Public Service Enterprise Group Incorporated (NYSE:PEG) Q1 2023 Earnings Call Transcript

Public Service Enterprise Group Incorporated (NYSE:PEG) Q1 2023 Earnings Call Transcript May 2, 2023

Operator: Ladies and gentlemen, thank you for standing by. My name is Rob, and will be your event operator today. I would like to welcome everyone to today’s conference, Public Service Enterprise Group’s First Quarter 2023 Earnings Conference Call and Webcast. As a reminder this conference is being recorded today, May 2, 2023, 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.

Carlotta Chan: Good morning. And welcome to PSEG’s first quarter 2023 earnings presentation. On today’s call are Ralph LaRossa, Chair, President and CEO; as well as Dan Cregg, Executive Vice President and CFO. The press release attachments and slides for today’s discussion are posted on our IR website at investor.pseg.com and our 10-Q will be filed shortly. 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 differ 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 earnings materials.

Following Ralph’s and Dan’s prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Ralph LaRossa: Thank you, Carlotta. Good morning to everyone and thanks for joining us to review PSEG’s first quarter results. As indicated in our release, PSEG reported first quarter 2023 net income of $1,287 billion or $2.58 a share compared to a net loss of $2 million or less than $0.01 a share for the first quarter of 2022. Non-GAAP operating earnings for the first quarter were $695 million or a $1.39 per share compared to $672 million or a $1.33 per share for the first quarter of 2022. The non-GAAP results for first quarter 2023 and 2022 exclude items shown in Attachment 7 and 8 provided in the release. PSEG delivered solid operating and financial performance to begin the year and we are on track to achieve our full year 2023 non-GAAP operating earnings guidance of $3.40 to $3.50 per share.

We are executing our plan to grow PSEG, while also increasing its predictability, which we outlined in our March 10 Investor Conference. In addition to introducing PSEG’S ten-year capital spending forecast during the conference, we announced the decision to retain our five-unit nuclear generating fleet and exit offshore wind generation. The utility invested approximately $800 million during the first quarter of 2023, consistent with its full year capital plan of $3.5 billion. These investments will be directed to modernizing T&D infrastructure, clean energy future programs, and the last mile projects in the Infrastructure Advancement Program that support New Jersey’s policies for energy transition. The 2023 capital spending program also represents PSE&G’s largest investment plan to date and drives PSE&G’s long-term growth outlook for non-GAAP operating earnings of 5% to 7% over the five-year period through 2027.

PSE&G completed the second phase of its Gas System Modernization Program in February. And in order to continue these critical infrastructure investments proposed a third phase with the New Jersey Board of Public Utilities or the BPU to invest $2.5 billion over a three-year period. This effort will reduce methane leaks and carbon emissions as we work to expand clean energy options for our customers. Also, in February, the BPU approved an accounting order allowing PSE&G to modify its methodology for amortizing a component of pension expense for rate making purposes. This is consistent with our request to reduce the impact of pension accounting on our reported results. Additionally during the first quarter, PSEG achieved several milestone metrics in customer satisfaction and nuclear operations, ratifying new labor agreements with all of our New Jersey unions and implemented back to back gas supply cost reductions that helped on the customer affordability front.

On the customer satisfaction measures, PSE&G achieved top quartile performance of overall among large utilities in the east in J.D. Power’s first quarter 2023 residential electric and gas studies. This follows our full year 2022 J.D. Power recognition of ranking number one in customer satisfaction with both residential electric and gas service among large utilities in the east. On the customer affordability front PSE&G implemented two basic gas supply service commodity charge reductions during the 2023 heating season, resulting in a total bill reduction of approximately 14% per month for a typical residential gas customer. Our nuclear fleet demonstrated its strong performance in the first quarter, operated at 100% capacity factor and maintained a strong ranking on the Institute for Nuclear Power Operations Performance Indicator Index.

We have also authorized the funding required to transition our 100% owned Hope Creek unit from an 18-month to a 24-month fuel cycle starting in 2025 and are monitoring NRC approval of a fuel change that would enable the transition of our co-owned Salem units to a 24-month fuel cycle in the future. We also continued to evaluate power upgrade options for our Salem units to increase their generation capacity in the back half of this decade. Salem unit two has completed a scheduled fueling outage and was synchronized to the regional power grid last Friday. Turning to our union contracts, following constructive discussions, PSEG recently reached new four-year labor agreements with all of our unions representing employees in New Jersey. This provides all parties with visibility and predictability on compensation and benefits into 2027.

During 2022, PSEG also hired over 1,000 new employees and maintained and created thousands of essential good paying jobs for the New Jersey economy, like PSE&G’s award-winning Clean Energy Jobs Training Program, which was focused on employment opportunities for underserved communities. Turning to Governor Murphy’s three executive orders issued in February to combat climate change and power the next New Jersey, we are developing proposals to help support and advance the state’s updated and expanded energy policy goals, which we also believe can represent a $3 billion to $7 billion incremental investment opportunity for PSE&G through 2032. BPU is expected to be the primary implementation agency for all three executive orders over the next 12 to 18 months.

We anticipate that the BPU will update their energy master plan with specific short- and long-term proposals to achieve the state’s accelerated target of 100% of electricity sold in the state coming from carbon free resources by 2035. a strategic roadmap with strategies to achieve the goals of having 400,000 homes, 20,000 commercial properties, and an additional 10% of all low to moderate income properties electrification ready by 2030. And convene a stakeholder process for the future of natural gas utilities aimed at reducing emissions all consistent with the state goals, while also considering impacts on costs and jobs. On the ESG front, Forbes recently added PSEG to its 2023 list of America’s Best Employers for Diversity. In addition, PSEG continues to work towards developing and submitting for validation our emissions targets for Scope 1, 2, and 3 to the UN-backed Science Based Target initiative this fall.

We are off to a solid start in 2023. We are on track with PSEG’s full year 2023 non-GAAP operating earnings guidance of $3.40 to $3.50 per share and with PSE&G’s $3.5 billion plan capital spend for 2023. The five-year capital spending program over 2023 to 2027, of $15.05 billion to $18 billion, drives our 6% to 7.5% of compound annual growth rate in rate base over that same five-year period. These utility investments and the cash generation from our nuclear fleet position us to continue supporting growth in our common dividend, which we recently raised by $0.12 to the indicative annual rate of $2.28 per share. It enables funding our capital investment program through 2027 without the need to issue new equity or sell parts of our company in order to grow.

The month of May marked the 120th anniversary of public service. We thank our 12,000 dedicated employees and the ones before us for carrying forward the company’s proud legacy of safe and reliable service. As we look to the next 120 years, I see a long runway of opportunity in the energy transition. We are seeing trends like the new business request trickle in for behind the charger infrastructure work. Policy makers pushing ahead on the next phase of offshore wind transmission and future investment opportunities in New Jersey’s accelerated and expanded clean energy policy goals. In fact, just last week, the BPU, in keeping with their stated intentions, opened the next solicitation window for offshore wind transmission solutions in 2024. The board staff and PJM recommended the PSEG Deans 500kV substation as the preferred interconnection point to facilitate the additional injection of 3,500 megawatts of power, part of New Jersey’s goal of adding 11,000 megawatts of offshore wind resources.

We fully intend to continue pursuing regulated offshore wind transmission investment opportunities both at our utility and separately at PSEG Power and other. This ongoing investment in the New Jersey economy and its energy infrastructure improves the reliability of our networks, as well as the predictability of the business, which we hope our stakeholders find to be a compelling value proposition. I’ll now turn the call over to Dan for more details on the operating results, and we’ll be available for your questions after his remarks.

Dan Cregg: Good morning everybody and thank you, Ralph. As Ralph mentioned for the first quarter of 2023, PSEG reported net income of $1,287 million or $2.58 per share compared to a net loss of $2 million or less than a penny per share for the first quarter of 2022. Non-GAAP operating earnings for the first quarter of 2023 was $695 million or $1.39 per share compared to $672 million or $1.33 per share for the first quarter of 2022. We have provided you with information on Slide 9 regarding the contribution to non-GAAP operating earnings per share by business for the first quarter of 2023, and Slide 10 contains a waterfall chart that takes you through the net changes quarter-over-quarter in the non-GAAP operating earnings per share by major business.

Starting with PSE&G. PSE&G reported first quarter 2023 net income of $487 million or $0.98 per share compared to $509 million or $1.02 per share in the first quarter of 2022. First quarter of 2023 non-GAAP operating earnings were $492 million or $0.99 per share compared with $509 million or $1 per share in the first quarter of 2022. The main drivers for the quarter were the rate base additions from transmission and our Gas System Modernization Investment Programs, which were offset by the lower pension credits and the timing of taxes. Compared to the first quarter of 2022 transmission was a penny per share higher. Gas margin was a penny per share higher driven by $0.03 per share, a favorable GSMP investment return that was partly offset by a penny per share of lower non-SIP demand due to the warm weather and other margin items.

Electric margin was flat compared to the first quarter of 2022. Also reflecting the absence of favorable ship true-up in the year earlier quarter partly offset by growth in the number of customers. Other Electric and Gas margin added a penny per share reflecting both the earnings impact of the cap or the tax adjustment credit and appliance service results. Lower distribution O&M expense added $0.03 per share compared to the first quarter of 2022, primarily reflecting reduced weather related corrective maintenance and gas maintenance costs. Both depreciation and interest expense increased by one penny per share compared to the first quarter of 2022, reflecting continued growth in investment. Lower pension credits reflecting 2022s investment returns resulted in the 4 penny per share unfavorable comparison to the year earlier quarter.

The impact of PSEGs $500 million share repurchase program completed in May 2022 had a penny per share benefit in the first quarter of 2023. Lastly, the timing of an effective tax rate adjustment, another flow through taxes had a net unfavorable impact of $0.03 per share compared to the first quarter of 2022. But will reverse over the remainder of the year driven by the use of an annual effective tax rate. The ship mechanism in effect since 2021, limits the impact of weather and other sales variances positive or negative on electric and gas margins, while enabling PSE&G to promote the widespread adoption of its energy efficiency programs. Winter weather in the first quarter of 2023 was the warmest first quarter in PSE&G’s records, measured by heating degree days the first quarter of 2023 was 23% warmer than the first quarter of 2022 and 23% warmer than normal.

The CIP mechanism allowed us to recover the impact of this extreme weather on sales. Growth in the number of electric and gas customers, the driver of margin under the CIP mechanism continues to be positive and we’re each up 1% during the trailing 12-month period. PSE&G invested $800 million during the first quarter and is on track to execute its plan 2023 capital investment program of $3.5 billion; that includes infrastructure upgrades to its transmission and distribution facilities, Energy Strong two investments, Last Mile spend in the infrastructure advancement program and the continued rollout of the clean energy future investments in energy efficiency and the energy in cloud including smart meters. For the full year 2023 PSE&G’s forecast of non-GAAP operating earnings is unchanged at $1,500 million to $1,525 million.

Moving on to PSEG Power & Other, which includes our nuclear fleet, gas operations, Long Island and parent activities including interest expense. For the first quarter of 2023 Power & Other reported net income of $800 million or $1.60 per share and non-GAAP operating earnings of $203 million or $0.40 per share, this compares to first quarter 2022 net loss of $511 million or $1.02 per share, and non-GAAP operating earnings of $163 million or $0.32 per share. We previously mentioned that PSEG Power would benefit from an approximate $4 per megawatt-hour increase in the average price of a 2023 hedged output, which rose to approximately $31 per megawatt-hour. The majority of this annual price improvement was realized during the first three months of the year with higher winter pricing driving most of the increase, and as a result gross margin for the quarter rose by a total of $0.10 per share driven primarily by $0.17 per share increase from recontracting 8.4 terawatt-hours generation and market impacts from the step up in power prices.

The gross margin increase also includes lower capacity revenues of $0.02 per share and lower gas operations of $0.05 per share reflecting lower capacity and natural gas prices during the first quarter of 2022. First quarter cost comparisons improved by a penny per share in 2023 reflecting lower nuclear costs and reduced spend on offshore wind activity versus 2022. Higher interest expense covering PSEG Power and parent financings were $0.04 per share unfavorable compared to the year ago quarter from refinancing, maturing debt and higher rates. Lower pension credits from 2022, investment returns were $0.03 per share unfavorable versus the first quarter of 2022. Taxes and other were $0.04 per share favorable compared to the first quarter of 2022, reflecting the use of a lower effective tax rate in the quarter that will reverse over the balance of 2023 partly offset by lower investment income.

On the operating side, the nuclear fleet produced approximately 8.4 terawatt-hours during the first quarter of 2023 similar to the first quarter of 2022, and ran at capacity factor of 100%. For the full year of 2023 PSEGs forecasting generation output of 30 to 32 terawatt-hour and its hedge approximately 95% to 100% of this production at an average price of $31 per megawatt-hour. For 2024, PSEG is again forecasting nuclear baseload output 30 to 32 terawatt-hour and it said 75% to 80% of this output at an effective price of $37 per megawatt-hour. A forecast non-GAAP operating earnings for PSEG Power & Others unchanged at $200 million to $225 million for the full year. This forecast reflects the realization of a majority of the expected increase in the average 2023 annual hedged price in the first quarter of the year with minimal incremental pricing improvement compared to the prior year expected over the balance of 2023.

Moving on to recent financing activity. As of March 31, 2023 PEEG had available credit capacity of $3.9 billion including $1 billion at PSE&G. In addition, PSEG had total cash and cash equivalents on hand of approximately $1.2 billion. PEEG Power had net cash collateral postings of $700 million at March 31st, primarily related to out of the money hedge positions resulting from higher energy prices. As these historical lower price trades continue to settle through 2023 and into 2024, collateral is returned as PSEG Power satisfies its obligations under those contracts. Thus far in 2023 collateral postings have been below the high levels experience during 2022 and remained subject to market moves Early in the first quarter we prepaid $750 million of the $1.5 billion, 364-day variable rate term-loan due in April.

Subsequent to the end of the quarter remaining $750 million of the April 2023 term-loan matured and was replaced by a new $750 million, 364-day variable rate term-loan maturing in April 2024. As of March 31, 2023, PSEG had outstanding a total of $1.25 billion of 364-day variable rate term loans expiring April and May of 2023 to support PSEG Power’s, collateral needs and PSEG Power had outstanding $1.25 billion variable rate term loan expiring March 2025. In total $1.05 billion of Power & Others’ variable rate debt has been swapped from variable rate to fixed as of March 31, 2023 with an additional $175 million swapped in April. Also in March PSE&G issued a total of $900 million of green bonds consisting of $500 million of secured medium term notes due 2033 and $400 million of secured medium term notes due 2053.

As Ralph mentioned we are reaffirming PSEGs 2023 non-GAAP operating earnings guidance of $3.40 to $3.50 per share with regulated operations at PSE&G forecasted to contribute $1.5 billion to $1.525 billion. And PSEG Power & Other forecasted at $200 million to $225 million, noting that PSEG Power & Other has realized the majority of the expected annual price increase and re-contracting during the first quarter 2022. That concludes our formal remarks. And operator we are ready to begin the question-and-answer session.

Q&A Session

Operator: Thank you. Thank you. And our first question is from the line of Shar Pourreza with Guggenheim Partners. Please proceed with your questions.

Shar Pourreza: Hey guys. Good morning.

Ralph LaRossa: Good morning, Shar.

Shar Pourreza: Good morning. So first question is on, on just looking at maybe opportunities to efficiently finance, I know obviously interest rate risk has been a headwind recently, but it’s embedded in plan. You don’t need equity, but do you feel like you have some opportunities for maybe financing efficiencies on the debt side especially as we kind of see a very attractive cash pay convert market unfolding, five-year terms, low 3% costs. And could that sort of benefit be accretive to that 5 to 7 you guys reiterate today, especially since you do embed a higher interest rate cost step up?

Ralph LaRossa: Yes. Sure. Thanks for that and, I will give it to Dan in a second here. I – look we’re never going to walk away from an opportunity to save a few dollars, which is what you’re referring to there, and so we wouldn’t do that. I also think there is a fine line there that you have to watch from a being 2Q to being folks thinking that you’re actually issuing equity. So I guess every one of those deals are different and we look at it and how it’s structured, but we don’t need to issue equity and I just want to be certain that anything that we did to look at that, would not be done in that light. So Dan, you want to add?

Dan Cregg: Yes. I think that’s the right theme, Shar. We obviously going to consider all options and we do on a regular basis when we try to look at how we finance the business. But I think it probably is a better fit for somebody who has an equity need coming up, but obviously we would look at it the same way that we would look at anything else to make sure we’re financing efficiently.

Shar Pourreza: Perfect. That was very clear. And then just lastly on the strategic side, it’s obviously maybe a small upside but do you have any sort of efficient ways to allocate proceeds for the lease sales if those occur? I mean, there’s been some activity on that front across the offshore wind players. So I wonder if you – if you think it could be more accretive to hold on to some of those leases for a more competitive process and maybe more stable capital market environment there. Thanks.

Dan Cregg: Yes. I don’t know that you can perfectly time the market. I do know that acreage that we do have is off the coast of Maryland. Maryland just upsized, they are targeted offshore wind; New Jersey has done the same. Those are, I think, probably the two markets that those acres would serve the best. And so I think you’d look at it from an operating perspective and from a market perspective I should say as to when you were going to execute on that sale. And when they come in, I think it’s just going to be part of general corporate funds. Probably the most, the quickest and most efficient way to use those funds would be a pay down of some debt and then just redeploying capital as we’ve seen needed. It’s not like we’re going to, I guess embedded within Ralph’s comments we’re not selling parts of the business in addition to not issuing equity for what we need to do.

And so it’s not like that’s going to be required from a timing perspective to do what we need to do to fund the capital plan. I think that’s all, all sound and I think it’s just going to go back and be part of the overall financing plan.

Shar Pourreza: Got it. Fantastic guys. Kudos on today. We’ll see you soon.

Dan Cregg: Thanks Shar.

Ralph LaRossa: Thanks Shar. Happy doing.

Operator: Next question is from Durgesh Chopra with Evercore. Please proceed with your question.

Durgesh Chopra: Hey. Good morning Dan. Thanks for giving me time here. Just – Dan, quick clarification on the proceeds from the lease that – that would be all incremental to the current CapEx plan, right? I just want to be clear on that front?

Dan Cregg: Yes. And look we shouldn’t overplay the magnitude of what that’s going to look like. It’s going to be great, but it’s not going to be life-changing for the company as we go forward. It is a transaction that will be around the edges and we’ll do it when it makes the most sense to make it the most efficient.

Durgesh Chopra: Makes sense. Okay. I didn’t hear you mention the lift out on the pension on the call. Sorry if I missed it. Can you just talk to that, what are the latest developments there and is that still sort of something you’re considering?

Dan Cregg: Yes. I think, Durgesh, you didn’t really hear anything because there really isn’t nothing new to report which is not to imply nothing’s going on. Diligence does continue, it’s something that we’re continuing to explore just with the same purpose to dampen the volatility that we would’ve within the pension. And I think things are continuing productively, but there’s nothing new to report. But don’t take the absence as if it’s off the table, it remains something we’re pursuing.

Durgesh Chopra: Got it. That’s very clear. And then just one last one for me, can you comment on how did the quarter shake out versus your expectations and how does that position you for 2023 with respect to your guidance range?

Ralph LaRossa: Yes. Durgesh, it shook out exactly the way we expected it to. So we’re, that’s why we’re so certain about reaffirming guidance. I think what you also heard in a bunch of the answers that Dan just gave you was flexibility that we have. We’re not – none of the things that you’re talking about are opportunities we have require us to thread a needle to execute the plan that we have in front of us. And that confidence I hope comes across in both the way that we’re answering and with the optionalities that we have.

Durgesh Chopra: It does. Well done guys. Thanks so much.

Ralph LaRossa: Thanks.

Dan Cregg: Thanks Durgesh.

Operator: The next question comes from Julien Dumoulin-Smith with Bank of America. Please proceed with your question.

Julien Dumoulin-Smith: Hey, good morning team. Thank you guys for the time. Just following-up on hedging and hedging strategy here post IRA, it seems like there’s been a pretty nice step up here at hedge prices versus the fourth quarter deck, $37 a megawatt-hour versus $32. Can you talk about that? What drove the significantly higher price? Is there a change in how commercial activities are being characterized or is that actually a real step up in economic value that you’re showing there? I just want to make sure we’re all clear about that.

Ralph LaRossa: Yes. And I’ll give it to Dan to give you because he’s got that trading operation. But I just do want to reinforce that a lot. There’s still some uncertainty out there in the out years until we get the rules back from treasury. So what we are describing there though is what we expect to happen. And Dan you could fill some more details in there.

Dan Cregg: Yes. Julien, I would – what you’re describing is not some kind of dramatic shift in what we’re doing. We’ve always worked within a range across a ratable period. There are bounds within that range. It’s not a perfectly scientific range, so you could see some movement within a fairly bounded range for what we do. The quarter started with some higher prices, ended with an uptick and in the middle had a drop off. And so I think that we did a nice job of capturing some decent pricing. The other thing I would say though that you don’t want to lose sight of is that, not everything is robotically across the year as well. So you could have some on peak, some off peak hedges come on. You could have some winter hedges, some seasonal hedges, some calendar hedges come on and that can make a little bit of a difference as you go through quarter-to-quarter.

It’s a little bit of a granular look. So to your question, I do think that we did a nice job in moving forward and capturing some value, but I think some of the other things that I described also could come into play in any quarter, frankly. I say that more generically as we go quarter-to-quarter and you look at it granularly through time.

Julien Dumoulin-Smith: And just to clarify that commentary. So basically this is more about hedging on peak resolve peak than it is anything tied to IRA or otherwise. And again you did a nice job commercially hedging, but you wouldn’t necessarily say that this is anything in terms of a change methodology importantly?

Ralph LaRossa: You got that last part is the most important point that that we said that we are kind of continuing on our path, similar methodologies to what we’ve done in the past. Pending the real update that is when we’ll get that from treasury and understand it. My only comment is you can’t take too much of a fine point because there are some nuances with the timing of hedges whether they’re on off peak and seasonal versus counter hedges and things of that nature. But on balance definitely a good quarter from a value perspective as we step through time.

Julien Dumoulin-Smith: Got it. And then super quick if I can. You alluded to these plans that you’re developing proposals for electrification. When do you expect that to come? I know we’ve talked about this a bit in the past, just what’s the timeline there and then especially any thoughts about a parallel higher load forecast with that and the timeline there?

Ralph LaRossa: Yes. So Julien, I think you’re going to – all of that’s going to play out over the next 12 to 18 months on multiple fronts. First we have to get agreement on our load forecast as you said. I continue to believe that the current load forecast that we see from PJM is light. Like isn’t that a big impact to us again because we are decoupled, which we’ve seen the benefit of this year. But I think that it will drive additional investments for us both potentially at the transmission level and at the distribution level depending upon what – where those forecasts levelize off that. There is a gap between our internal forecast and what PJM has. We provide that information, but PJM is the ultimate transmission authority from a planning standpoint, so we build our system out to that.

I think there are though as we get alignment on rates of EV turnover in the state of New Jersey as we get alignment on the electrification plans of the Governor. And then as we get more alignment on this clean energy transition as a whole and specifically as in regards to the offshore wind transmission, I think we’ll be able to give you a little more guidance on that over that next 12 to 18 months.

Julien Dumoulin-Smith: Excellent. Good luck guys. See you soon.

Ralph LaRossa: Thanks Julien.

Dan Cregg: Thanks Julien.

Operator: The next question is from Travis Miller with Morningstar. Please proceed with your questions.

Travis Miller: Good morning everyone. Thank you.

Ralph LaRossa: Hey Travis.

Dan Cregg: Hey Travis.

Travis Miller: I know it’s really early in the process, but wonder if you could characterize the discussion and issues that might come up on the GSMP III filing so far?

Ralph LaRossa: Sure, Travis. I think you’ve said the key though, which is it’s still early in the process right now, but we still don’t have any red flags as far as what we’ve seen in the conversations that we’ve had with the regulators. So we’re confident at the end of the day that we’ll get a similar run rate to what we have currently with our GSMP II filing. And I think – I think you’ve heard and seen in all the comments made from the administration, specifically the governor’s office that there’s no intent to stop any gas installations. There’s no intent at this point to stop stoves from being tied into gas. So it’s a little bit different environment that we have and I think that the lack of attention that it has had is also a very good indicator for all of us is to where policy will be heading in the state.

Travis Miller: So you’re not taking anybody’s stoves away?

Ralph LaRossa: Yes. No, I mean there’s no plan on that. And I look at; we got to be careful on all of this because that process is confidential, right? So we – I think you can see from the newspaper articles and so on that there’s really no challenge to us on the replacement of our facilities.

Travis Miller: Yes. Just joking on that one, and perhaps I should have asked this first, but how early is it in the process? What kind of timeline are you thinking about?

Ralph LaRossa: Yes. We usually talk about those things in the 12-month plus timeline for filing like that. And I think we’re only a couple months into it yet, so they just – they just named a presiding officer at the BPU for that – for this filing. And so I think we’re 12 months plus away for early decision.

Travis Miller: Okay. Great. Thanks so much. Appreciate it.

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

Andrew Weisel: Hi, good morning everyone.

Ralph LaRossa: Hi Andrew.

Andrew Weisel: First question on the new four-year labor agreements, first of all I’m glad you had more success than the Hollywood writers did. But my question is given the inflationary pressures, how do the cost structures compare to prior deals and how will that affect customer bills?

Ralph LaRossa: Yes. So Andrew, a couple things there. Let me start backwards with the customer bills, I think there’s been a few reports out that I just would encourage. If I take a look at New Jersey from 2021 to 2022 was I think the fourth lowest state in the U.S. as far as residential electric rate increases. So the process here is working, it’s not just what we do in the T&D business, but it’s also the way they procure power. And we’ve talked about that a bunch of times. So kudos to the BPU on that and the process that’s been in place, and so we – because of that rolling nature, I – any kind of increase that we would have is going to be minimal to start with. That said labor is a large component of our O&M and the largest component of our own O&M expenses within the utility.

So it will be a piece that goes into our rate case filing that we have. But the 4% increase that we were able to negotiate, three in the out years is just – it’s just a good indication of the relationship that we have. The strong relationship that we have with our unions – all of our unions in the state, and the fact that in prior years when we had a 3% labor increase and inflation was in at 1% to 2%, the unions recognize that and the unions recognize now when inflation is higher than the 3% to 4%. They had some benefit in prior years. So I think the outcome is pretty flat and it’s flat from a growth standpoint for our folks because the good working relationships that we have and the way it plays out. At the end of the day, I don’t think this will have a major impact on the rates again because of a number of different factors.

So that’s exactly what we expected and should give you some confidence and others on a call as to our own end projections in the out years because it is the biggest component of our expenses.

Andrew Weisel: Great. That’s very helpful, and yes, I know those negotiations are never easy; so congrats. Next question is on electric vehicles. Can you talk a little bit about how soon you expect to see the impact in terms of both infrastructure investment and higher residential demand? And then just remind me under the CIP decoupling mechanism. Would you benefit with higher revenues as EVs pick-up? Or would that be kind of more of an affordability story?

Ralph LaRossa: Yes. So a whole bunch in there. First of all as far as timing goes, we are starting to see some new business requests come in. We see it in some of the Garden State Parkway, rest stops we’re seeing it in the New Jersey Turnpike rest stops. We’re seeing in some of the large commercial organizations that were just granted approval by the BPU that will installed the charging infrastructure. So those – that activity has started, and we’re going to keep an eye on that and see about what it – what kind of capital is required for each one of those installations on a standalone basis that’ll help us in projections going forward, but it’s just a start. As far as load increases, and individual residences, we’ll know more about that as we deploy AMI.

We have our AMI cross rollout going very well in New Jersey, and we’ll have a lot more details that we can talk about, I would say 12 months from now as far as when we start to see folks connected their EVs that we had an engineer that – that had worked here, just retired after about 60 years. And he said that he sees this transition as the transition when we went to Central Air Conditioners back in the 1950s. So it’ll happen – it’ll happen sporadically and then it’ll take-off just like – like that, that deployment took place. So we are – we will have more to say about it as we go forward, but I’m just really excited about the fact that we’re starting to see it take place already and these first set of plans getting out from the BPU last week.

Dan Cregg: And on the affordability side of things, Andrew, too, I think that there will be infrastructure improvements that will need to be made that last mile of our system is pretty dated and there is a lot of work that’ll need to be done, but I think, part of what you’re going to see is a shift where a piece of the wallet that used to end up at the gas station is going to end up on the electric bill. So, that helps things as well.

Ralph LaRossa: And that’s only for the commodity because again, as you mentioned from the SIP, we’re not going to collect anymore for the pipes or the wires other than for what we deploy additional capital on.

Andrew Weisel: Okay. Thank you very much.

Dan Cregg: Thanks, Andrew.

Operator: Next question is from the line of Paul Patterson with Glenrock. Please proceed with your questions.

Paul Patterson: Hey, good morning.

Ralph LaRossa: Good morning, Paul.

Paul Patterson: You mentioned the selection of the offshore wind injection point, and I was just wondering if you could elaborate a little bit more what that actually might mean for you. If you could just elaborate a little bit more on that, I guess.

Ralph LaRossa: Yes, sure, Paul. So it wasn’t a selection, it was a recommendation by the BPU to PJM to look at our Deans Sub Switching Station as the entry point. So what that could – what it means for us certainly is that if PJM does agree with the Board of Public Utilities and does select that, any of the work inside the fence will be the responsibility of PSE&G the complete inside the fence. The work outside the fence will still follow under that state agreement approach and be a competitive solicitation. However, what I am encouraged by is the fact that Deans is in our service territory. We know our service territory. And we should be very knowledgeable about the routes to get from the shore to that Dean’s substation. And I wouldn’t go beyond that at this point, but I’m happy to see that that Deans was selected.

I also would tell you that I’m very happy about the work that we’ve done on our transmission system because the indication that that gives us is that our transmission system is robust enough to take that injection of offshore wind generation into it. So, we’ve done a nice – our engineering team has done a really nice job of readying the system for what might come and here it is.

Paul Patterson: Is there any potential, I guess, when we talk about inside defense, do you have any number about how much that might be?

Ralph LaRossa: No. Well, I wouldn’t know. We won’t know until we actually see the size and magnitude of what comes in there versus down to the area JCP&L just is rebuilding and maybe even down in the Atlantic City Electric territory. So, a lot of flows to be figured out by PJM between now and then.

Paul Patterson: Okay. That’s something to watch, I guess. Then with respect to the going from an 18-month fuel cycle to a 24-month fuel cycle, can you tell us what the – what the potential impact of that might be, I guess, starting in 2025?

Ralph LaRossa: Well, from a capital expenditure standpoint, I think, we told you it’s going to be around $30 million or so. It’s about that same amount. So it’s a very small number. What the impact will be is we’ll be some savings in O&M that we’ll have as a result of that. And we’re also obviously going to get additional megawatts. We have not – I don’t think we’ve published that anywhere yet. So I’d just stay away from disclosing any of that information until we get the engineering completed, which is what that $30 million. There is really not a lot of work to do to actually ready a nuclear plant for this. What really has to be done is the engineering on the fuel rods and how they are going to interact with each other. And as that’s completed, then we’re going to tell what additional power we’re going to get out of the unit.

Paul Patterson: Okay, great. Thanks so much.

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

Ralph LaRossa: Hey Ryan.

Ryan Levine: Hi. Hi. How are you? A couple of follow up questions. As the organization continues to evaluate the pension lift out opportunities, do you think the company will be in a position to make a decision later this year, or has the timeline changed as you continue to work through the mechanics and details of how that would all work?

Ralph LaRossa: You want to give that one with Dan?

Dan Cregg: Yes. Ryan there is really no change in schedule, I think, it’s a – we think about it as being a 2023 event, but we’ll continue to watch what’s going on. We’ll continue to watch what the market looks for is a large deal announced today on that front. So, we’ll make sure that as we do move forward first and foremost continuation of benefits and certainty around all that and all that diligence that we’re going to do and that everything works well it’s going to be super important, but we’ll also keep an eye on what the overall market conditions are to move forward on that.

Ryan Levine: Got it. Appreciate the color. And then as in terms of the Salem, what’s the remaining process to extend the fueling cycle there? And are there any other capacity additions or changes to maintenance or refueling that you are contemplating in the near term?

Dan Cregg: Yes, what we referred to in the script was that the NRC has several PWR plants that are looking at changing their fuel cycle from 18 to 24 months. So we’re monitoring that. What we had discussed in the past and what we’re continuing to look at is the additional upgrades, which are different than the fuel cycle down at Salem. So, more to come on that we have not disclosed anything further than what we talked about at the investor meeting.

Ryan Levine: Okay. I appreciate the color. Thank you.

Dan Cregg: Thank you.

Operator: Our next question comes from the line of Anthony Crowdell with Mizuho. Please proceed with your questions.

Anthony Crowdell: Good morning, Ralph. Good morning, Dan.

Dan Cregg: Good morning. Anthony. How are you? Is your first comment going to be congratulations, devils?

Anthony Crowdell: It was, congratulations, devils. Big win last night. Congratulations. I’m a little sad with my ranges. But most of my questions answered. Just one super quick one following up on Shar’s question earlier on, I think, the thought of maybe using a hybrid maybe for financing, I guess, are you guys forecasting additional debt to parent to fund CapEx either at power or the utility?

Ralph LaRossa: Yes, we gave a little bit of indication in March on that Anthony, that the parent will see some debt levels come down as the existing collateral cycle kind of works off down to a more baseline amount of collateral. But then over time, we do expect, as we continue to fund the capital plan that we have we do anticipate some incremental financing over time. And when Shar asked the question, is it something that we think of first and foremost as we’re going to finance? No, we don’t have equity needs as we go through the capital plan, but is it something that we would look at just to make sure we’re not missing anything? I think that answers yes.

Anthony Crowdell: Great. That’s all I had. Thanks so much.

Dan Cregg: Thanks, Anthony.

Ralph LaRossa: Thanks, Anthony.

Operator: The next question is from the line of Ross Fowler with UBS. Please proceed your questions.

Ross Fowler: Good morning.

Ralph LaRossa: Good morning, Ross.

Dan Cregg: Good morning, Ross.

Ross Fowler: I’ll echo the congratulations devils. And my broods laid a big egg, so they cleared the way for me for sure. So most of my questions have been answered. Just maybe a couple for you, Dan. So, customer growth came in pretty good in the quarter, tracking around 1%.

Dan Cregg: Yes.

Ralph LaRossa: Can you just kind of remind us with the SIP what you’ve assumed for customer growth in your go forward earnings growth guidance?

Dan Cregg: Yes, less than – between 0% and 1% is kind of the range that we’ve assumed for customer growth over time. And again, that’s number of customers, that’s the important element for us. Right.

Ross Fowler: Right, right. And then there was this $0.10 of expected tax carryback, in your walk from 2022 to 2023, but that ended up coming in 2022. So, what other things are now sort of in 2023, given the absence of that $0.10 and get you back to sort of your 2023 guidance rate?

Dan Cregg: Yes, it’s a great question. And that $0.10 was not entirely the carryback that was the biggest chunk of it. And so that did come in early. What we’re seeing in 2023 really that offset some of that without going through a whole bunch of puts and takes with respect to the guidance, which is still in the same place it was last quarter, is some of the lower collateral deriving lower interest, which is a little bit of a tailwind. So a headwind from the former, a tailwind from the latter. And we’re still in the same place from an overall guidance perspective.

Ross Fowler: All right. Perfect. That’s all I had. Thank you.

Dan Cregg: Thanks Ross.

Ralph LaRossa: Thanks Ross. And I’ll fill you in on my Panthers’ connection later.

Operator: Thank you. The next question is from the line of Michael Sullivan with Wolfe Research. Please proceed with your questions.

Ralph LaRossa: Hey, Michael.

Michael Sullivan: Hey, Ralph. How are you?

Ralph LaRossa: Good.

Michael Sullivan: Just wanted to circle back to the offshore wind transmission opportunity and solicitation next year. I guess like how should we think about the read through from the first go around? And I think the fact that it came on shore in JCP&L’s territory and the fact that they got most of the opportunity there should we take that as a read through with using the Deans substation?

Ralph LaRossa: Yes. No, Michael. I think, look, the fact that that work was awarded to JCP&L just indicated that they had some work to do to make that system more robust, to catch the power coming in, to use an analogy there. What you are hearing now is that the work that we have been doing at Deans has ready our system al already. So, we’re in a little better place from a readiness standpoint at Deans. And I think that you are now seeing the BPU executing on what they had originally said from the beginning, which was, hey, we want to come into the southern part of the state, the central part of the state, and the northern part of the state. And our Deans substation switching station, allows them to execute on that plan.

Michael Sullivan: Okay. That’s very helpful. And then just in terms of the timeline for any spend related to this solicitation next year?

Ralph LaRossa: Yes. It’s all end of the decade, Michael. We have been saying from the beginning, they will go through the solicitation process. Again they are still waiting for treasury as well to figure out the tax rules, once they get there, we will determine what’s going to be transmission, what’s going to be generator leads, and we’ll be off to the races at that point. But that still puts us at the end of the decade before anyone is deploying capital on us.

Michael Sullivan: Okay. That’s very helpful. One, one quick one, back to the quarter. On the electric and gas margin, I just wanted to make sure I understood correctly the impact that was not covered by the SIP, what was that related to?

Ralph LaRossa: So like, I think, we said in March there is about 95% of our overall revenues covered by the SIP, and there is some component that is not. And so we do have some variability, albeit much more on the smaller end. I think the variance you are talking about was a $0.01. So, it was not a significant amount, but there is some element that falls outside of it, some of the larger customers that’s all.

Dan Cregg: It’s the I&C. It’s a small piece of the I&C customer base.

Michael Sullivan: Understood. Thanks guys, appreciate it.

Ralph LaRossa: You bet Michael.

Operator: Our next question is from the line of Angie Storozynski with Seaport Global. Please proceed with your questions.

Angie Storozynski: Thank you. So, I know you guys covered this in detail during the Analyst Day, but I still want to ask a question about the future of your nuclear plans. And so you talked about the assets being an important source of cash to finance the growth of the utility that you wanted to do upgrades at the assets and you were waiting for more guidance from IRS around nuclear PTCs. So, my question is – so is it just a question of timing in the sense that you are not ready yet to separate these assets, or maybe there is no easy way to separate these assets without any tax, so it could still come in the future? Or is it just a long-term strategy that you plan to stick with these assets and you hope that investors will value them at least the PTC backed earnings as regulated like?

Ralph LaRossa: Yes, Angie, I was trying to be as clear as possible at that investor meeting. We want to and expect to keep those assets in a portfolio. I don’t see any scenario that we’ve been presented with that would make us waiver from that. And so, I just want to be as clear as I can, crisp as I can beyond that. You laid out exactly upfront, all the reasons why we articulated and I stand by that today as to why we’re keeping those plants. They are a great cash flow, they’ve been run really, really well and they continue to be run really well. And so when you have that operating excellence combined with the cash flow, it does create a very unique utility like revenue stream for us that we think differentiates us from some of our peers. And hopefully across the board today you are seeing that differentiation.

Dan Cregg: And hard to think of a more valuable asset in these times, Angie.

Angie Storozynski: Yes, I mean, I don’t disagree. But then lastly, so we’re waiting for that guidance on nuclear PTCs, and it sounds like it’s only going to come in the first quarter. Do you guys have any, like, what is the main question mark here? What is it? Is it about the low market hedges? Is those getting – if those are going to get recognized in that true up associated with the nuclear PTC, I’m just wondering what is it that we’re really waiting for?

Ralph LaRossa: Yes, I’ll not give it to Dan to give you some more details on this. But look at the very high level it’s the definition of revenues and how that’s going to be treated by treasury. But Dan can give you a lot more.

Dan Cregg: Yes, just the mechanics of how it works Angie, I’m sure you know, is there’s a calculation of grocery receipts and then a comparison to what the PTC threshold is and the credit kind of fills that gap. And so how that definition is determined, and you went to exactly some of the areas that I would reference and how do you treat hedges, is it a spot price, is it some kind of an assumption around what hedges have happened, is it actual hedges that it’s just? It’s unclear exactly how they will define the gross receipts in order to figure out how you move from that amount to the PTC threshold. And so, that’s what we’re waiting on. I think that at the end of the day, we’ll get a reasonable answer. And I think that there’s a significant support for what’s there. And I think we just got to work, treasury has got to work their way through, what’s going to make the sense across units that are in various situations across the country.

Angie Storozynski: Okay. And then lastly so, we’ve heard from, consultation , for example, that they are thinking about replacing some of the state support for their nuclear plans with the federal subsidies. In your case, I’m just thinking about it, so the – so the nuclear PTCs would accrue in 2024, but you would collect them only in 2025. So, New Jersey is expiring in May of 2025. So, is it fair to assume that it’s unlikely that that there would be any changes in the current structure, given that, again, the payments roughly coincide with the expiration years ?

Ralph LaRossa: Yes, Angie I think, those mechanics are still ahead of us to be worked out. But I do think – look I think that all along, one of the things that we were saying that was so, so important is that we had a long term solution for nuclear. And I think that we were very happy to see that the PTCs did create that and honestly did create that at the federal level. And so if you think about most of the other elements that support renewable energy are the types of things through ITCs and PTCs that ultimately are funded at the federal level. And so that’s another element that I think is very important within this. And that’s what we will end up moving towards once this PTC amount starts to start to kick in.

Angie Storozynski: Awesome, thank you.

Carlotta Chan: Operator, we’re going to conclude the Q&A Session at this time. And I will turn it over to Ralph for just the closing comments.

Ralph LaRossa: Yes, well, thanks. So, listen, I appreciate everyone getting on, I appreciate the robust questions. I just leave you again with what we’ve been saying, ad nauseam at this point, but predictability and stability and confidence, and I think, that all three of those things have come across again today in both our results and hopefully in our Q&A. We’re proud of the organization we’ve got here. We’re proud of the results that we’ve been able to achieve. And we’re just trying to build on 120 years of great history that we’ve been able to inherit. And as we’ve said multiple, multiple times, we want to leave it better than we found it. So, thank you for calling in and I appreciate the time.

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