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. As a reminder, this conference is being recorded today, April 30th, 2024 and will be available for replay as an audio webcast on PSEG's Investor Relations website. 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 Investor Relations website 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 Investor Relations 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 PSEG’s non-GAAP operating earnings by 5% to 7% through 2028, which we are 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 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 expenses. 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 PSEG's 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 baseload 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 financial information. 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 operating and maintenance 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 PSEG's 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 energy efficiency program. PSE&G has installed and placed into service about 1.8 million of the planned 2.3 million smart meters through our AMI program, still on schedule and on budget for completion by 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 the Mid-Atlantic region, similar to PSEG's award of a $424 million project from PJM's 2022 window three process. In April of 2024, PSE&G submitted bids to the New Jersey Board of Public Utilities 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 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 upgrades 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 and 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 three-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 considerations that are increasingly mission-critical for 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 to close 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 regarding the contribution to non-GAAP operating earnings per share by business for the first quarter. 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 expenses that are 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 by $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. Depreciation and interest expenses 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 await 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. Weather 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 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 continued to grow by approximately 1% over the past year. On capital spending, 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 infrastructure modernization and electrification initiatives. These include upgrades and replacements to our transmission and distribution facilities, last mile spending in the Infrastructure advancement program, ongoing gas infrastructure replacement spending, Energy Strong II investments, and the continued rollout of the clean energy investments in energy efficiency, 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 Clean Energy Future program filing made in December 2023, which would enable commitments starting January 2025 through June 2027. Based upon the BPU’s energy efficiency framework, 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 a $0.02 favorable contribution from nuclear driven by the net impact of the nuclear production tax credit, which went into effect on January 1st of this year, partially offset by a 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 2023's 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. Operating and maintenance 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 from a 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 100% 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, PSEG had 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 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 2024, and PSEG Power had $1.25 billion outstanding of a variable rate term loan maturing March 2025. The entirety of these term loans were swapped from a variable rate to a fixed rate, mitigating fluctuations in interest rates as of the end of March. Given our swaps and 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 Power's 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.

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 comment on the potential timing around any potential announcement and then how we should think about when that could contribute to EPS if it were to be achieved? Then just, I know you talked about being in 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 see this as 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 are 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 including some of the hyperscale data centers and their timing. I don't want to speak for them, and I really 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. From an overall timing standpoint, I would just 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 would it really be something that would be post 2025 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 at the 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 all upside, so I understand the attention to it, but what we will do is roll in any Power Purchase Agreements, whether it be on data centers or hydrogen, 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 finalize it and be transparent about it. But right now, our plan as we look forward is to continue projecting 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 PSEG's role in this?

Jeremy, I think 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 will be opportunities across the PJM footprint. You have to just take a look at what happened recently 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 impact 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. 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 a need for additional modifications to the grid and it's to be determined for all of us.

And then just thinking 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 ensuring that this is developed in a way 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 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 are different paths. Those interconnection agreements are the way that that's handled through cost allocations in the PJM market today. So, I think there's a very fair and transparent way that's taken care of. I think each state has a different solution for in front of the meter data centers or loads that are popping up and those states' individual tariffs. Every state will review 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, could you provide 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.

I wish I had a better answer for you, but we continue to wait for guidance to come out of the Treasury. I know there have been various different approaches to the Treasury to try to spur some information to come out. But I know that the PTC began on January 1st, so we are in it. I continue to think that the most important definition is the definition of gross receipts—this is what we're waiting for more than anything else. I think we're moving forward and discovering a bit more about what 2024 looks like every day that goes by, and we continue to do what we've been doing, trying to position ourselves ideally against the backdrop of that uncertainty. I think we're doing fine, but we would prefer to have it clear. I don't have a date for you or an estimated date. I haven't heard that one is forthcoming. So, I think we're still in the same boat. 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 guidance. Is that a fair way to put it, Dan?

Yes, that's exactly right.

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 nuclear side. I know that's going to be capital light, but generally speaking at the utility, whether it's energy efficiency or the transmission opportunity, just can you give us a sense of how much more capital can the balance sheet cover without issuing any equity?

Yes, we've talked about that it’s going to come off of the FFO to debt. When you did see that increase in capital that you referenced, there are different FFO to debt implications depending on the exact nature of the capital. Energy efficiency program investments have a recoverable, depreciable, or amortizable life, closer to 10 to 12 years, while infrastructure-oriented investments have a longer recoverable life. You’ll see less impact on your FFO to debt for those infrastructure investments because you're going to see a lot of cash coming back to you quicker. To the extent that it's energy efficiency benefits, that's something more steel on the ground, whether it's on the transmission side or electric or gas side. I do agree that the power side would be capital light, but could be favorable to FFO. We're mid-teens, our current threshold for where we are is 13-14, depending on whether you're talking about Moody's and S&P. So, we've got some room, but it’s going to depend a bit on the nature of the investment, and as you saw more of that increase coming from energy efficiency lately, it was more credit-friendly for us.

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

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 one-off as you look at it? Is there a level of potential grid dependence and do you see that becoming a concern for regulators or is that kind of getting addressed in other forms?

The grid dependence, Constantine, I think is not just for data centers. We're seeing electrification across the board; as policymakers continue to move in that direction, we must be aware and ensure that the system is being built out correctly. I think it's being handled on multiple fronts, including at FERC and at each individual state. There are plenty of avenues for conversations that take place to minimize the burden to customers. For the scalable side, there's a lot of work being done by Dan's team on the commercial front, and I let him elaborate on that.

It's a great question. By definition, if you're going to do something behind the meter, you're going to do it at scale. It's likely we'd see something that would be agreed upon to upscale and come in over time.

Just to remind everyone, where we sit geographically is a great spot, but I also point out that we are the only merchant site that has three units on it, so the ability to scale there is a little different and the ability to back up the supply is also different. We're really excited about whatever opportunities might come down the road because of that.

As we look more broadly at supply and demand in power markets, power prices are now well north of the PTC levels that continued to be 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?

If there's a change in how we look at things and what's in place for a period for us to speak about it, that's a logical time for us to do so. You've seen these markets for a long time, they come up and down and they're cyclical. When they are higher, our intention is to be more predictable and let investors know what they can count on, but I won’t embed it until it's real. We're trying to maintain grounding.

Just a reminder, the highly visible and liquid PJM West top is not necessarily reflective of the entire PJM marketplace. So those numbers aren't accurate for everyone.

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 the scope of what's getting done and how much will be left in order to make that shift as we get to 2025?

It's a very small piece of the puzzle that's going on now. There's a lot of engineering work underway. There's work being done on rewinding the generator, along with an upgrade—we're basically cleaning out some old insulation on the cooling tower, which provides us about 8 megawatts of additional capability. These are small steps but really help us based on weather conditions and the rates that are required. Optimizing the unit itself in anticipation of that fuel change will take place over the next couple of fuel cycles, and then we'll be ready for the ultimate change to the 24-month cycle.

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

Yes, Carly, we may see it move a little bit higher. We talked about the winter earlier; it was a mild winter, but with significant precipitation events. That drove costs a bit higher, as did any time we have a Hope Creek outage. It's 100% owned, so there’s a bigger impact there. You'll see that come through on the power side. 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. Can you maybe pin this 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?

You can look at what happened at Talend as a placeholder for the size of the units at hyperscalers are considering. Just a reminder, our state plan ends in May of 2025, so I don't expect a data center to be operational before May of 25 down at that site. We may be in discussions with firms looking for power sooner than that, but I don't foresee any power flowing into a data center before May of 25 when that program ends. We'll see what the rules are regarding the IRA and how the PTCs interact with any agreements that are reached.

But your expectation is that the entire portfolio is available?

Yes, I think the entire portfolio could be available for long-term contracts. However, that falls into multiple different scenarios. I don’t see anything that would be a restriction and we'll continue to work forward and keep you posted.

Just wanted to pivot to the energy efficiency side of the utility. The two programs you filed in December call for $3.1 billion of spending, which is much larger than the first program at about $1 billion. Can you talk about some of those dynamics of why each incremental kilowatt-hour of savings is so much more expensive? Are you seeing any pushback from the BPU or key stakeholders, or is this all well understood and supported?

It's simple as to why the dollar per megawatt saved goes up. You're moving from changing light bulbs to now upgrading HVAC units and doing work in commercial and industrial operations. That's significantly different in terms of dollar per megawatt hour saved. As far as the pushback, this was all part of the BPU's triennial process, so much of what was submitted was based upon the needs identified by the Board of Public Utilities. The total spend will be the only question on how far they’d like to go. Previous performance has been really good, so I don't expect much argument about the cost per megawatt based on the type of work we'll be doing going forward. Also, the BPU has strategically targeted things through this program that they view would not happen otherwise.

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

Sorry, another nuclear question. We've discussed this conceptually over the last several months regarding hydrogen, and I believe there's plans for a potential offshore wind port next to the plants. Should we consider these as all viable potential activities in that area, or should we focus on just one, as data centers are now kind of top of the list?

No, Steve, it's a great question. The port is built. The New Jersey Economic Development Authority has done a lot of work down there. I don’t know if we can pull a ship up there yet, but we're getting close. A lot of activities have been completed. They’ve already begun leasing space to offshore wind developers. There’s additional land available for data centers. You could also have a hydrogen unit or an electrolyzer there. It all depends on the rules that come out and what we finally see from IRA implementation. We're thinking about it as an optimization strategy to determine the best way to use that electricity while aligning with state policy. 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 opportunities becomes.

On the hydrogen front, an upgrade there would meet both additionality and hourly matching if those limitations continue on hydrogen. I do think we feel good about what we have the ability to do without seeing limitations on needing to pick one opportunity over another.

The reliability in New Jersey is generally good. We have prepared well for challenges. I'm confident that we're in a solid position, and the margins aren't quite as tight compared to other areas. We're looking at the best solutions for the state as part of our collaboration with state plans.

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

I have a couple more questions regarding nuclear. In terms of the duration of contracts your counterparties may be willing to sign, can you share any color on how long term you view this? Additionally, to the extent that there are transmission constraints in PJM, how does that investment timeline play into the ability to serve those longer terms?

The straightforward answer is—if somebody’s going to come in and build a data center, it'll involve significant investment and it's going to be around for a long time. While I don't have a specific number of years to provide, I think long term is best viewed broadly.

The transmission system has also been built out quite robustly, given experiences from events like the 2003 blackout. We are well prepared for whatever flows need to happen within the region. Both aspects are in pretty good shape.

To follow on from the last line of questioning, are there policy opportunities to potentially attract this customer base to the state? Are there any legislative initiatives that you're keeping an eye on that may make it more appealing for stakeholders to draw this load to the service territory?

The state has multiple solutions to welcome new businesses or startups to New Jersey. Several initiatives at the EDA can attract businesses, and I don't think anything I've seen requires more legislative changes. There may be some measures to accelerate opportunities for businesses, but I'm confident that the state has the necessary tools to reach out to potential opportunities.

Our last question is 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. Just thinking about what a contract at a very high level might look like for a co-located facility. Primarily, who would bear the risk of potential non-performance—would that be your responsibility, or will we likely look to the offtaker to take that risk?

It's too early to talk about details of discussions. We're not at a point where we can discuss specifics now. We don't want to get into the commodity risk situation. Our approach is simple; we put a meter at point A, and the customers can take it from there. Data centers or electrolyzers—anything else in that space is viewed similarly.

From a practical standpoint, with a three-unit site, there's extensive redundancy to deal with those challenges. Contractual terms will undoubtedly be worked through across the entire agreement spectrum, but we start from a position of strength.

Regarding the transmission in your bids and proposals, how much do those depend on a second round of offshore wind projects? Is any of it or some of it?

The interest pre-build opportunity does not require that. It's similar to what happened in the first solicitation where we use an analogy. It's about the infrastructure for energy coming from the offshore wind farms. That piece really isn't dependent, but the size and scope of the next solicitation is clearly dependent upon how big that offshore wind opportunity gets for the state as a whole. We have not seen a clear scope on that yet.

Would that go through the PJM process or through New Jersey?

It would be a PJM process initiated by the state agreement approach from New Jersey. So, New Jersey would engage PJM and ask them to run the process on behalf of the state.

I would like your thoughts on the upcoming transmission policy agenda from FERC in the coming weeks. What might come out from there and how it may affect PSEG?

There are several critical items on the agenda. Some of our people heavily involved in transmission are watching those closely. I don't expect wild swings, given the balanced approach from FERC under the current chair, but we will monitor it diligently.

Regarding the push for grid-enhancing technologies, how might that impact operations in the coming years?

Grid-enhancing technologies have been focused on upgrades of some of the conductors. We've piloted some initiatives and have done substantial transmission upgrades built into our system to facilitate additional improvements. It'll ultimately become a cost-benefit evaluation for the consumer based on what capacity we would gain and necessary actions taken to front-run demand. So, we'll closely watch opportunities, and PJM will prioritize these for addressing any gaps as we move forward.

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

I simply want to thank you all for your continued confidence and support. We welcome all these questions and 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 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.