick, as to where you would settle with anybody on any of these cases. I don’t want to talk about sizing. It would be really premature.

Nick Campanella: Totally get that. And then I guess just given PJM’s auction is coming up here, I think tonight we’ll get the results. But just your five to seven forecast, do you just assume just constant payment from the last auction or is there already an assumption embedded in there? Thank you.

Dan Cregg: Yes. And there’s assumptions that are embedded within our overall longer-term plan. But if you think about what we are from a generation perspective, the nuclear units’ capacity is not a very significant component of the overall mix. And so, there’s a — it is not, our five to seven overall, from an enterprise perspective, is not terribly sensitive to what that is. We’ll see what comes out here, I think, where the parameters seem to point. And a lot of what I’ve read shows things may be a bit more bullish than we’ve seen recently, but we’ll find out what that looks like at the end of the day. I don’t expect it to be significant enough to move us within, certainly outside of the range, and barely move us inside the range.

Operator: Our next question is from the line of Jeremy Tonet with J.P. Morgan. Please proceed with your questions.

Ralph LaRossa: Hey, Jeremy.

Jeremy Tonet: Hi. Good morning. Just wanted to circle back on data centers, maybe a little bit more, if I could. You least references increased inquiries at PSEG for data centers and the need for system investment to address this and EV charging. Could you expand a bit more on these comments? And how much is this additive to your current capital plan? Any other important points for us to think about here?

Ralph LaRossa: Yes, I think we’ll roll forward our capital plan at the end of the year, beginning next year, as we have in the past. So, any updates on that front will come there. Jeremy, I tell you, I think, look, I’ll walk you through a couple of scenarios that we’re seeing in the utility space itself. One is you’ll have, if anybody’s familiar with Northern New Jersey, there used to be a big Nabisco plant up in the northern part of New Jersey that doesn’t exist anymore. Greenfield is there and it’s near a 69 KV sub transmission line that we just built out, which is very close to a substation. I wouldn’t expect a lot of capital required if someone was to locate something there. But if you are talking about a data center that’s going to go into an old industrial site in one of the cities that has used up most of its capacity, and they’ve chosen that location because the construction of the building is such that they won’t really need to put up much capital to support all the servers that are there and the floor load and everything else that exists.

And I think that one might need a little more capital that’s going to be involved and it’ll be a little more complicated and we’ll see where things play out. So, every one of them are different. Right now, I would say that it’s a mixed bag as to what we’re seeing and where things are falling out. But it’s positive for us in the fact that we continue to see the growth that’s taking place here, and we’re attracting the businesses. A number of AI folks have been working with the state and we’re excited about it. We’re never going to be maybe as big as some of the other states are going to be, just by the geographic size that we are. But I think it’s going to make a difference for us here.

Dan Cregg: Hey Jeremy, the other thing I’d say is there’s another layer as you take a look at what PJM has done from some of their competitive windows, that is data center related as well. Those are competitive solicitations. They end up in regulated transmission. You’ve seen us participate in those before where in Maryland, we have a $400 million and change capital opportunity, and I think more of those are available to us. They’re competitive. We’ll see where we go. We don’t count on those within our existing plan, but to the extent that those come forward, there’ll be an opportunity there for us.

Ralph LaRossa: Yes, I think Dan just hit on a key point, Jeremy, the next PJM solicitation, I think it’s referred to as Window One, is a good signal as to what’s going to be required on the transmission side. Again, every last mile sub transmission, last mile investment will be different, but Dan’s absolutely right. Watch that load profile change of PJM to see what’s coming down the pike.

Jeremy Tonet: Got it. That makes sense. And any incremental thoughts you could share on the EV side as far as impacts that could have.

Ralph LaRossa: Yes, again, we’re seeing steady, slow but steady growth on the EV front. And proud to say we’re not turning down any EV interconnections. We have the capacity, but we’re upgrading that last mile. So that’s really playing out exactly the way we expected it to. New Jersey is, again, a little bit unique in the condensed nature of our housing and our commutes. So EVs have not had the same challenges and pressure that maybe the rest of the country has seen as far as the expansion that was expected. So, we’re kind of moving along at about the pace that we thought we would, and it’s having the impact on the last mile as we had planned.

Jeremy Tonet: Got it. That’s very helpful. And just one last one, if I could, and appreciate the sensitivities and limitations and what you can say at this point, but as folks make their way back from the beach over August into Labor Day, just wondering. So you can share with us on the rate case process in stakeholder discussions, point out there just any sticking point or anything else that you could share?

Ralph LaRossa: No, I really appreciate you asking that. Look, I take it as a big compliment to the team here that we’re this far in, and that was the first rate case question we got. So, the team is executing as we expect they would execute in those conversations. And the Board of Public Utilities, as I have been saying multiple times, continues to really run a very efficient and thoughtful process. So, I don’t see there’s no red flags there either. But I would point out that that recent COVID settlement that we just had was exactly the way we had thought it would play out. The fact that we expected the conversations not to become public has played out exactly that way. And so, I just very grateful for the way this has all been portrayed.

Jeremy Tonet: Got it. Great. Thank you for that. Hopefully everyone can enjoy their time on the shore.

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

David Arcaro: Hey, good morning, thanks for taking my questions. It sounds like there’s good momentum in terms of data center support from a policy perspective, and maybe on the contracting front. I was just wondering if there’s any timeframe that you would offer in terms of when you think you could come to a colocation deal.

Ralph LaRossa: No, David, we really haven’t gone there. I appreciate the question, but we just try to be thoughtful about everything and make sure that the folks that we talk to are people that are aligned with the policies we have here in the state.

David Arcaro: Yep, understood. Makes sense. And then in terms of the utility business request and increased data center interest at PSE&G, I was wondering, are you still seeing continued momentum? Is that backlog still growing and kind of, if so, is there a time when you would anticipate taking another look at the load growth outlook that you have in capex plans that would be required to address it?

Ralph LaRossa: Yes, David. So, I referred to several hundred megawatts that are at what I would consider to be the very firm stage that we would have. And again, every utility looks at that a little bit differently. The other two stages are even more robust than the very firm stage. The leads and the initial engineering analysis that would be done here somewhat double or triple in each one of those stages. From what we’re seeing in the firm construction side, that makes sense projects to look at, but we — any roll forward that we have from a capex standpoint, we will do at the end of the year, as I mentioned earlier. So, we’re just we’re happy to see it taking place.

David Arcaro: Got it. Excellent. Thanks so much for the color.

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

Carly Davenport: Hey, good morning. Hey, thanks for taking the questions. Just wanted to quickly follow up on Jeremy’s question on the call out on electric vehicles. Do you see any election related risk to the uptake of EVs in New Jersey and the potential investment needed to support that?

Ralph LaRossa: No, I don’t think, I don’t see any real risk from an investment standpoint here. I think most of those interconnections are done at the distribution level. There’s not an election that’s going to impact the state of New Jersey until next November. So, I think the only question, and we’ve talked about this before, is — will you have 100% EVs by 2035 or will we get a 50 on that test? And a 50 on that test is still going to be quite a bit of market penetration for the electric vehicle industry here. So, I’m not concerned about an election change. Maybe it’ll impact some of the tax incentives and some of the other things that we have. But again, the uniqueness of our condensed and compressed service territory, I think will keep electric vehicles at the forefront.

Carly Davenport: Got it. Okay, great. That’s helpful. And then switching gears, just, I guess as you think about your nuclear fuel requirements, I know you mentioned in the slides you’re covered through 2026 and then have a significant portion also covered through 2027. I guess. Just how are you thinking about longer term supply just in the context of the Russia waivers kind of rolling off in 2028? Just curious of your thoughts there.

Dan Cregg: Yep. We’re thinking about it quite a bit, Carly, and it’s very topical, given what you mentioned within your question. And so, there’s been a fair bit of work that’s been ongoing to move forward and extend out over time. And I would expect that, I don’t know, maybe when we’re sitting here at the next call, we’d have a little bit of an extension there we’d be able to offer. So, we’re aware of it on top of it. It’s not the most immediate, urgent thing that’s going on from the standpoint of actually producing power, but we always have a lead time that we’re interested in and continue to move forward on that. So, we’ll continue to push that data out and give updates as we do it.

Carly Davenport: Great. We’ll stay tuned there. Thanks so much for the time.

Operator: Our next question is from the line of Ryan Levine with Citi. Please proceed with your questions.

Ryan Levine: Good morning. For the EV program or energy efficiency program with a six-month extension in place, are you looking at any expansion to the energy efficiency program given the load forecast in the service territory?

Ralph LaRossa: Yes, I think that, Ryan, that we’re in the middle of trying to settle at, we refer to it as EE2, I think will be that response that you’re kind of inferring there that people are going to be looking at from a policy standpoint to offset some of the other data center and other load growth. So, the VPU has those filings from all the utilities here in the state, and they’re taking a look at it. I think their timeline was the end of the year to reach, I think it was October timeframe to reach settlement. So, I think they’re on track for that and looking for some consistency across all the utilities. So, again, completely aligned with the policy there. And I don’t expect a big jump in the next couple weeks, ask for a new filing or anything like that. I would just keep an eye on the filing that is in front of them today.

Ryan Levine: Okay. And then in your prepared remarks, you highlighted data center feasibility study that some of your potential customers are engaging in. What’s the scope of that study? And are there different legal or regulatory frameworks that may be deterministic around what’s viable?

Ralph LaRossa: Yes, no, I mean, look, a feasibility study is where — where we haven’t gotten an official request to go out and buy the copper, the transformers, and start digging a hole to install a wire. So, our engineers are out looking to see whether or not those megawatts that are being requested can be supported. And it is, again, I think if you talk to every utility, we would refer to that differently with a different acronym, and it might be at different spots in the process. I would say our feasibility studies are the middle of the road for us. When it becomes real in that last couple hundred megawatts, that’s what we consider to be a new business request, an official request that comes in, and then we have leads that are coming in all the time. But both the feasibility side and the leads are about triple right now, the actual new business requests that we’ve started to work on.

Dan Cregg: Yes, I think it’s inherent within your question, the legal and regulatory. I tend to think of it more operationally than anything else about just having the injection of that incremental need into the system. And can the system handle it? What will it take for the system to handle it?

Ralph LaRossa: Yes, I mean, the only time it would become a regulatory issue is if there was a concern that somebody turned down, whether it was a solar panel that was trying to get installed on one side or a data center because they didn’t have the infrastructure to support it in a timely fashion. It might be a regulatory issue raised in that scenario.

Ryan Levine: Okay, great. And just to confirm, so you’re saying that the Amazon connection dynamic isn’t being pursued or diligence through that process.

Ralph LaRossa: You talk about a hyperscale data center we’re handling through Dan’s team in the commercial development side.

Dan Cregg: Yes. To the extent there’d be a difference in the approach to the extent of something that might be co-located versus something that was, I think, inherent within your first question, which is about the feasibility study on the grid the utility has an obligation to serve. They’re figuring out the best way to do it, figuring out what has to happen from a capital perspective, and from a system operation perspective.

Operator: Our next question is on the line of Sophie Karp with KeyBanc. Please proceed with your questions.

Sophie Karp: Hi. Good morning, guys. Thank you for taking the question. Just kind of curious how you’re formulating your PJM strategy from here on, considering that you’re also looking at co-location opportunities. I mean, like with this next BRA auction coming up at some point this year, would you still consider bidding into it or hold back? Like, what’s your thought on that?

Ralph LaRossa: Yes, I think the data center that’s co-located, that doesn’t exist right yet needs to be built. And so that’s going to take some time, and that time is going to basically at some point, cross over what you’re looking at from a BRA. But I think where we are right now, we’re either not there or we’d be adjusted at the very [indiscernible]. So, I don’t think that that’s quite hit a crossover point yet. So, I don’t think that’s really critical to where we are.

Sophie Karp: Got it. Thank you. That’s all for me.

Operator: The next questions are from the line of Andrew Weisel with Scotiabank. Please proceed with your questions.

Andrew Weisel: Hi, good morning, everybody. First, one quick one to clarify. I know you’ve talked about it a little bit, but of the land of the artificial island, how much of that is already leased out, and maybe you could talk a bit about just the size and shape of some of those parcels, and how suitable it might be for a small number of larger facilities or a larger number of smaller facilities.

Ralph LaRossa: Andrew, it’s a great question, but one that we haven’t really discussed. And obviously we were being talking to folks and would give a handle as to what other people are thinking about. So, I don’t want to go down that path, but I would just say to you, qualitatively, I mean, big picture. Yes. I would simply say to you this. Any data center that comes in, each one of them have a unique configuration and design. Some of the data centers would be comfortable with multiple stories. Some are not comfortable with multiple stories. Some have certain cooling needs, others have different cooling needs. So, each one of them, it’d be really hard pressed to say one acre of land equals this many megawatts, and we’re seeing multiple designs, whenever we would have a conversation with anybody, and they think about it.

So, I kind of sidestepping that specific question, but really think that’s better left for the negotiating team and any conversations they’re having with developers.

Andrew Weisel: Understood. Certainly not one size fits all. Then if I can ask sort of a two-part question on the ZEC program. First question is, if we were to see the hypothetical red sweep scenario in November, would you have any concerns about the IRA and specifically the nuclear PTC being at risk? And then conversely, if you were to see data centers being co-located behind the meter, obviously, the original intent of the ZEC program was to support uneconomic struggling nukes. The nukes are no longer struggling. So, the question is, as you mentioned, the governor is trying to incentivize these tech companies to come. Would it make sense for New Jersey ratepayers, for PSE&G customers to be supporting tech companies? Is there a scenario that the New Jersey program gets revamped in one way or another if we do have hyperscaler signing co-located contracts?

Ralph LaRossa: Yes. So again, I’ll put on a couple different hats here, one of which is actually even a customer hat. I would say to you this, first of all, the ZEC program ends next March. So, start from — next May, I’m sorry. So, start from that scenario so that we would certainly, there won’t be any conversations or that would take place that would — we would benefit from a data center before then. Second, I think any company would be very hard pressed asking for a subsidy on top of a revenue stream that was similar to what was we think was just negotiated at Talend. And I’ll leave my comment there. That’s my customer hat being on. I would be hard pressed to think that you would pancake that on top of something else, whether it be the state subsidy or a federal subsidy.

Federal PTC, we don’t know what the definition is yet for gross revenues. And when that comes out, we’ll certainly take a look at it. Again, I would be hard pressed to believe that they’re going to allow a PTC payment on top of X dollar payment per megawatt hour that we’re seeing in the marketplace. So, there’s a lot of TBDs in what I just laid out for you, but there’s also a little bit of just reality. And I would not be thinking that we’d be asking New Jersey ratepayers to be subsidized in tech companies. In fact, I would probably step in front of that conversation myself personally.

Andrew Weisel: Okay, great. So, assuming things go in the direction of data centers, it would be more of a market-based pricing mechanism going forward, you would expect?

Ralph LaRossa: I don’t — well, again, look, I never want to say never, but I wouldn’t. I can’t see any other scenario.

Andrew Weisel: Okay, very good. Thank you.

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

Anthony Crowdell: Hey, thanks for squeezing me in. I guess Carly is looking to get like an EV IRA Camaro or something. I guess, just quickly, you guys are in a unique position where you have unregulated generation. You guys are the regulated utility in New Jersey. Just all the talk is maybe higher capacity prices, higher power prices. I mean, is there, while that’s going to benefit your units, but any thought on maybe the customer bill impact starts crowding out rate base investment, like managing that line? You guys are in a unique position where you kind of will see both ends of that.

Ralph LaRossa: Yes, Anthony. No, it’s a great question, and it’s one that we’ve been thinking about since 2008, right. We always go back and take a look when commodity prices were much higher and make sure that any projections that we have do not put us in that position. I’ve said it multiple times, and I’ll say it again. Because of the good economic development work that we’ve done in this region, not just in this state, but in this region, the income has continued to do pretty well. And if you look at the share of wallet or pocketbook that anyone would have to put up to pay their utility bills, it’s been pretty consistent over the last 20 years. So, I would expect that to remain the same. There’s a lot of that information that’s in our IR materials that we’ve gone over a bunch of times with you.

So, I don’t see anything that’s on the horizon. Even in some of the conversations that are taking place that would lead me to believe that we’re crowding out the required utility investment that’s going to have to take place if we’re going to have all this electrification.

Dan Cregg: And I think as we kick into PTCs too, Anthony, I think it rightfully puts whatever support there may be for nuclear at the federal level, which puts on even playing field for some of the PTC and ITCs that you see for other carbon free investments. So, I think that helps as well.

Anthony Crowdell: Great. Thanks so much for taking the question.

Operator: Thank you. Our next question is from the line of Bill Appicelli with UBS. Please proceed with your questions.

Bill Appicelli: Hi, good morning. How are you doing? Just similar line of questioning of Anthony there, but just maybe around the demand and supply balance in PJM. So, going back to the point of you kind of being on both generation front and on TD, I mean, how are you viewing the demand growth broadly, whether it’s behind the meter or otherwise? You did make that comment earlier about proliferation of colocation deals going forward in other sectors. I mean, do you have confidence in the current PGM process to ensure adequate reliability?

Ralph LaRossa: Hey Bill, look, I got to leave that to the experts at NERC and FERC and every place else to look at PJM and their processes. I am one of the folks who has continued to say we need to keep our eye on the ball very, very closely. That won’t change. I was very happy to see PJM react to our push specifically for our projections and to listen to the input that we provided them last year. I think they’ve started the process to look at load growth again. I think it’s another four- or five-month process that they’ve just begun, and they’ll come out with that towards the end of this year, beginning of next year. I trust that everything you’ve heard from other utilities that are within the PJM footprint and the load projections I said will be reflected in those, in those forecasts.

And as a result, we’ll either have a need for generation that’ll be signaled through the capacity markets or we’ll have some transmission that’ll be required, and you’ll see that come in there through the RTEP process. So, I’d like to see something longer from a capacity standpoint than three years or a year or whatever you might want to take a look at. It’s tough, when we were looking at those types of things, it’s tough to make a decision on building a power plant. We’re not in that business anymore. We’re simply here on the, with the assets we have, the clean assets that we have today and we’re going to continue on that path.

Bill Appicelli: Right. I guess maybe to that last point then, I mean, some companies within PJM have contemplated maybe pursuing legislation that could allow for regulated generation and rate base at some point. Right. If you feel like the system isn’t.

Ralph LaRossa: Yes, look, I think they may be closer to conversations they’re having with PJM and they may have more frustrations about how PJM is listening to them. We were pretty vocal and we got a decent response last year. So, I don’t want to really weigh in on what their conversations may be, and I think I might be doing that if I weigh in on their generation.

Bill Appicelli: Well, I guess the question is for you, right? I mean, would that be a path you would ever consider?

Ralph LaRossa: Oh, from our standpoint, look, I have said multiple times, Bill, we have more than enough capex to have our 5% to 7% growth rate with our replacement activities. If the state of New Jersey or the federal government says, hey, listen, we’d like utilities to go do that, we would certainly listen to those requests. But we like putting pipe in the ground and wires in the air right now, and we’re not in the business of building new rotating equipment. So, if that happens, we certainly can put that skill set, we have it, we could restart it if we needed to, but we’re counting on the marketplace that we’re in to resolve it right now.

Bill Appicelli: Understood. Thank you very much.

Ralph LaRossa: Yes, I think that’s it for the call, correct, timing wise?

Operator: Correct. Yes. I was just going to hand the floor back to you for closing comments.

Ralph LaRossa: All right, great. Well, I listen, great conversation. I really appreciate everybody calling in and appreciate the Q&A section, obviously was robust. I do want to just make one comment at the end here. We’re in our normal storm and season that takes place, and I’m going to go a little bit off the script here from the standpoint that I want to thank all those that responded to the storm down in Texas and just remind us all of the hard work that’s done, day in and day out by the line workers that responded in Texas. I was taken aback, I must say, by some of the behaviors that took place from a security standpoint down at center point and in Texas in general. And I just ask you all to keep that all in mind as we go forward into this season.

Lights will go out, storms will come through, and there’s people out there working really, really hard in some really tough conditions. And let’s just keep them in our thoughts and prayers. With that, I thank you for calling in, and we’ll catch up with you either on the road or in three months. Take care.

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