公共服務電力與天然氣 (PEG) 2022 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Rob, and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's Third Quarter 2022 Earnings Conference Call and Webcast. (Operator Instructions) As a reminder, this conference is being recorded today, October 31, 2022, and will be available for replay as an audio webcast on PSEG's Investor Relations website at https://investor.pseg.com.

I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Thank you, Rob. Welcome to PSEG's Third Quarter 2022 Earnings Presentation. Joining us on the call today are Ralph LaRossa, President and Chief Executive Officer of PSEG; and Dan Cregg, Executive Vice President and Chief Financial Officer.

Our press release, attachments and slides for the discussion today are posted on our website, and our 10-Q will be filed shortly. The 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 or loss 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 Ralph and Dan's prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph.

Thank you, Carlotta, and thank you all for joining us today.

As you may know, this is my first earnings call since becoming CEO in September. And if you've met with us over the past few months, you've heard me lay out my initial action plan for PSEG to deliver value to our investors. The focus is clear and simple: continue to grow the company through investments with appropriate risk-adjusted returns and increase the predictability of our business by reducing the variability in both financial and operating results.

PSEG has a solid utility operation, a constructive regulatory and policy environment, and now a federal tax incentive for our nuclear fleet that stabilizes its cash flows for a decade. Together, these attributes make PSEG a compelling investment.

Earlier today, we reported net income of $0.22 per share for the third quarter of 2022 compared to a net loss of $3.10 per share in the third quarter of 2021 that was related to the announced sale of our fossil assets. We also reported non-GAAP operating earnings of $0.86 per share for this third quarter compared to $0.98 per share in the third quarter of 2021. Results for the 9 months ended September 30 of $2.83 per share places squarely within our guidance range. So we are narrowing our 2022 non-GAAP operating earnings guidance of $3.40 to $3.50 per share, assuming normal operations over the remaining 2 months of 2022.

We remain highly confident in the growth potential of our regulated investments and are committed to the cost discipline needed to minimize the impact of current economic conditions. We also reaffirm our 5% to 7% multiyear EPS CAGR to 2025 with the understanding that this CAGR is nonlinear and we fully intend to deliver on our earnings guidance expectations as we've done for the last 17 years and counting.

PSE&G's investments in transmission and distribution infrastructure continue to produce rate base growth consistent with our long-term expectations. Our new infrastructure advancement program, which launches investment in a critical last mile of our distribution system, and the clean energy future investments are also supporting wide-ranging decarbonization priorities, driven by our programs to expand energy efficiency, electric vehicles, solar investments, and create clean energy jobs and training opportunities.

Now turning to our offshore wind ventures. We are approaching a final investment decision on Ocean Wind 1 in New Jersey to determine if we will proceed to the construction phase. We are reviewing our options related to our 25% equity investment in Ocean Wind 1 as well as our option to purchase 50% of Ørsted Skipjack 2 project and options regarding PSEG's interest in the remaining Garden State offshore energy lease area.

Last week, the BPU completed its review of offshore wind transmission competitive proposals and awarded several onshore-only projects. PSE&G was awarded 50 -- sorry, $40 million of system upgrade work needed to accommodate the injection of offshore wind generation in Central New Jersey. However, the BPU also indicated that will consider an additional solicitation to address the state's increased offshore wind generation targets. We remain optimistic that our emphasis on reliability and resiliency will keep it as a strong contender for any future offshore transmission solicitations to bring regional offshore wind projects onshore.

Our energy strong investments in the aftermath of Sandy lifted and hardened PSE&G substations against future storms. With similar foresight, the BPU has recognized for the infrastructure advancement program that attention is needed to address that last mile of our distribution system and proactively replace critical components in advance of electrification.

Safe and reliable operations will always be the core of our customer-focused mindset. This is the focus our team of over 12,000 dedicated employees as every day in providing safe and reliable service to over 3 million customers in New Jersey and Long Island. As a result of these efforts, I'm pleased to report that both PSE&G, our nuclear operations are trending at above top quartile metrics on several key measures. In addition, PSE&G continues to receive some of its highest ever customer satisfaction ratings from J.D. Power.

The 2022 hurricane season has been relatively quiet in New Jersey and Long Island, which enabled PSE&G to send mutual aid to Florida to assist with Hurricane Ian restoration. Our thoughts and prayers in addition to our support went out to all those impacted by Ian. I mentioned this cooperation because it is unique in our industry, and we all benefit from it. On this 10-year anniversary of Super Storm Sandy, we remain acutely aware of how a single powerful storm rolling up the Atlantic Coast can permanently affect lives, destroy homes, businesses and livelihoods for extended periods of time, and we remember how grateful we were for the support we received then.

I'm also proud to announce that MSCI has raised PSEG's corporate environmental, social and governance ratings to AAA from AA, placing us at its highest rating. PSEG has also improved its score within the top tier of the 2022 CPA Zicklin Index of corporate political disclosure and accountability.

I have met and listened intently to many of you these past few months, and I recognize the importance of maintaining our financial strength, preserving our ability to grow without needing to dilute our existing shareholder base and rewarding our shareholders with a compelling common dividend yield. As we approach several critical decisions in the weeks and months ahead, I won't be guided by the approach that I mentioned at the very beginning, prioritizing predictability and increasing shareholder returns.

I look forward to meeting with many of you at the EEI financial conference over November 13 through November 15 where we'll announce PSEG's 2023 full year earnings guidance, provide more detail around our estimate of pension impact on 2023 financials as well as a longer-term EPS growth rate.

I'll now turn the call over to Dan, who will provide you with the financial review and outlook.

Thanks, Ralph. Good morning, everybody.

As Ralph mentioned, for the third quarter 2022, PSEG reported net income of $0.22 per share and non-GAAP operating earnings of $0.86 per share. We provided you with information on Slides 8 and 10 regarding the contribution to non-GAAP operating earnings by business for the third quarter and year-to-date periods ended September 30.

Slides 9 and 11 contain waterfall charts that take you through the net changes quarter-over-quarter and year-to-date for 2022 and 2021 and non-GAAP operating earnings by major business. I'll now discuss results starting with PSE&G.

PSE&G's results were $0.03 higher compared to the third quarter of 2021 driven by continued capital investments in transmission distribution and clean energy. Compared to the third quarter of 2021, transmission margin was flat as growth in rate base of $0.02 per share was offset by the combination of the August 2021 formula rate settlement, which included a lower return on equity and the timing of O&M expense versus recovery.

For distribution, electric margin was $0.02 favorable compared to the third quarter of 2021, driven by investments in Energy Strong II and the impact of the conservation incentive program or CIP mechanism. Gas margin improved by $0.01 per share over the third quarter of 2021, reflecting recoveries of our gas system modernization to investments and other margin primarily related to our appliance service business, also added $0.01 per share compared with the third quarter of 2021.

O&M expense was $0.01 per share unfavorable compared with the third quarter of 2021 and interest expense was $0.01 per share unfavorable reflecting higher investment. Flow-through taxes and other items had a net unfavorable impact of $0.01 per share compared to the third quarter of 2021 driven by the use of an annual effective tax rate. For the year-to-date, unfavorable flow-through taxes of $0.07 per share year-over-year will reverse in the fourth quarter of 2022.

Lower shares outstanding had a $0.01 per share benefit on third quarter 2022 results versus the year-earlier quarter, reflecting the impact of the completed $500 million share repurchase program. And in addition, nonoperating pension expense was $0.01 per share favorable compared with the third quarter of 2021.

Weather during the third quarter as measured by the Temperature-Humidity Index or THI was 19% warmer than normal but similar to conditions during the third quarter of 2021. With the CIP in effect variations in weather, both positive and negative, have a limited impact on electric and gas margins while enabling the widespread adoption of PSE&G's energy efficiency programs.

PSE&G's system peak load exceeded 10,000 megawatts for a second summer in a row on August 9. And growth in the number of electric and gas customers has continued to track at approximately 1% for the trailing 12-month period ended September 30.

Regarding our capital spending program, PSE&G invested approximately $795 million during the third quarter and $2.2 billion year-to-date through September 30. PSE&G now expects a revised capital spending forecast of $3 billion for 2022, up from the planned 2022 capital program of $2.9 billion. The 2022 capital spending program includes transmission investment, the continued rollout of the Gas System Monetization II program, Energy Strong II and Clean Energy Future investments as well as the Infrastructure Advancement Program focused on our distribution systems last mile.

On the regulatory front, in September of 2022, PSE&G filed a petition with the BPU requesting an accounting order with an effective date of January 1 of 2023 to authorize PSE&G to modify its method for calculating pension expense for ratemaking purposes, which will partly reduce future variability and pension expense. Also in September, PSE&G filed a petition with the BPU requesting a $320 million 9-month extension of its Clean Energy Future energy efficiency program, which would serve to align future program timing with the other New Jersey electric and gas utilities.

And in October, PSE&G filed its annual transmission formula rate update with FERC, which increases its annual transmission revenue requirement by $69 million effective January 1, 2023.

Now turning to carbon-free infrastructure and other, which reported a net loss of $285 million or $0.58 per share in the third quarter of 2022 compared with a net loss of $1.953 billion or $3.87 per share in the third quarter, impacted by the fossil sale process. Non-GAAP operating earnings were $0.15 per share lower in the third quarter of 2021 driven by lower margin related to the fossil divestiture, lower capacity prices for the remaining nuclear fleet and recontracting at lower prices.

For the third quarter of 2022 electric gross margin declined by $0.29 per share, which includes recontracting approximately 8 terawatt hours of nuclear generation at a $3 per megawatt hour lower average price. In addition, higher off-system sales of gas operations from heightened commodity volatility added $0.01 per share to total gross margin versus the third quarter of '21, with customers also benefiting from a long-standing sharing mechanism in place.

Cost comparisons for the third quarter 2022 improved by $0.09 per share from the year earlier period, driven by lower O&M, depreciation and interest expense related to the fossil divestiture. Taxes and other were $0.04 per share favorable versus the third quarter of 2021. During '21, the Solar Source sale was reflected in June. Cessation of fossil depreciation began in August onward as the assets were held for sale. And the retirement of PSEG Power's outstanding debt occurred in October. And accordingly, the majority of the favorable cost comparisons related to the fossil divestiture occurred in the first half of 2022.

Nuclear generating output declined slightly to approximately 8 terawatt hours in the third quarter of 2022, reflecting the ramp down of Hope Creek and Peach Bottom 2 into their fourth quarter refueling outages. The capacity factor of the nuclear fleet for the year-to-date period through September 30 was 94.3%. PSEG forecasts generation output of approximately 7 terawatt hours for the fourth quarter of 2022 and has hedged approximately 95% to 100% of this production at an average price of $27 a megawatt hour.

For '23, PSEG is forecasting a nuclear baseload output of 30 to 32 terawatt hours and is hedged 95% to 100% of this output at an average price of $30 a megawatt hour. For 2024, PSEG is forecasting nuclear baseload output of 29 to 31 terawatt hours and is hedged 55% to 60% of this output at an average price of $32 a megawatt hour.

As of September 30, 2022, our total available credit capacity was $3.4 billion, including $1 billion at PSE&G. PSEG Power had net cash collateral postings of $2.2 billion at September 30 related to out-of-the-money positions as a result of higher energy prices, and that amount was $1.7 billion through last Friday. The majority of this collateral relates to hedges in place through the end of '23 and is expected to be returned as PSEG Power satisfies its obligations under those contracts or if market prices decline in the interim.

In July of 2022, PSEG repaid a $1.25 billion short-term loan that was due in August. Following the repayment of this term loan, PSEG had outstanding a total of $2 billion of 364-day term loans expiring April, May of 2023 to support power collateral needs. And PSEG Power had outstanding a $1.25 billion term loan expiring March of 25. Combined, these term loans comprise $3.25 billion of variable rate debt. And during September and October, we entered into interest rate swaps from floating to fix for $1.05 billion of our outstanding term loans, reducing variable rate debt exposure.

Moody's recently published updated credit opinions for PSEG, PSE&G and PSEG Power with credit ratings and outlooks remaining unchanged. Regarding the potential headwinds of pension impact on 2023 costs. We continue to monitor several items that will influence the pension calculations when we take the actual measure on December 31. We will assess the net impact of various factors, including the decline in financial markets year-to-date, updating the discount rate and interest component, setting the expected return on plan assets for 2023 and the inclusion of the impact of the petition filed with the BPU earlier this year. We will include an estimate of the impacts of pension on our 2023 earnings guidance, which, as Ralph said, we will provide at EEI.

As Ralph also mentioned earlier, we've narrowed our 2022 non-GAAP operating earnings guidance to $3.40 to $3.50 per share, with regulated operations contributing approximately 90% of the total. For the full year, PSE&G's forecasted 2022 net income is narrowed to $1.545 billion to $1.575 billion, reflecting strong transmission and distribution margin growth in the year-to-date period. 2022 non-GAAP operating earnings for CFIO is now forecasted at $160 million to $180 million reflecting higher interest costs. PSEG 2022 earnings guidance excludes financial results from the divested fossil assets.

That concludes our prepared remarks. So we can now open up the line to begin the question-and-answer session.

Just as a reminder before we go to Q&A. (Operator Instructions) Rob, you can start the queue. Thanks.

(Operator Instructions) Our first question comes from the line of Shar Pourreza with Guggenheim Partners.

Excellent. So again, Ralph, as we're kind of getting closer to year-end and we still see continued turbulence in the market. What are some of the moving pieces around offsetting pension headwinds? Is it your regulatory filing? Is that enough to cushion some of the drag as we're thinking about '23? And is that kind of a contributing factor for the removal of that 5% to 7% language, which I think caused a lot of investor confusion this morning even though you just verbally reiterated. Can you just elaborate on this and kind of what you mean by nonlinear for modeling purposes?

Sure, Shar. So a couple of things. There's -- if you just look at the pension, there were 3 factors that we've been looking to offset the pension impacts and the headwinds from the market that you referenced. One, the filing that we made at the BPU, I think we've talked about that being around 20% or so of the pension impact. We've got the lift out that Dan has been working on. And I'd say that's in the same 20% to 30% range. And then O&M offsets that we've been working on inside the building, which again, we've talked about for quite some time, we're not going to do anything that's shortsighted, but looking for O&M offsets that we possibly can tab that will stay in place even post rate case when we make that filing in '23, which will be effective in '25.

That -- those 3 pieces there together are kind of we're looking at to offset the pension. And then the 5% to 7% to specifically address that, we -- that we always have said is not linear. I think we've talked about that quite a bit on prior calls. So we have a test year in '20 that we're going to be filing in '23 and then we expect rates to be effective in '25. So inherent in that will be an uplift and kind of drives a little bit of what we talked about as being nonlinear.

Got it. But just to reiterate, you have not removed the language around 5% to 7%?

We have not. We are committed to the 5% to 7% through '25.

Perfect. Great. And then just lastly, I guess, Ralph, as we're sort of thinking about your offshore wind segment and sort of the remaining nuclear assets in a sale or retention scenario, we could see some interesting public marks on both fairly soon from some of your Eastern peers. I mean, Ralph, you've been in the helm now for a few months, so you're ready to go. I mean what's your latest thinking here? Are you waiting for public signals to decide what you want to do and where the value is, is the Analyst Day, the right podium to announce any strategic paths, if any? I guess, how are you sort of thinking about the non distribution business as you've taken your seat, right?

Yes. So Shar, I'll split those into 2 pieces, right? First from a wind standpoint, we have been pretty -- and we've mentioned it in my prepared remarks that we're looking at FID on Ocean Wind 1, that's the project in New Jersey. So one of the things we're looking at there is where the costs come in and where we finally -- what that project looks like from an investment standpoint, that's pretty straightforward.

And then for our Skipjack and other projects, we're certainly looking at what might be out there from a mark, as you said, whether it's from some of our peers or for some other entities. So there's -- I think the offshore wind is pretty straightforward. Transmission, obviously, as we talked about -- again, I'm very happy to see what the BPU did. I might not seem to make a lot of sense when I say that. But the BPU kind of kicking a can and moving that decision later is the right thing to do for the ratepayers in New Jersey.

There's some uncertainty around the tax treatment of the copper that will be in the water. And so I think what they did there made a ton of sense to just focus onshore for the time being. So that kind of ties together everything from an offshore standpoint. Then from a nuclear standpoint, look, it may not be the most popular, but I think, again, you still need more and more time there. There's a lot of details to be worked out in the treasury rates when those are worked out and we see some marks in the marketplace, we should be in a very good position to tell whether or not, as my predecessor Ralph Izzo said multiple times, there's -- whether or not we're the natural owners.

Got it. Perfect. Congrats, Ralph, on your first earnings call, and we'll see you guys in a couple of weeks.

Looking forward to it, too, Shar.

Our next question is from the line of David Arcaro with Morgan Stanley.

Maybe on the pension first, do you think you can clarify or give a little bit more color around the lift-out approach that you mentioned could be pursued for a portion of the pension. And I was just curious if there are any other regulatory approaches that could be pursued as kind of a follow-on to what you've already requested with the BPO?

Yes. So Dan is going to give you more in a lift out. Just the other obvious regulatory solution we could is when we filed for the rate cases to put in a pension tracker. And at this point, we fully expect to be doing that in our rate filing. But I'll give Dan the mic to talk a little more about the lift out.

Yes. And David, really, there's -- I think the easiest way to think about that is just if the pension is giving us some variability within results, then having it be smaller would give us less variability. And in that same vein, we continue to have a pension that is well funded. Yet we have seen assets decline as I think every pension fund in the country have, but we've also seen discount rates come down. And as they come down in parallel, the fund stays pretty well funded.

But you can do a lift out, which essentially would be taking some of the assets and taking some of the obligations and moving them to an appropriate creditworthy entity and have that be housed elsewhere. And it just essentially would shrink the size of the pension, we are beginning down a path of that exploration. And I think to the extent that we find that to be a successful way to go, we would inform you at that time, but it's also would have the effect of just basically shrinking the overall pension and therefore, the overall variability of it. So I think that's the way to think about it, and we'll continue to keep you posted as we continue to go down that path.

Okay. Got it. Great. That's helpful. And then, Ralph, you mentioned a little bit on the offshore wind transmission opportunity, but I was just curious given maybe what you saw with the BPU's decisions and elections within this first solicitation and how the other bidders approached it. Any thoughts on how you might look at future opportunities, whether you still think you can be competitive and how you might respond in terms of setting up other future project designs for solicitations?

Sure. So the selection that the BPU made was, again, focused onshore, right? And I'd like to just think about the state, North Central and South, the southern part of New Jersey has a lot of, what I'll call, takeaway capability already on a transmission system because we had Oyster Creek retire and [Bill England] retire in the southern part of the state. So that onshore transmission system was pretty well set up for -- to take onshore -- offshore generation.

The northern part of the state is also has a pretty robust transmission system because a lot of the work that we've done at PSEG over the past 10 years, 15 years after we started to get approval from projects after the 2003 blackout. So then that kind of left the central part of the state. And that project that was approved for JCP&L is -- at Larrabee Substation and again, very consistent with the need to have to take more takeaway ability from the shoreline into New Jersey.

So not a lot of learned from that. That was all the information that we had and we would have expected to be in place. I think what we've all learned, both us and our competitors, is what others are thinking about and how they're both from a financial standpoint, but also from an engineering standpoint, how they were going to design the offshore grid. We think our mesh network is absolutely the most resilient and most robust. We're very proud of that design, keep the lines in and we're very unique in how we did that.

And for all 11,000 megawatts, I'm absolutely convinced that you need that robust solution to be in place. So I think we'll all learn from each other and the next set of bids will be more robust as a result of that. So looking forward to it. But I am confident that our design is a really good design and will meet the reliability and resiliency the state demands.

Next question is from the line of Julien Dumoulin-Smith with Bank of America.

Looking forward to seeing you guys soon. Just following up on Shar's question here, if I can. Just to break down your expectation for an update versus your reaffirmation of the '22 through '25, 5% to 7%. Is the -- is what you're prepared to disclose in the coming weeks more around rolling that forward here? Are we talking about keeping '22 as the baseline? I know because of this nonlinearity, I think folks going to be very focused on this piece. Or is this about including the nonutility businesses as well within the EPS card? Can you give us a little bit more of a flavor of how you're thinking about that relative to what you just reaffirmed on the call here?

Yes. Well, Julien, I won't front-run what we're going to do in EEI much, but I will tell you that we think about the business is the business we have in front of us at the moment, and we'll look at it from that direction. We'll give you '23 guidance, and then we will extend the guidance beyond that. So that's the way we're thinking about it and the way you should be thinking about it and be prepared for EEI.

Got it. And just to clarify, would that be based off of '23? And then also, are you assuming 2024 here has the PTC in effect versus the hedge in terms of an uplift?

Well, so think about what you just asked me from a PTC and a hedge standpoint, right? That exactly is the core issue that I was raising earlier, which is treasury regs and how that's going to come out, right? So we'll pick one of those and give you some guidance based upon that. And for '22, '23, Julien, you can use '21 as the baseline, right? You have all that data. So whatever CAGR you decide to use going forward, but we'll talk to you about '23 and we'll talk to you about future years.

Got it. Okay. But you feel covered off of using baselines of '21 and '22 still?

You can use '20 or go back to '19, go back and go wherever you want to go, Julien.

I love it. I love it.

We'll give you the CAGR off -- we'll give you the CAGR going forward.

Next question comes from the line of Nicholas Campanella with Credit Suisse.

I just wanted to ask on the hedges. I think your hedge percentages are unchanged for '24. So I guess my question here is just why not do more? Can you just give us an update on your general hedging strategy for the nuclear assets, please?

Yes. And I'm going to ask Dan to give you a little more color on this. But again, I'll point everyone back to the regs that are needed out of treasury and some of the guidance there. So there's -- it's a balance as to how we're going to -- how we're going to be looking at this both from a PTC standpoint, and frankly, our ZEC process and everything in between. So Dan, if you want to give a little more.

Yes. I think, Nick, if you take a look at 2022, 2023, essentially fully hedged for those years and really where there's some open -- is into those years where the PTC comes about. And so Ralph's exactly right, trying to make sure that we understand the backdrop of the PTC is going to be important. I'd say that by the same token, we have seen some decline in markets in the near term, but those declines really have been mostly focused on '22 and '23, and we've seen the back end hold up fairly well.

So we are I'd say, within the same ranges that we've provided. It doesn't mean we're in exactly the same place. But I think keeping an eye on what happens down in treasury and as well as keeping an eye on markets is how we're approaching things as we go forward.

So I guess just on the lift out as it pertains to the pension, I think you said potentially can mitigate 20% to 30% of the impact. Is that something that we should have clarity on by year-end? Or is that something that you're continuing to work through maybe it's more of an Analyst Day item? And then just as I think about transacting on that lift out and the overall contribution to EPS. Is it a headwind, like i.e., a step-down headwind to the 5 to 7 CAGR? Or is it just more onetime in nature and reduces volatility going forward? Just trying to think through like how a decision like that could impact '23 and '24.

Yes. So you're probably somewhere -- I'd say Analyst Day is probably the right approximate time for that. It's going to depend upon how our analysis has gone on for us to give you a little bit more detail about it. And I think that at the highest level, one of the ways to think about what happens from the pension perspective is you determine an estimated return on your assets and you have a discount rate for your liabilities. And those comparisons -- and that gap really determines what you see coming out of it.

So if you assume that you're going to earn north of the discount rate than a smaller pension while having less volatility would also have less of a contribution. We would certainly include that in whatever guidance we were to give. But I think as we've seen interest rates come up, we've seen discount rates come up, there's not a whole lot of daylight between those 2.

So whatever we give you will be based upon our plans at the time and our calculations at the time. And I think it's probably around Analyst Day when we'll be able to firm that up for you.

Yes, that would be my expectation that could be around Analyst Day.

All right. See you in a few weeks, sir.

Next question is from the line of Durgesh Chopra with Evercore ISI.

Just on the pension discussion, can you remind us what the regulated versus nonregulated mix of pension is? Is it still around 80% regulated toward pension?

It's closer to 70%, Durgesh.

Got it. 70%. And so when we think about the lift out, are we thinking -- I'm just trying to see the 20 -- is it -- could you lift out the regulated portion of the pension too? Or is it just the nonregulated portion? I'm just wondering if there's any state opposition or regulatory opposition to lifting out the regulated portion of the pension.

Durgesh, I think it would be premature for us to get into that level of detail at this point. So some work to be done. And again, I think our expectation and try to set for you is that we'll have those kind of details at Analyst Day.

The next question is from the line of Jeremy Tonet with JPMorgan.

Good. Just wanted to start off with offshore wind, if I could here. How do you view offshore risk -- offshore wind risk currently, particularly given some of the high-profile development or other projects that have kind of implied a degradation of returns in this inflationary environment?

Jeremy, I think, look, we're -- these projects are no different from some of the other projects that you've been reading about. But we have been steadfast in that front running our partner who has 75% stake in this. And Ørsted has their call coming up in the future, and I'll let them talk to that level in the detail. But certainly at a very high level. What you've been seeing with others is consistent with what we've been seeing with our projects here.

Got it. That makes sense there. And I was just wondering as it relates to power, if you could walk us through the return of your collateral postings on power hedges. And is it kind of fair to think of these financings as the incremental drag in the current environment? And are there any kind of offsets looking versus that?

Yes. I think if you think about our overall hedging picture at our percent hedge, 2022 is mostly behind us, 2023 is where most of the hedges are. So you would see most of that collateral come back as we go through 2023. And so as that cash comes back to us, frankly, there's 2 ways that it could. You could see market moves, which could move it up or down. But over time, as you deliver on those contracts, you would see that coming back to you.

And so frankly, what that's going to do is it's going to lessen the overall cash needs that we have and ultimately reduce some of those borrowings. And so as that cash comes back, you can almost think about it as just taking out those borrowings over time.

Yes. If you look at the -- I think it's the second to last paragraph in our release, we've dropped from $2.2 billion to $1.7 billion, and that's exactly a reflection of the moves in the market over that time frame that's listed there since the end of September into the end of October. So Dan's explanation is completely aligned with what we have there in that release.

Our next question is from the line of Steve Fleishman with Wolfe Research.

Yes. Ralph, congrats on your first call.

Thank you, Steve. Good to have you on.

I've been looking forward to this for a long time. Yes. So just -- so obviously, you said you're going to give '23 guidance at EEI and then you've reaffirmed the 5% to 7% to '25. Is there -- are you going to give some kind of path of how you go from whatever you give to '23 to get to that end game, 5% to 7% in '25, so we have kind of a view with that?

Yes, absolutely will.

Okay. That would be very helpful. And then secondly, given the pension impact in '23 as well as the kind of going into the rate case test year, is it fair to assume that you maybe are kind of under-earning in 2023 (inaudible) as you probably enter this rate case?

Yes, Steve, I don't usually like to -- if you point to that, but I would not make an assumption one way or the other on that about how we're entering that test year.

Okay. Lastly, just on nuclear, Ralph, you've talked about the kind of better visibility of nuclear, but also trying to kind of reduce volatility. Obviously, at the floor price, super visible and a lot of certainty, but at higher prices, in theory, there is great news, great returns, but more variability. Just any thoughts on how that fits into your framework that you've talked about?

Yes. No, 100%. I think, look, a lot of that gets back to the hedging strategy and what makes sense from a treasury regs standpoint. So I think we need to see that visibility, understand what the potential volatility is down the road and then also look at what growth we potentially have from that business and put all 3 of those pieces together and determine whether or not it fits. And that's -- it's exactly what we've been talking about, and it's not going to happen tomorrow, but we need those regs in place. We need to understand what those growth opportunities are in and we need to see what these marks are.

Growth being stuff like hydrogen, you mean or something else?

You've got -- we've talked a little bit about some growth opportunities that we now have in front of us because the revenue stream is more certain, right? So simple things like fuel cycles. There's a couple of those things that are out there as well that we've mentioned in the past, we would not have pursued based upon a 3-year ZEC cycle. But now with a much longer runway out of the PTC, we have those opportunities in front of us.

Yes. So Steve, I mean, I think implied in your question is you do have that floor, which is helpful from a variability standpoint if you're above it. You're happy to be above it because you had a higher value location. And then the challenge really just is trying to manage whatever variability does happen there. But frankly, that's a -- it's a better place to be, obviously, if you're above that floor, right?

Our next question is from the line of Travis Miller with Morningstar.

When you think back to the offshore winds discussion, if you weren't to go forward with that or if you were to sell out of that, how do you think about capital allocation over the next 4 to 5 years?

Yes. I think, frankly, Travis, it's -- for right now, that is one of the options that's there. I think we've talked a little bit about the other side of offshore wind, which could be some transmission work. And we've referenced that as being somewhere in the $2 billion to $7 billion range for our 50-50 partnership. And so there is still a degree of capital that, I think -- as Ralph alluded to before, with the state's target of 11,000 megawatts, we will still continue to look for whether that solution does make some sense.

Beyond that, predominantly, capital would be going to the utility part of the business. I think there continues to be areas to invest within the utility, and that would be the #1 place where we would deploy capital.

And just again, we're still hopeful on that offshore transmission and a full mesh network. I think there's an opportunity there in addition to the core utility activities. And all of this, though, as we've been kind of teeing up, will come together at the investor conference.

Okay. And I think you answered my second question, but on your update on the opportunity set in terms of dollars for that transmission, the offshore-related transmission, is that the $2 billion to $7 billion?

I mean there's -- yes, again, just based upon the selection that was made by the BPU of -- just focused on the onshore portions of work that was required that a large part of that opportunity set is still in front of us.

Okay. And so that would be both the onshore and the, say, under the sea (inaudible)?

Most of what's needed and most of what we were in our bids were offshore. There's a little piece of onshore that work that could be done up in the northern part of the state, as I kind of laid out earlier kind of think about those 3 doors or entry points into New Jersey for offshore wind. The largest amount of work that was needed was in the central part of the state, in that Jersey Central Power & Light territory, but a little bit for us up in the North, if that entry point is selected.

Our next question is from the line of Paul Patterson with Glenrock Associates.

So just -- I apologize if I missed it, but the BPU order on the pension accounting, when are you expecting them to act on that?

Yes. We -- our petition had requested a response by year-end. We have some discovery and so that there's activity that has gone on, on it, but they will act on their own time. But our request was to see if we could get that in place by year-end. And probably, as importantly, to have it be effective year-end. So there's potential if we get something modestly after that, that it could still be effective as of year-end, but that was the anticipation. And that's where things stand.

Okay. And then on the wind, given what you're saying about the economics and how they might be similar to others, how should we think about FID sort of the steps that we should be looking out for here in terms of the potential for asking for a change in the contract? Or would there actually be rebidding? Or should we think about -- I mean, just sort of how should we think about the time line associated with your review process and the FID thing, given the changed economics?

Yes. So Paul, again, our FID decision is our decision to invest in the joint venture. The joint ventures decision as to whether or not they want to talk to the state or customers or however they want to do that, that's with the joint venture. And I leave that to our partners that are set to talk about if they so choose.

Okay. But I guess what I'm wondering is it would seem to me that your decision would be dependent upon the JV's actions in the response to the JV's actions. Do you follow what I'm saying? (inaudible)

I follow but it also might be independent, right? And that's the point I wanted to make to you. We could go in either direction. And they're not dependent upon each other, whether it's changes in the revenue or changes in the expenses. One of those things could impact our decision, but I would also tell you that they may not so...

Okay. And then just what's the timing that we should think about with respect to the FID decision?

Yes. There's no set time and we've talked about that on a number of prior calls. That is a decision that joint venture will make based upon what contracts they choose to enter into and in what time line. So again, we've left that to the majority owner to speak to. But there is no set time line in any of our contracts. On next date, there will be a decision.

It's not a calendar date, Paul. It's just FID thing moves you to the construction phase of the project. And so it's when things are ready to move to that phase.

The next question is from the line of Ryan Levine with Citi.

Given the EPS growth guidance through 2025, the new PTC through 2032 and to be made decision around transacting the nuclear decision, how are you thinking about managing the 2025 power debt maturities to be able to continue your EPS growth rate under the various scenarios?

Yes. (inaudible), it will depend upon overall cash needs and overall revenue picture. I mean we would determine what the best magnitude of debt would be at that entity based upon what that -- the overall economics that can be supported there and what makes sense there. So we don't have an absolute number, but we do have in place is a 3-year term loan that sits at power. And runs through '25, and that's what was put in place after the sale of Fossil. And so as we get a little closer to that date, we'll be looking at all that to make that determination.

Is there any consideration to amend and extend the duration to be able to provide more earnings smoothness or keep things more visible?

The duration of the debt?

Yes.

Yes. We'll do what makes sense as we approach that maturity or even before if it makes sense to do it before. But there's -- that will come as we step towards that maturity time frame.

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

Okay. Thanks. Well, first of all, thank you for participating in the first call that I've had. I was -- I appreciate the interest and the opportunity to talk to all of you. I also just want to reiterate in this forum, my thanks to our Board and to my predecessor, Ralph Izzo for this opportunity. I am internally grateful and humbled by this -- what's in front of us, but at the same time, excited and look forward to continuing the conversations and providing more clarity and more a little bit about what we're trying to do to remove some of the volatility that has been a concern for some of you at EEI. So I can't wait to have those conversations. And again, I appreciate you all calling in.

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