Ladies and gentlemen, thank you for standing by. My name is Rob, and I am your event operator today. I would like to welcome everyone to today's Conference, Public Service Enterprise Group's First 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, April 30th, 2024 and will be available for replay as an audio webcast on PSEGs 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 first 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 materials. 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 to review PSEG’s first quarter 2024 results. PSEG’s financial results for the first quarter are in line with our full-year expectations for 2024, and we are reaffirming our non-GAAP operating earnings guidance of $3.60 to $3.70 per share. We are also continuing to execute on our long-term strategy to grow PEG’s non-GAAP operating earnings by 5% to 7% through 2028, which we are also reaffirming today. This will be accomplished by investing in energy infrastructure and energy efficiency programs, which support greater electrification of transportation homes and workplaces, while also reducing greenhouse gas emissions while helping our customers lower their bills. Turning to the first quarter of 2024 PSEG reported net income of $1.06 per share compared to $2.58 per share in 2023, which reflects the absence of mark to market gains that benefited first quarter GAAP earnings in 2023. Non-GAAP operating earnings were $1.31 per share in the first quarter of 2024 compared to $1.39 per share in 2023. As a reminder, our non-GAAP results exclude to items shown in attachment seven and eight, which we provide with the earnings release. The main driver for the quarter was continued rate-based growth from investments focused on infrastructure replacement, which was offset by higher investment-related expense. These expenses will build over the balance of 2024 as we await the resolution of our pending distribution rate case later this year. In addition, the nuclear production tax credit went into effect on January 1st, 2024, which provides our nuclear fleet with downside price protection through 2032, an important contributor to the increasing predictability of PEGS’ results. Dan will provide a detailed financial review later in the call, but I want to note for PSEG, power and other, some margin contribution will be skewed to the back half of 2024 as we expect to realize most of the increase in 2024 as gross margin versus 2023 during the second half of the year. Turning to operations, we are pleased to report that both our utility and nuclear businesses continue to exemplify operational excellence. PSE&G and PSEG Long Island met the challenge of quickly restoring service to tens of thousands of customers following severe rain and windstorms early in the year. And at PSEG Power, our nuclear fleet also operated well during the quarter, achieving a capacity factor of 96.8% and supplying New Jersey and the region with over eight terawatt hours of reliable carbon free base load energy. Shifting to an update of our pending rate case, our combined electric and gas base distribution case covering 57% of our rate base is progressing as expected at the BPU. We are currently working through the discovery and documentation phase, responding to requests for information from parties to the case, and we recently submitted updated test your financials. The procedural schedule for the case includes several weeks of built-in settlement discussions beginning later in the second quarter. Based on recent and prior rate case timelines, we anticipate that this rate case will be settled later in 2024. As a reminder, this combined electric and gas filing proposes 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 this six-year period. During the same period, we have consistently delivered on our reputation for reliability, affordability, and nationally top-tier customer satisfaction scores with a nonstop focus on cost containment. PSE&G continues to manage its o and m to minimize customer bills while continuing to compare favorably to regional peers for residential, electric and gas service, and are among the lowest in national comparisons on a share of wallet basis. Now moving on to capital investments. We are on track to execute PSEGs five year $19 billion to $22.5 billion capital plan through 2028. The regulated portion of that program is $18 billion to $21 billion and it's focused on infrastructure replacement as well as our Clean Energy Future EE program. PSE&G has installed and placed into service about 1.8 million of the plan 2.3 million smart meters through our AMI program, still on schedule, it's still on budget for completion by the year end. These investments are projected to result in a compound annual growth in rate base of 6% to 7.5% through the 2024 through 2028 period. Premised on PSEG's year-end 2023 rate base of $29 billion, which was up 10% over the prior year, and we continue to pursue potential investment opportunities for future regulated growth. Among those opportunities, we are currently evaluating our competitive transmission solicitations in a Mid-Atlantic region, similar to PSEGs award of a $424 million project from PJMs 2022. Window three process. In April of 2024, PSE&G submitted bids to the New Jersey Board of Public Utilities or the BPU for its pre-built infrastructure project to support offshore wind. The BPU is expected to announce the winner or winners of the pre-built infrastructure solicitation in the second half of 2024. PSEG is also evaluating two other upcoming regulated transmission solicitations this July. The first is the BPU's second public policy solicitation for offshore wind transmission infrastructure utilizing the state agreement approach. The second is PJM's 2024 regional transmission expansion plan window one solicitation, which is expected to include the impacts of higher load growth forecasts that have been influenced by increased electrification expectations and data center load growth through throughout PJM. At Power, our nuclear fleet is also pursuing multiple growth paths with modest capital spending needs. We have previously commented on our plans for thermal up rates at the Salem nuclear station, which could potentially add up to 200 megawatts of additional capacity and would qualify for clean hydrogen tax credits under current rules for both additionality and hourly matching. PSEG nuclear has also notified the Nuclear Regulatory Commission of its intention to pursue subsequent 20-year license renewals for our three reactors in New Jersey. This would extend the operational capabilities from 2036, 2040, and 2046 for Salem units 1 and 2 in Hope Creek to 2056, 2060, and 2066 respectively. Beyond these opportunities in nuclear, there's been discussion lately about the potential for direct power sales to data centers from our 3 unit artificial island site. We have had discussions related to both sides of the meter in recent months. In a form of new business inquiries at PSE&G for mid-sized data center construction of approximately 50 megawatts to 100 megawatts and behind the meter inquiries for co-located facilities that prioritize highly reliable carbon-free baseload power from existing facilities, all without the challenges faced by non-dispatchable generation. PSEG has a long history of aligning with New Jersey policy goals. This data center opportunity has the potential to create a nexus between economic development and energy policy, and we stand ready to support New Jersey. In its recent efforts to create an in-state artificial intelligence hub, our New Jersey nuclear units could provide access to a highly reliable, carbon-free source of baseload power and infrastructure consideration as increasingly mission critical for the large data center developers and hyperscalers. One thing that is certain at this point is that all these opportunities in nuclear would be incremental to our long-term forecasted growth rate guidance of 5% to 7% through 2028 based upon that PTC threshold price. Another differentiating factor for PSEG overall is that our nuclear operations provide the business with the added flexibility to fund its current regulated investment plan without the need to issue new equity or sell assets. I'd like -- my remarks by thanking our employees for all they do and their dedication to safety, reliability, and our customers. I'll now turn the call over to Dan to discuss our financial results and outlook in greater detail, and I will be available for your questions after his remarks.

Thank you, Ralph. Good morning everyone. As Ralph mentioned earlier, PSEG reported net income of $1.06 per share for the first quarter of 2024 compared to $2.58 per share in 2023. Non-GAAP operating earnings were $1.31 per share in the first quarter of 2024 compared to $1.39 per share in 2023. We provided you with information on Slide 7 regarding the contribution to non-GAAP operating earnings per share by business for the first quarter, and Slide 8 contains a waterfall chart that takes you through the net changes quarter over quarter and non-GAAP operating earnings per share by major business. Going with PSE&G, which reported first quarter net income of $0.98 per share for both 2024 and 2023, PSE&G had non-GAAP operating earnings of $0.98 per share for the first quarter of ‘24 compared to $0.99 per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth and rate based from continued investments in infrastructure replacement offset by higher distribution, investment-related depreciation and interest expense, not yet reflected in rates as well as higher O&M costs compared to the first quarter of 2023. Margin was $0.07 higher in total driven by transmission at $0.03 per share, gas margin at a penny per share and other utility margin added $0.03 per share. Distribution O&M expense increased $0.05 per share compared to the first quarter of 2023, primarily due to gas meter inspections and overhead corrective maintenance following severe rain, wind, and flooding events early in the year, and tree trimming. Appreciation and interest expense increased by a penny per share and $0.03 per share respectively compared to the first quarter of 2023. Reflecting continued growth and investment, these costs of weight recovery in our pending distribution rate case anticipated to be settled later this year. 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 had a net favorable impact of $0.02 per share in the quarter compared to 2023, whether during the first quarter as measured by heating degree days was 17% warmer than normal, but 9% colder than the first quarter of 2023, which was the warmest first quarter in PSE&G’s records. As we've mentioned, the conservation incentive program or SIP 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 programs. The number of electric and gas customers, which is the driver of margin under the SIP mechanism, continue to grow by approximately 1% over the past year. On capital spending, as Ralph mentioned, PSE&G invested approximately $800 million during the first quarter, and we remain on track to execute on our 2024 regulated capital investment plan of $3.4 billion focused on enter on infrastructure modernization and electrification initiatives. These include upgrades and replacements to our T&D facilities, last mile spend in the Infrastructure advancement program, ongoing gas infrastructure replacement spending, Energy Strong II investments, and the continued rollout of the clean energy investments in 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. This 2024 to 2028 plan includes the $3.1 billion CEF EE2 filing made in December, 2023, which would enable commitments starting January, 2025 through June of 2027. Based upon the BPU’s EE framework with investments being made over a six-year period. This proceeding is expected to be resolved at the BPU later this year. Moving on to PSEG Power and other, for the first quarter of 2024 PSEG Power and other reported net income of $0.08 per share compared to $1.60 per share for the first quarter of 2023. Non-GAAP operating earnings were $0.33 per share for the first quarter of 2024, compared to non-GAAP operating earnings of $0.40 per share for the first quarter of 2023. For the first quarter of this year, net energy margin rose by $0.03 per share, including $0.02 favorable contribution from nuclear driven by the net impact of the nuclear production tax credit, which went into effect January 1st of this year, partially offset by reduction in capacity revenue. Also, in energy margin gas operations increased by a penny per share compared to the year earlier quarter. Importantly, for 2024, while the PTC begins this year, there will be a shape to our results per quarter as we move through the year. We anticipate realizing the majority of the increase in the 2024 gross margin, over 2023s gross margin during the second half of the year based upon the shape of our underlying hedges. This will differ from last year when PSEG Power realized most of the step up in the annual hedge price in the first quarter based on lower pricing in the winter of 2022 compared to 2023. O&M increased by $0.03 per share, mostly driven by the start of the scheduled refueling at our 100% owned Oak Creek nuclear plant. Interest expense was a penny unfavorable reflecting higher interest rates partially offset by lower short-term debt balances. Taxes and other were $0.06 per share unfavorable compared to the first quarter of 2023, primarily reflecting the use of a higher effective tax rate in the quarter. That will reverse over the balance of 2024. Operating standpoint, the nuclear fleet produced approximately 8.2 terawatt hours during the first quarter of 2024 compared to 8.4 terawatt hours in the year earlier period, and ran at a capacity factor of 96.8%. Our Hope Creek Nuclear Unit is undergoing its scheduled refueling outage, which will include preliminary work on the fuel cycle extension project. As a result, as is always the case with outages for our a hundred percent owned Hope Creek Unit, we expect a little higher O&M and lower generation in the second quarter. Touching on some recent financing activity at the end of March, PCG had a total available liquidity of $5 billion, including $1.2 billion of cash on hand. Our revolving credit facilities totaling $3.75 billion were also extended by one year to March of 2028. During the first quarter at the end of March, PSEG had $500 million outstanding of a 364-day variable rate term loan, which subsequently matured in April of 2024, and PSEG Power had $1.25 billion outstanding of a variable rate term loan maturing March of 2025. The entirety of these term loans were swapped from a variable rate to a fixed rate, mitigating the fluctuations in interest rates as of the end of March. Given our swaps in cash position, we had minimal variable rate debt in early March. PSE&G issued $1 billion of 10 and 30 year secured medium term notes consisting of $450 million at 5.2% due March, 2034 and 550 million at 5.45% due March, 2054. A portion of the proceeds was used to pay the maturity of $250 million of 3.75% secured MTMs on March 15th. Later in March, PSEG issued $1.25 billion of senior notes consisting of 750 million at 5.2% through April 2029 and 500 million at 5.45% due April, 2034. A portion of the proceeds will be used to pay the maturity of $750 million of 2.875% senior notes in June. We continue to maintain solid investment-grade ratings. Looking ahead, we expect that PSEG's considerable cash generation combined with PSEG powers enhanced cash flow visibility from the nuclear PTC will support the execution of PSEG's five-year capital spending plan dominated by regulated CapEx without the need to issue new equity or sell assets. In closing, we are reaffirming PSEG’s full-year 2024 non-GAAP operating earnings guidance for $3.60 to $3.70 per share, which reflects continued rate-based growth from ongoing regulated investments offset by higher depreciation and interest expense that will build over the balances of 2024. 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 and non-GAAP operating earnings through 2028, supported by our capital investment programs and the new nuclear PTC. That concludes our formal remarks, and we are ready to begin the question and answer session.

[Operator Instructions]. The first question is from Nick Campanella with Barclays. Please proceed with your question.

Thanks for all the context around the direct power sales opportunities with your nuclear facilities. Can you just kind of comment on the potential, just the timing around any potential announcement and then how we should kind of think about when that could contribute to EPS if it were to be achieved. Then just, I know you kind of talked about being in like the nexus between economic development and energy policy. Is there something that you're looking for from the state before moving forward with this? Or just what are the data points that investors should be looking for to know whether this is becoming more of a reality or not? Thanks.

Yes, Nick. Look, I think, the bottom line here for us is that we kind of see this as just a continuation of us following the state's policy, not setting it. I think the governor has been very clear about his desire to attract AI jobs to New Jersey and the infrastructure in data centers and other IT assets or things that he's looking to have in place. Now, the timing of something like this, I think is driven by a number of different factors, you have got some of the hyperscale, data centers and their timing. I don't want to, I really don't want to talk for them, and I don't want to front run the governor on some things that he may or may not be working on. So, we're here to support. And I think from a timing, overall timing standpoint, I would just really follow the state's announcements and policy initiatives around this effort.

I appreciate that. I guess, I think you also said in your remarks that you would maybe provide an update later in the fall. I guess that would be, dependent on how the rate case kind of progresses, but to the extent that you're giving a refreshed kind of financial outlook, when would that be? And then also is the data center opportunity something that could be included in that, or it would really kind of be post that ‘25 and beyond?

Yes, Nick, I think those are really kind of a couple of different pieces there, we'll roll forward later in the year as we roll forward every year. I think we start out with the CapEx and some other items at the end of the year, and then our earnings beginning of next year. But the data center specific, we're not going to change our plan. Power is still a very small part of this company's earnings stream. It is a all upside, so I understand the attention to it, but what we'll do is we'll roll in any PPAs, whether it be on data centers or hydrogens, opportunities or anything else that we have down at the plant. We'll optimize it, and as soon as we agree on terms around something like that, we'll roll it in, and be transparent about it. But right now, our plan as we look forward is to continue to project ourselves out based upon that PTC floor.

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

Just wanted to touch base on a non-data center question here. You've been closely following, the state and regional transmission needs for offshore and now that data centers have come into the equation having an outsized impact, how do you see the transmission system changing overall and how do you see pegs role in this?

Jeremy, I think, it's really my advice is to keep a very close eye on the PJM -- process as they continue to re-evaluate the topology of the transmission grid. I think there'll be opportunities across the PJM footprint. Look, you got to just take a look at what happened at with -- as a very simple example. That power plant was connected to our Susquehanna Roseland line. That power, at least a hundred megawatts or so of it won't be flowing out of the power plant into the grid. And so that'll have an impact on the topology in a very simple term. Then you've got data centers popping up in different locations. We have a number of requests that have come into our utility that we're processing not of the magnitude of a hyperscale, but smaller edge-type computing solutions. And so, each one of those will have an impact and the place where it all comes together, and I would encourage you to take a look at is through that -- tech process. Offshore wind will be one of the generation solutions for it, but there will be need for additional modifications to the grid and it's a TBD for all of us.

And then just think about the picture at large in structuring tariffs in a way that doesn't impact other rate payers. Just wondering if you could provide any other thoughts on that. I guess, making sure this is developed in a way and such that other rate payers don't bear more burden. Look, if it's a behind the meter solution, the way rate payers will be held harmless on that is that they -- there won't be any additional infrastructure charges, so they wouldn't be burdened with additional infrastructure other than if there's new generation that comes on and it has to be supplied into the grid and there's different paths. Those interconnection agreements are the way that that's handled through cost allocations at, in the PGM market today. So, I think there's a very fair and transparent way that's taken care of. And I think each state has a different solution for in front of the meter data centers or loads that are popping up and those state individual tariffs. And I guess, every state will take a look at it from an economic development standpoint and determine how they want to handle it. But we haven't seen any changes in New Jersey to the tariff requirements for new business extensions.

Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Dan, maybe just what are -- like, just any updates on the nuclear PTC guidance from the IRS? It feels like we've been waiting on it forever. And then any implications that you see coming from that guidance on your financial plan, please.

To guess, I wish I had a better answer for you, but we continue to wait for guidance to come out of treasury. I know that there's been a host of different approaches to treasury to try to spur some information to come out. But I know that you know that the PTC began January 1st, so we are in it. And I continue to think that the most important definition is as we've all thought about it, is the definition of gross receipts. And so that's what we're waiting for more than anything else. I think we're moving forward. We're finding out a little bit more about what ‘24 looks like every day that goes by in ‘24. And we continue to do what we've been doing is trying to think about what different potential outcomes could come from treasury and try to position ourselves as ideally as we can against the backdrop of that uncertainty. And I think we're doing fine there, but we would prefer to have it. I don't have a date for you. I don't have an estimated date. And I've not heard that one is forthcoming. So, I think we're in the same boat. I think we're just waiting.

I appreciate that color. Sounds like you're kind of planning different scenarios and you've kind of baked that risk and opportunity into your 2024 guide guidance. Is that a fair way to put it, Dan?

Yes. I think that's exactly right.

And then just, you had this very nice chart that you used to share. I think it was maybe a bit dated now. It showed your balance sheet capacity in terms of funding more or higher CapEx and you have all this opportunity, whether it's transmission, related or on the nuke side. I know that's going to be capital light, but generally speaking at the utility, whether it's energy efficiency, whether it's the transmission opportunity, just can you give us a sense of, and the CapEx plan recently was raised light right in December 13% over the prior five year. So maybe can you give us a sense of how much more capital can the balance sheet cover without issuing any equity, if there's a way to do that? Thank you, Dan.

Yes, and we've talked about, it's going to come off of the FFO to debt. And I think that, one of the things that when you did see that increase in capital that you referenced, there are different FFO to debt implications depending upon exactly what the capital it is. And kind of on the opposite ends of the spectrum, our energy efficiency program has a recoverable life, depreciable life, amortizable life, whatever you want to call it, closer to 10 years to 12 years and are more infrastructure-oriented investments have a longer, recoverable life. And so, when you look at those particular investments, you're going to see much less of an impact on your FFO to debt. Because you're going to see a lot of cash coming back to you quicker. To the extent that it's EE benefits, that's something that's more steel on the ground, whether it's on the transmission side or electric or gas side. And then to your other point, I totally agree with your comment that, on the power side it would be capital light, but it could be FFO positive in a fairly significant way. So, those are the elements that move around. If we're in the mid-teens, our current threshold for where we are is 13, 14, depending upon whether you're talking about Moody's and S&P. So, we've got some room in there, but I think it's not -- it's going to depend a little bit on the nature of the investment and I think as you saw more of that increase coming from EE of late, it was more credit friendly for us to move in that direction.

Our next question is from the line of Shar Pourreza with Guggenheim.

It's actually Constantine here for Shar. Thanks for taking the questions. I really appreciate the commentary on the nuclear opportunity. Maybe a bit of nuance from your perspective, is behind the meter a scalable opportunity for data centers in New Jersey, or is it a bit more kind of one off as you look at it? And maybe as you mentioned, there's a level of potential grid dependence and do you see that becoming a concern at all for regulators or is that kind of getting addressed in other forms, regulatory forms?

Look the grid, I'll go backwards on that. The grid dependence, Constantine, I think is, it's not just data centers, right? We're seeing electrification across the board, and as policy makers continue to move in that direction, we have to be aware and make sure that the system's being built out correctly. I think it's being handled on multiple fronts. It's being handled at FERC. It'll be handled at each individual state, but there's plenty of avenues for those conversations that take place in and to keep the burden to customers to a minimum. No offense or buts about that -- the scalable side, I'm going to give it to Dan, because his team does a lot of work on the commercial front. I'll just tee up that there are different ways that you can look at it and Dan's team is doing a great job of talking to multiple folks and looking at multiple solutions that he can give you some more detail about it.

It's a great question, but if I try to think about exactly then the nature of how you're asking, I think that by definition, if you're going to do something behind the meter, you're going to do it at scale. And so, I think that you wouldn't move into that situation with something that was not of scale and grow at the scale other than the natural fact that I think you're not going to have a data center of scale appear immediately. And so, it's more likely, and from what we have seen, you would see something that would be agreed to be upscale that would come in over time.

And so, if you, if that meets your definition of scalable meaning it's going to grow as you step through time, I think that the answer would be yes, but I think you'd want to set that all up right at the jump. And Constantine, the only thing I'd add to what Dan said, just a reminder, where we sit geographically is a great spot, but I also point out to everyone, we're the only merchant site that has three units on it, so the ability to scale there is a little bit different and the ability to back up the supply is also very different. We're really excited about whatever those opportunities might be down the road because of that.

That's abundantly clear. And maybe as we look a little bit more broadly at just supply and demand in power markets and power prices are now well north of the PTC levels for the ‘25, ‘26 trip, which kind of continued to be the PTCs that were the core planning input. Do you plan to update guidance as you kind of recontract or start realizing those revenues and do those become ACC creative to the credit metrics and kind of the investment capacity that you talked earlier about?

I think, if there's a change in how we are looking at things and what we are seeing that is in place in lock for a period of time for us to be able to say something about it, I think that's a logical time for us to do something constant. You've seen these markets for a long, long time. You know that they come up, they come down and they're cyclical. And so, in an instant, when they are higher, our intention is to try to be more predictable and come out to investors and let them know what they can count on and to the extent that there's some upside opportunities speak about it, but not have it be embedded until it is real. We're trying to just kind of keep things grounded. And so, my sense is with that you will probably see that as you continue to go forward from us.

And just a reminder, Constantine, the highly visible and liquid PJM West top is not necessarily reflective of the entire PJM marketplace. So those numbers aren't dead on for everybody.

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

Maybe just on the Hope Creek outage, you mentioned that you're doing some of the initial work on the kind of fuel cycle shift there with the outage. Could you just talk a little bit about sort of the scope of what's getting done and how much will be left in order to make that shift as we get to 2025.

Yes. It's -- Carly, it's a very small piece of the puzzle that's going on now. There's a lot of engineering work that's going on. There's work that's being done on -- we're doing a rewind on the generator that in part of this outage, we've got an upgrade that we're doing -- we're basically cleaning out some old insulation on the cooling tower, which provides us about 8 megawatts of additional capability there. I mean small, little pieces, but really helps us in some -- based upon weather conditions and the rates that are required. So, lots of work to optimize the unit itself in anticipation of that fuel change that we're going to be making down the road. So, it's -- the investments will be made at Hope Creek over the next couple of fuel cycles, and then we'll be ready for the ultimate change to the 24-month cycle.

Got it. Okay. Great. That's helpful. And then maybe you just mentioned a bit higher O&M related to the Hope Creek outage and then you talked a bit at the beginning some of the storm activity that you had to respond to earlier this year. Just any thoughts on where O&M for the full year could sort of trend versus last year with some of those early moving pieces in mind?

Yes. Carly, we may see it to move a little bit higher. It's funny. We talked a little bit about the weather in the earlier remarks, and it was a fairly mild winter, but it was a really wet winter, and we had some storms that were not exactly temperature-driven as much as they were precipitation-driven. And so, some of that drove costs a little bit higher as did. Any time we have a Hope Creek outage, it's 100% owned. So, there's a little bit of a bigger impact there. And so, some years, we'll have that, some years we won't. So, you'll see that come through on the power side. But really, the storms were one of the contributors to the first quarter's impact on O&M.

Our next question is from the line of Andrew Weisel with Scotiabank. Please proceed with your question.

Appreciate the details on the nukes. Maybe just one -- can kind of pin you down a little bit to size up the opportunity, how much nuclear capacity do you have that's not committed to state programs like the ZECs or other obligations? In other words, how many megawatts could actually be committed to a new dedicated customer?

Yes, Andrew, I think, look, you can look at what happened at Talend as a placeholder for size of units at hyperscalers are thinking about. Just a reminder, our state plan kind of ends in May of '25, right? So, we're -- I don't see a data center being built before May of '25 down at that site. We may be in discussions with folks and have something to say sooner than that. But I don't expect any power to be flowing into a data center before May of 25 when that program ends. And then we'll see what the rules say on the IRA and how the PTCs interact with any of this kind of agreements that are reached.

But your expectation is the entire portfolio is available?

I think, the entire portfolio could be available for long-term contracts. And again, I think that that falls into a bunch of different scenarios. I don't think there's anything that's a restriction and we'll continue to work forward and keep you posted.

Just wanted to clarify that then second pivoting to the energy efficiency side of the utility, the -- two program you filed in December calls for $3.1 billion of spending, much bigger than the first program at about $1 billion. Can you just talk to some of those dynamics of why each incremental kilowatt hour of savings is so much more expensive, and maybe more importantly, are you seeing any pushback from the BPU or key stakeholders, or is this all well understood and supported?

Andrew, it's kind of simple as to why the dollar per megawatt saved goes up. I mean, you're going from changing light bulbs, which was the first effort that we started way back when and thermostat changes to now you're upgrading HVAC units and moving into commercial and industrial operations. That's very different just from a dollar per megawatt hour save standpoint. As far as the pushback, this was all part of the BPU's triennial, so a lot of what was submitted was based upon the needs identified by the Board of Public Utilities and really are not a surprise. The question will be just from a total spend standpoint, how far they would like to go. I don't think there'll be a lot of arguments about the cost per based upon one historic performance, which has been really good. And then second the types of work that we'll, the type of work that we'll be doing going forward. Andrew, also, within what the BPU -- I think to their credit, they tried to take a philosophy in approaching this, that they wanted to target things through this program that they viewed would not happen otherwise. And so, these light bulbs is an example of that given that incandescent are off the shelf, but in other examples too things that were going to happen anyway are not a great target for this kind of a program is to try to expand what would otherwise happen. And so that I think expands the reach a little bit moves them to a better place, but may cost a little bit more to get it done.

Our next questions from the line of Steve Fleishman with Wolfe Research. Please proceed with your question.

Sorry, another nuclear question. We've talked about this hypothetically the last -- let's say six, nine months hydrogen, I think there's supposed to potentially be like offshore wind port next to the plants around there, and then obviously data centers. Now just should we think about these as things, all things you can do there or you have to kind of focus to one and data centers is now kind of top of the list?

No, Steve, it's a great question. So, the port is built. I mean they've done a ton of work down there, and that was the New Jersey Economic Development Authority has done a lot of work there. I don't know if we can pull a ship up there yet, but we're pretty darn close. So, there's been a ton of activities completed. And they started to lease some space to some of the offshore wind developers. And so, I think from a state standpoint, that's going pretty well. Then there's additional land that's available, and you could put a data center there, you could put how big it is, is a question right? You've got to figure all of that out based upon each individual developer design criteria and what they might be considering and the size that they're looking for. You could put a hydrogen unit there, you might have an electrolyzer or something that makes some sense to go there? Or maybe it goes a little bit off property, right? And again, it all depends upon the rules that come out and what we finally see from the IRA implementation. So, we're thinking about it as all of the above and an optimization strategy. Just to figure out what is the best way for us to use those -- that electricity that's coming off the units and doing in a way that's completely aligned with the state's policy. So, you could do it all. It's just a matter of what the policy is at the state and how big any one of those individual opportunities become.

An on the hydrogen front, Steve, as just a reminder, an upgrade there would meet both additionality and hourly matching to the extent that those limitations continue on hydrogen. So, I do think we feel pretty good about what we have the ability to do down there and don't see limitations on having to pick one or the other.

Okay. And then just the other -- I guess the other part of this is just reliability in New Jersey overall and just a lot of focus on offshore wind that's been delayed and the like. And just -- so I guess from that last standpoint can kind of how are you in this alignment with the state thinking about that aspect to be able to do something behind the meter at nuclear?

Yes. So, Steve, that power flows a whole bunch of different ways, right, not just in New Jersey, but other states, right? So, it's more of a PJM question as to that specific unit in those specific megawatts. But I will say this, and what we've set it in multiple settings, I apologize if it's a repeat, but that 2003 blackout gave us the opportunity to rebuild the transmission infrastructure and we did that. And as Sandy comes along when we rebuilt the switching stations and substations. So, we're well prepared for this. I think New Jersey is uniquely prepared and I've got my economic development hat on here for a second, but I think we're in a really good place. and the margins aren't quite as tight as some others might have. So, I think we're looking at this and trying to figure out what's the best solution for the state and we're doing it in a partnership that one-off of the states plans. So, we feel pretty good.

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

Had a, I guess, one or two more on nuclear. In terms of the duration of contracts that your counterparties may be willing to sign. I think in your comments, you mentioned long term, any color you could share around how long term is as you look at it? And then to the extent that there's transmission constraints in PJM, how does the timeline of any investment there play into ability to serve that longer term?

Ryan, I think, the simple answer on the first question is somebody's going to come in and build a data center that's going to be a very, very significant investment and it's going to be around for a long time. I don't have a specific number of years to give you, but I think long term is pretty comfortably thought about as being long-term. And I think on the transmission side of things Ralph just really, I think gave the right response as much as we have built out the transmission system, given what we went through about 20 years ago and 10 years ago I do think we're prepared for whatever flows need to happen within the region. Both of those I think are in pretty good shape.

And then to follow-on the last line of questionings, to the extent that there is policy opportunities to maybe attract this customer base to the state, are there any legislation initiatives that you're keeping an eye on that may make it more palatable for other stakeholders to attract this load to the service territory?

No, so I believe, again, I'm putting my other hat on. I believe the state has plenty of solutions for new businesses to move to New Jersey or to start up here. There was a number of different initiatives down at the EDA that could attract businesses, and I don't think anything that I've seen would require additional legislative changes. There may be some to speed things up or expand opportunities for folks, but I'm pretty confident that the state has the tools and its tool just to reach out to the opportunities that it has.

Our next questions are from the line of Travis Miller with Morningstar. Please proceed with your question.

Since I don't have to apologize for a nuclear question, I suppose I'll jump in with another one here. Just thinking about what a contract at a very high level might look like for a co-located facility. And mainly, I'm thinking about who would take the risk on their -- of perhaps a non-performance or something like that. Is that something you'd be comfortable with or is that something you're going to essentially make the offtaker take that risk?

Travis, I would simply tell you way too soon for us to be talking about anything like that. We're not in a position to talk about any details of any discussions. I would say this to you though, we've answered the question a bunch of times. And I'll tie it back to the hydrogen opportunities. We don't want to get into the commodity risk commodity risk situation. What we basically look at this is, we put a meter at point A and folks can pick it up from there and figure out what they're going to do with the electricity. And I don't see data centers or electrolyzers or anything else that might happen in that space as different.

And Dan, I don't what you want to add. No, I mean, the only thing I would say is, is just from a practical perspective, if you think about a 3 unit site, you've got a lot of redundancy in the ability to deal with things like that. And so obviously contractual T's and C's are going to be worked through as across the entire breadth of, of whatever agreement you come to. But I think we start from a position of strength there.

And then one other question on the transmission in your bids and proposals there. How much does what you proposed or put in those bids depend on a second round of offshore wind projects coming in, is any of it or some of it.

Yes. So, Travis, I think there's two answers there. First, the PBI, the interest prebuild opportunity does not require that. It's basically very similar to what happened in the first solicitation where use an analogy. It's a [Indiscernible] for pipes coming -- or wires coming in from the offshore wind farms. So that piece really is not dependent. I think the size and scope of the next solicitation is clearly dependent upon what -- how big that offshore wind opportunity gets for the state as a whole. And that -- we have not seen a scope of what that might look like yet.

Okay. And would that be through the PJM process or through New Jersey process?

It would be a PJM process initiated by the state agreement approach from New Jersey. So, New Jersey would pick up the phone call PJM and ask them to run the process for -- on behalf of the state.

Our last question is from line of Paul Patterson with Glenrock Associates. Please proceed with your question.

So just to sort of follow-up on the transmission stuff. I was wondering if you could -- what your thoughts might be with respect to the upcoming transmission policy agenda that's coming up here with FERC in the next few weeks. Any thoughts about how -- what you think might be coming out there and how it might affect you guys?

No. I think -- look, there's 5 or 6 items that are there. We have some folks that are heavily involved in transmission in our wire’s organization, so many other ones. So, we're staying abreast of it. I think FERC has remained balanced under the current share. And I don't expect some wild swings in the outcomes there, but we're monitoring it closely right now, Paul, and I wouldn't have much more to add than that.

Okay. And then just on another big policy push that we're seeing from different officials is grid enhancing technologies. And just wondering if your -- if you see -- how you see that might-- how that might impact you guys or your operations in the next few years?

Yes. So, some of that grid enhancing has really been focused. I think there was a New York Times article on it about the upgrades of some of the conductors that people have installed. And we've looked at some of that and piloted some of that. As we've talked about, we've done a lot of transmission upgrades. We've also built into our system, the ability to do some additional upgrades. But I think that just becomes a cost benefit for the consumer based upon what additional capacity we would get out of it and whether or not we wouldn't want to front run the need. So, it's something we'll monitor and it's something that PJM again, will have in their tool chest to make some determinations upon how they want to solve some of the gaps that might get created as we move forward here with electrification.

There are no further questions at this time. And I'd like to turn the floor back to Mr. LaRossa for closing comments.

I just simply want to thank you all for your continued confidence and support, we welcome all these questions and we really look forward to getting together with most of you at AGA later in May. Again, thank you to our employees, to our customers, and to and to our investors, and we'll see you all in California. Take care.

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