Q3 2024 Public Service Enterprise Group Inc Earnings Call

Daniel Cregg

Thank you, Ralph. Good morning, everybody. As Ralph mentioned earlier, PCG reported net income of $1.04 per share for the third quarter of 2024, and compared to $0.27 per share in 2023. Non-GAAP operating earnings were $0.90 per share in the third quarter of 2024 compared to $0.85 per share in 2023.
Slides 7 and 9 detail the contribution to non-GAAP operating earnings per share by business segment for the third quarter and first nine months of 2024.
Slides 8 and 10 contain waterfall charts that take you through the net changes for the quarter-over-quarter and nine month periods and non-GAAP operating earnings per share by major business.
Starting with PSE&G, which reported third quarter net income and non-GAAP operating earnings of $0.76 per share for 2024 compared to $0.80 per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth in rate base from higher regulated investments that was more than offset by a higher investment-related depreciation and interest expense in advance of the October rate effective date of our distribution rate case approval.
Compared to the third quarter of 2023, transmission margin was flat due to higher recovery of investment offset by the timing of a formula rate true-up. Energy Efficiency margin was $0.01 per share favorable on higher investment and distribution margin increased by $0.06 per share. Split between Energy Strong 2 and the Infrastructure Advancement Program or IAP recoveries and the absence of storm cost and amortization from a year ago.
Distribution O&M expense was $0.04 per share unfavorable compared to the third quarter of 2023, primarily due to the timing of spending and higher cyber and IT spend. Depreciation and interest expense rose by $0.01 per share and $0.03 per share, respectively, compared to the third quarter of 2023, reflecting continued growth in investment and higher interest expense.
Lower pension and OPEB income resulting from the cessation of OPEB-related credits, which ended in 2023, resulted in a $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 $0.02 per share in the quarter compared to 2023.
Weather during the third quarter, as measured by the temperature humidity index was 5% warmer than normal, but 5% cooler than the third quarter of 2023. And just as a reminder, weather variations have minimal impact on 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, by electric and gas margins, while helping PSE&G promote the adoption of its energy efficiency programs. The number of electric and gas customers, which is the driver of margin under the CIP mechanism, continued to grow by approximately 1% each over the past year.
On capital spending, PSE&G invested approximately $1 billion during the third quarter, bringing year-to-date spend to $2.7 billion. For the full year 2024, our capital spend is expected to total $3.5 billion, slightly higher than our original plan of $3.4 billion.
Based on the continued execution of our electric system reliability programs, including Energy Strong and last mile spend in the IAP, our ongoing gas infrastructure replacement spending as well as our energy efficiency programs. We are reaffirming our 2024 to 2028 regulated capital investment plan of $18 billion to $21 billion as well as our rate base CAGR over the same period of 6% to 7.5%.
Moving to PSEG Power and Other. For the third quarter 2024. PSEG Power and other reported net income of $0.28 per share compared to a net loss of $0.53 per share for the third quarter of 2023. The non-GAAP operating earnings were $0.14 per share for the third quarter of 2024 compared to non-GAAP operating earnings of $0.05 per share for the third quarter of 2023.
For the third quarter of 2024, net energy margin rose by $0.16 per share, driven by higher recontracting prices at nuclear which includes the net impact of the Nuclear PTC that took effect January 1, 2024.
As a reminder, for 2024, we mentioned that we anticipated realizing a significant portion of the increase in the 2024 gross margin over 2023’s gross margin during the second half of the year based upon the shape of our underlying hedges.
This differs from last year when PSEG Power realized most of the step-up in the annual hedge price in the first quarter of 2023. O&M was $0.03 per share unfavorable mostly driven by higher costs from the peach bottom units and the absence of a onetime benefit last year. Interest expense was $0.04 per share higher, reflecting incremental debt at higher interest rates. And taxes and other were $0.01 per share favorable compared to the third quarter 2023.
On the operating side, the nuclear fleet produced approximately 8.1 terawatt hours during the third quarter of 2024 in line with the year earlier period and ran at a capacity factor of 94.5%. Touching on some recent financing activity. As of the end of September, PSEG had total available liquidity of $3.4 billion, including $200 million of cash on hand.
Through September 30, 2024, cash from operations was strong, and our cash collateral balance was below $200 million, supporting our strong liquidity position. PSEG’s variable rate debt at the end of September consisted of a $1.25 billion term loan maturing March of 2025, the entirety of which has been swapped to a fixed rate, which mitigates fluctuations in interest rates.
As of the end of September, given our swaps, we had minimal variable rate debt. In August, PSE&G issued $1.1 billion of secured medium-term notes or MTNs comprised of $600 million of 4.85% MTNs due August 2034 and $500 million of 5.3% MTNs and due August of 2054. A portion of the proceeds were used to repay the $250 million August 15 maturity of 3.15% MTNs.
Looking ahead, our solid balance sheet supports the execution of PSEG’s five year capital spending program dominated by regulated CapEx without the need to sell new equity or assets and provides the opportunity for consistent and sustainable dividend growth.
In closing, we are narrowing PSEG’s full year 2024 non-GAAP operating earnings guidance to $3.64 a to $3.68 per share from $3.60 to $3.70 per share prior. This update reflects PSEG’s solid results through the first three quarters of 2024 and PSE&G’s new distribution base rates, which took effect October 15. We are also reaffirming our long-term 5% to 7% compound annual growth in non-GAAP operating earnings through 2028, supported by our capital investment programs and the nuclear PTC.
With the rate case and energy efficiency filings now approved, we will look to finalize our annual business planning process, which will position us to update our financial guidance disclosures with our fourth quarter and full year 2024 earnings release.
We will introduce PSEG’s non-GAAP operating earnings guidance for 2025. We will refresh and roll forward our capital investment plans. We will update our rate base and long-term earnings CAGR’s and discuss the details during our year-end call in February of 2025.
That concludes our formal remarks, and we are ready to begin the question-and-answer session.

Operator

Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community. (Operator Instructions)
Shahr Pourreza, Guggenheim Partners.

Shahriar Pourreza

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

Ralph LaRossa

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

Shahriar Pourreza

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

Ralph LaRossa

Yes. Sure. Again, it’s been 72 hours or so since that all came out. Look, I think I think there’s a number of different paths where we can see an ultimate solution come out. But for our specific scenario, I stick to what I said a couple of minutes ago, you could — look, you could see somebody in that proceeding, asking for rehearing and trying to get a different solution there. You could see something coming out of the federal — I mean not the federal, the technical conference and what they have going on.
You could see something coming out as a 205 proceeding that Exelon has or you could see somebody put together an interconnection agreement that is a little different than the one it exists and comes out with a solution that the FERC supports. So any of those scenarios are possible. And I just think we’re that focused on support in the state of New Jersey’s economic development goals.

Shahriar Pourreza

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

Ralph LaRossa

Yes. So if that was misunderstood or I misspoke, but we always have said in our conversations that we would like to get this done during this governor’s term. He turns out at the end of next year. Obviously, there’ll be an election in November and different policies will be discussed. But we’ve been focused on that time line since we’ve started the discussions. (multiple speakers) initiatives and supporting those initiatives would make a ton of sense for us.

Operator

Nicholas Campanella, Barclays.

Nicholas Campanella

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

Ralph LaRossa

Yes, sure. I’ll let Dan give you some details there.

Daniel Cregg

Yes. Nick, I’m not going to give a ’25 or any particular year’s guidance as we step forward. I think that range is where we are. I do think, to your point, you’re looking at elements that will come into play. We had assumed all along we would see the result of this rate case in the second half of the year.
So the kind of the timing is as expected and one of the key elements that we look at for that rate case was being able to fully recover the capital that we have prudently deployed during that period. And that was also where the rate case came out. So I think we got a good outcome, and I think it was where we expected it to be. But that’s been baked into how we’ve been thinking about where we’re going.
To your point, I do think on capacity it’s unfortunate that we do have a delay, but we will continue to step through those actions as we go through time. There’s a little bit of a balancing for those auctions. If you think about the auctions may go up and down they do split years, right, Nick. So you’ve got a kind of a June to May time frame.
And so to the extent that you see some ups and downs throughout where those actions may go, you will see a moderating effect on the year-over-year results that we see. So I think if you just think about that range of 5% to 7% that we’ve given you’ve been in pretty good shape as you step through the time frame that we’ve talked about.

Nicholas Campanella

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

Ralph LaRossa

Well, look, so a couple of things there. Let me go back to the capacity auction for a second. And Dan correctly said we’re — we’re sorry to see that the auction didn’t proceed, right? But we’re also happy that PJM is going to take a step back and get that right. So we filed some comments to that effect.
And it was really just based upon getting the reference unit right and figuring out this RMR piece that I would encourage you all to take a look at the — some of the filings that were made around that RMR, 5 that or more complaint that went in. There were some pieces there about brand insurers that might be helpful for people to take a look at.
And then, look, from a pricing standpoint, if you just take a look at the transmission rate that exists within the A service territory. It’s just under $7 a megawatt hour right now. And I think if you step back and look at that full rate on a network service basis and net it, it could really put in context the amount of dollars that we’re talking about here that is at risk in any way, shape or form and how whether it’s made up in the pricing deal or tax breaks or something else, the state of New Jersey could still meet its economic goals.

Operator

Paul Zimbardo, Jefferies.

Paul Zimbardo

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

Daniel Cregg

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

Paul Zimbardo

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

Daniel Cregg

Yes. I mean — so I think as I first start by just if you go backwards, we were successful in Maryland and have a project that’s moving along there. Ralph referenced on the call, in Window 1, we’ve got a proposal sitting in front of PJM that’s kind of comparably sized, which we’ll find out in short order.
I think what you’re going to continue to see, Paul, given the other topic that’s been kicked around and will continue to be on the data centers, more of these opportunities that will come forward. I think we’ll analyze them all. We’ll try to figure out what makes sense for us to move forward on. But I can tell you that we do move forward with some confidence in our ability to do the work and to put in competitive bids to continue to move forward.
The other thing I would say is just as you take a look at the capital program, incremental competitively bid transmission is not in that program. So we don’t need to be able to win some of these competitive programs to be able to hit the capital budget.

Operator

Jeremy Tonet, JPMorgan.

Jeremy Tonet

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

Ralph LaRossa

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

Jeremy Tonet

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

Ralph LaRossa

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

Operator

Durgesh Chopra, Evercore ISI.

Durgesh Chopra

Just Ralph, you kind of went through the tariff implications of the fourth quarter in a lot of detail, thank you for that. Maybe just address grid reliability. I mean that was one of the things that was brought up in the order you just mentioned it, but just maybe a little bit more color as to how do you overcome that. This notion of taking power away from the grid and then giving it to the data center. Any color you can share that would be helpful.

Ralph LaRossa

Yes. So Durgesh, I don’t think we could really state anything there with any sense of certainty right now, right? You’ve got so many different things that are going on with the topology and the grid down in that region. Brand insurers, as an example, it’s a large unit that unit stays on, it will have one impact on the region. If it comes off, it will have another. Where TMI ultimately connects into the grid in that region is going to have another impact on it.
So I began way ahead of our skis if I was to tell you exactly what the grid reliability issues are. I can tell you this from a stability standpoint on our system overall, we have extra capacity here in New Jersey because of the work that we did after the blackout in 2003 and after Superstorm Sandy. But I don’t want to tell you for sure that there won’t be any upgrades that will be needed until I know how a lot of the other generators are going to play out in that part of PJM.

Daniel Cregg

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

Durgesh Chopra

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

Ralph LaRossa

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

Operator

Michael Sullivan, Wolfe Research.

Michael Sullivan

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

Ralph LaRossa

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

Michael Sullivan

Okay. Sure. No worries there. And then maybe separately, just how we think about LIPA and the opportunity, and I guess, risk there will you know enough by your year-end call to decide whether or not you include that in there? What’s just the range of outcomes you’re looking at, whether it be publicly owned or other?

Ralph LaRossa

Yes. So yes, I don’t think they’re going with a publicly owned solution, but we continue to hear is that they’re going to stick with the service provider model. What we have at risk there is $0.07 to $0.08. We’ve been pretty clear about that over the last six months or so. And we should know by the end of the first quarter of next year, I would expect some time in the beginning of the year because that transition needs to take place by the end of ’25.
So maybe we can find out something sooner, but my expectation is by the end of the first quarter, we would we would have a pretty good sense of where we stand with that. And a lot of it depends upon how those — how that contract is written and how aligned it is with some of the LIPA Reform Act goals that were put in place 10, 12 years ago now.

Operator

David Arcaro, Morgan Stanley.

David Arcaro

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

Ralph LaRossa

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

Daniel Cregg

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

David Arcaro

Yes, absolutely. Got it. And yes, I didn’t really maybe appreciate the excess transmission capacity you might have in the state. Is there any way you might be able to quantify that as you think about — I don’t know if it’s a number of megawatts that you could handle without major upgrades? Or yes, some of your peers have talked about that transmission capacity. So just wondering if you have any way to frame that?

Ralph LaRossa

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

Operator

Anthony Crowdell, Mizuho Securities.

Anthony Crowdell

Good morning Ralph, good morning Dan.

Ralph LaRossa

Welcome the hockey season.

Anthony Crowdell

Welcome the hockey season. The weather is right and my voice is a little horse. Have a kit of my UA team, Ralph, who’s also named Ralph and he’s a little extra attention. I don’t know if it’s the name. But just quickly, off of Mike Sullivan’s question, I mean, the LIPA contract, again, $0.07 to $0.08, it’s not incremental instrumental to PSEG’s earnings, but do you think that’s going to be more competitive this go around, given how successful it’s worked for you for the last, whatever, 10 years.

Ralph LaRossa

Yes. I don’t want to — any reaction to that could be read as being a little bit too arrogant on the issue. I think we’ve done a great job. We’re very proud of the work that we’ve done there from a safety standpoint, from a reliability standpoint and from a customer satisfaction standpoint. So we’ve done all of that. We’ve met our — all of our commitments and prices have remained from an affordability standpoint, where the expectations were. So I think we have a very good story to tell. I just want to make sure that our story meets the needs of LIPA as they look forward.

Anthony Crowdell

Great. And apologies if you’ve answered this already, just on the potential upgraded sale, have you guys quantified the cost of that and how many megawatts you think out of it?

Ralph LaRossa

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

Operator

Paul Freeman, Glenrock Associates.

Paul Fremont

Congratulations. I just wanted to maybe get a little bit more detail on the CoreWeave’s lease. Has — has there been any determination in terms of who’s going to power that facility and how many megawatts are going to be needed to power the facility?

Ralph LaRossa

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

Paul Fremont

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

Ralph LaRossa

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

Paul Fremont

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

Ralph LaRossa

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

Paul Fremont

And then lastly, in terms of the — in terms of the PTCs, is there a final interpretation out by the DOE in terms of how they’re going to account for the PTCs and market price?

Ralph LaRossa

I will give that one to Dan.

Daniel Cregg

Yes. We’re still waiting on rigs from Treasury, the exact definition of gross receipts, Paul. So the answer is no.

Paul Fremont

So for accounting purposes, how are you handling it?

Daniel Cregg

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

Operator

Carly Davenport, Goldman Sachs.

Carly Davenport

Maybe I just wanted to start on the nuclear fuel side. I think you’ve updated the commentary that you’re now essentially covered through 2027. Just as we think about some of the capacity addition announcements that are — we’re starting to see in, call it, 2028-plus, is this time frame of sort of contracting out two to three years the way that you plan to manage your fuel purchases going forward? Or just any thoughts on how you’re thinking about that would be helpful.

Daniel Cregg

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

Carly Davenport

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

Daniel Cregg

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

Operator

Paul Patterson, Glenrock Associates.

Paul Patterson

Just sort of the follow-up on the co-location issue. If I was to understand the commentary and everything, it sounds like the tax issue is pretty much resolved by the state of New Jersey offering tax breaks, et cetera. And that’s just the $7 of transmission cost that in theory would be in play or a portion of that associated with locating with being behind the meter in New Jersey. Is that the way to think about it?

Ralph LaRossa

That is the way to think about it.

Paul Patterson

Okay. And then do you have any — do you know why the two commissioners declined to participate in the order?

Ralph LaRossa

Yes. No, we just know that they recuse themselves, so I’d have to refer you back to FERC on that one.

Paul Patterson

Okay. And then finally, as I’m sure you’re aware that the OPS, which NJ BPU is part of has been making letters back and forth with PJM correspondence and [P3s] has been responding and what have you about their concerns about the capacity market and the prices. I know you guys are very focused on affordability as you guys outlined today as well. Just how do you think — I mean, with the history of LCAP and everything else?
And it seems like we’re maybe getting to a market situation, which we don’t see a lot of new generation showing up at least by kind of generation and these high prices, how should we think about this apprehension that’s being — voiced by state regulators and by consumers and what have you, how do you — when you see that, what kind of thoughts go through your mind, I guess, if you follow what I’m saying.

Ralph LaRossa

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

Operator

There are no further questions at this time. And I’d like to turn the floor back over to management for closing remarks.

Ralph LaRossa

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

Operator

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