Ladies and gentlemen, thank you for standing by. My name is Rob, and I'll be your operator of event today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's 1st quarter 2023 earnings conference call on webcast. At this time, all participants are in listen-only mode. Later, we'll conduct a question-and-answer session for members of the financial community. At that time, if you have a question, you'll need to press the Star and the 1 on your telephone keypad. To withdraw your question, please press Star and then 2. If anyone should require operator assistance during the conference, please press Star 0 on your telephone keypad. 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. Good morning, 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 differs from net income or net 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 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 $1.39 per share, compared to $672 million or $1.33 per share for the first quarter of 2022. The non-GAAP results for first quarter 2023 and 2022 exclude items shown in attachments seven and eight 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-$3.50 per share. We are executing our plan to grow PSEG while also increasing its predictability, which we outlined in our March tenth investor conference. In addition to introducing PSEG's 10-year capital spending forecast during the conference, we announced the decision to retain our 5-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 PSEG's largest investment plan to date and drives PSEG's long-term growth outlook for non-GAAP operating earnings of 5%-7% over the 5-year period through 2027. PSEG completed the second phase of its Gas System Modernization Program in February, 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 3-year period. This effort will reduce methane leaks and carbon emissions as we work to expand clean energy options for our customers. In February, the BPU approved an accounting order allowing PSEG 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, ratified 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, PSEG achieved top quartile performance 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, PSEG 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 strong performance in the first quarter, operated at 100% capacity factor, and maintained a strong ranking on the Institute of 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. 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 its scheduled refueling outage and was synchronized to the regional power grid last Friday. According to our union contracts, following constructive discussions, PSEG recently reached new 4-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 PSEG's award-winning Clean Energy Jobs Training Program, which is focused on employment opportunities for underserved communities. According 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-$7 billion incremental investment opportunity for PSEG through 2032. BPU is expected to be the primary implementation agency for all 3 executive orders over the next 12-18 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. Producing 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. 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 one, two, and three to the UN-backed Science Based Targets 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-$3.50 per share, and with PSEG's $3.5 billion planned capital spend for 2023. The five-year capital spending program over 2023 to 2027, $15.5 billion-$18 billion, drives our 6%-7.5% compound annual growth rate and 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 12 cents 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 marks 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 requests trickle in for behind the charger infrastructure work, policymakers 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 500 KV 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. Good morning, everybody. Thank you, Ralph LaRossa. As Ralph LaRossa 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 were $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. 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 $1.01 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 $0.01 per share higher. Gas margin was $0.01 per share higher, driven by $0.03 per share of favorable GSMP investment return that was partly offset by $0.01 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 SIP true-up in the year earlier quarter, partly offset by growth in the number of customers. Other electric and gas margin added $0.01 per share, reflecting both the earnings impact of the TAC, or the Tax Adjustment Credit, and appliance service results. Lower distribution O&M expense added 3 cents 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 1 penny per share compared to the first quarter of 2022, reflecting continued growth in investment. Lower pension credits reflecting 2022's investment returns resulted in a 4 penny per share unfavorable comparison to the year earlier quarter. The impact of PSEG's $500 million share repurchase program completed in May 2022 had a 1 penny per share benefit in the first quarter of 2023. Lastly, the timing of an effective tax rate adjustment and other 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 SIP 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 SIP 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 SIP mechanism, continues to be positive and were 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 planned 2023 capital investment program of $3.5 billion that includes infrastructure upgrades to its transmission and distribution facilities, Energy Strong II 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 Cloud, including smart meters. For the full year 2023, PSE&G's forecast of non-GAAP operating earnings is unchanged at $1.5 billion-$1.525 billion. Moving on to PSEG Power and Other, which includes our nuclear fleet, gas operations, Long Island, and parent activities, including interest expense. For the first quarter of 2023, Power and 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 our 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. As a result, gross margin for the quarter rose by a total of $0.10 per share, driven primarily by a $0.17 per share increase from recontracting 8.4 terawatt-hours of 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 $0.01 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 at 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 a capacity factor of 100%. For the full year of 2023, PSEG is forecasting generation output of 30-32 terawatt-hours and has hedged approximately 95%-100% of this production at an average price of $31 per megawatt hour. For 2024, PSEG is again forecasting nuclear baseload output of 30-32 terawatt-hours, and has hedged 75%-80% of this output at an effective price of $37 per megawatt hour. The forecast non-GAAP operating earnings for PSEG Power and others unchanged at $200 million-$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 31st, 2023, PSEG 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. PSEG Power had net cash collateral postings of $700 million at March 31st, primarily related to out of the money hedged 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 experienced during 2022 and remain 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, the 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. PSEG Power had outstanding a $1.25 billion variable rate term loan expiring in March 2025. In total, $1.05 billion of Power and 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 LaRossa mentioned, we are reaffirming PSEG's 2023 non-GAAP operating earnings guidance of $3.40-$3.50 per share, with regulated operations at PSE&G forecasted to contribute $1.5 billion-$1.525 billion, and PSEG Power and Other forecasted at $200 million-$225 million, noting that PSEG Power and Other has realized the majority of the expected annual price increase in recontracting during the first quarter of 2023. That concludes our formal remarks. Operator, we are ready to begin the question-and-answer session. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community. If you have a question, please press the star and the 1 on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing the star and the 2. If you're on a speakerphone, please pick up your handset before entering your request. One moment please for the first question. Thank you. Our first question is from the line of Shar Pourreza with Guggenheim Securities. Please proceed with your question. Hey, guys. Good morning. Morning, Shar. Good morning. First question is 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, you know, we kinda see a very attractive cash pay convert market unfolding, you know, 5-year terms, low 3% costs. Could that sort of benefit be accretive to that 5-7 you guys reiterated today, especially since you do embed a higher interest rate cost step up? Yeah, Shar, thanks for that. I will give it to Dan in a second here. We're never gonna walk away from an opportunity to save a few dollars, which is what you're referring to there. Mm-hmm ... we wouldn't do that. I also think there's a fine line there that you have to watch from being too cute to being folks thinking that you're actually issuing equity. I guess every one of those deals are different, and we look at it in how it's structured. We don't need to issue equity, and I just wanna be certain that anything that we did to look at that would not be done in that light. Dan, you wanna add? Yeah, I think that's the right theme. Shar, we obviously are gonna consider all options and we do on a regular basis when we try to look at how we finance the business. I think it probably is a better fit for somebody who has an equity need coming up. Obviously, we would look at it the same way that we would look at anything else to make sure we're financing efficiently. Perfect. That was very clear. 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. I wonder if you, if you think it could be more accretive to hold on to some of those leases for a, you know, more competitive process and maybe more stable capital market environment there. Thanks. Yeah. I don't know that you can perfectly time the market. I do know, you know, that acreage that we do have is off the coast of Maryland. Maryland just upsized their targeted offshore wind. New Jersey has done the same. Those are, I think, probably the two markets that those acres would serve the best. I think you'd look at it from an operating perspective and from a market perspective, I should say, as to when you were gonna execute on that sale. You know, when they come in, I think it's just gonna be part of general corporate funds. Probably 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 see needed. It's not like we're gonna, 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. It's not like that's gonna be required from a timing perspective to do what we need to do to fund the capital plan. I think that's all sound, and I think it's just gonna go back and be part of the overall financing plan. Got it. fantastic, guys. Kudos on today. We'll see you soon. Thanks, Shar. Have a good one. Thanks, Shar. The next question is from Durgesh Chopra with Evercore. Please proceed with your question. Hey, good morning, team. Thanks for giving me time here. Hey, just, Dan, quick clarification on the proceeds from the lease. That would be all incremental to the current CapEx plan, right? I just wanna be clear, on that front. Yeah. Yeah. It's... Look, you know, we shouldn't overplay the magnitude of what that's gonna look like. It's gonna be great, but it's not gonna 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. 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? Yeah, 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, with the same purpose, to dampen the volatility that we would have within the pension. I think things are continuing productively, there's nothing new to report. Don't take the absence as if, you know, it's off the table. It remains something worth pursuing. Got it. That's very clear. 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? Yeah, Durgesh, it shook out exactly the way we expected it to. We're you know, 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 or opportunities we have require us to thread a needle to execute the plan that we have in front of us. You know, that confidence, I hope, comes across in both the way that we're answering and with the optionalities that we have. It does. Well done, guys. Thanks so much. Thanks. Thanks, Durgesh. The next question comes from Julien Dumoulin-Smith with Bank of America. Please proceed with your question. 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 in 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. Yeah. I'll give it to Dan to give you because he's got that trading operation. I just do want to reinforce that there's still some uncertainty out there in the outyears, you know, until we get the rules back from Treasury. What we are describing there though is what we expect to have. Dan, you could fill some more details in there. Yeah, Julien, you know, 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. You could see some movement within a fairly bounded range for what we do. You know, the quarter started with some higher prices, ended with an uptick, and in the middle had a drop-off. I think that we did a nice job of capturing some decent pricing. The other thing I would say, though, that you don't wanna lose sight of is that, you know, not everything is robotically across the year as well. 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. To your question, I do think that we did a nice job in moving forward and capturing some value. 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. Just to clarify that commentary. Basically, this is more about hedging on-peak versus off-peak, than it is anything tied to IRA or otherwise. Again, you did a nice job commercially, hedging, but you wouldn't necessarily say that this is anything in terms of a change of methodology, importantly. You got that last part is the most important point, that we said that we are kind of continuing on our path, similar methodology 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 know, 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, you know, and seasonal, versus calendar hedges and things of that nature. On balance, definitely a good quarter from a value perspective as we step through time. Got it. Super quick, if I can. You alluded to these plans that you're developing proposals for around the 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? Especially any thoughts about a parallel higher load forecast with that and the timeline there. Yeah. Julien, I think all of that's gonna play out over the next 12-18 months on multiple fronts. First, we have to get agreement on that load forecast that you said. I continue to believe that the current load forecast that we see from PJM is light. Like, not a big impact to us, again, because we are decoupled, which we've seen the benefit of this year. 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 though, you know, 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 it 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. Excellent. Good luck, guys. Speak soon. Thanks, Julien. Thanks, Julien. The next question is from Travis Miller with Morningstar. Please proceed with your questions. Good morning, everyone. Thank you. Hey, Travis. Travis. I know it's really early in the process, but I wonder if you could characterize the discussion and issues that might come up on the GSMP3 filing so far. Sure, Travis. I think you said the key though, which is it's so early in the process right now. We still don't have any red flags as far as what we've seen and in the conversations that we've had with the regulators. We're confident at the end of the day that we'll get, you know, a similar run rate to what we have currently with our GSMP2 filing. 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, you know, stop any gas installations. There's no intent at this point to stop stoves from being tied into gas. 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 as to where policy will be heading in the state. Mm-hmm. You're not taking anybody's stoves away? Yeah, no. I mean, there's no plan on that. you know, look, we gotta be careful on all of this 'cause, you know, that process is confidential, right? Yep. 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. Yes, just joking on that one. Perhaps I should have asked this first, but, how early is it in the process? What, what kind of timeline are you thinking about? Yeah, we usually talk about those things in the 12-month-plus timeline for a filing like that. I think we're only a couple months into it yet. Yeah, March. They just named a presiding officer at the BPU for this filing. I think, you know, we're 12 months plus away from- Early innings any decision. Early innings for sure. Yeah. Okay, great. Thanks so much. Appreciate it. The next question is from the line of Andrew Weisel with Scotiabank. Please just give us your question. Hi, good morning, everyone. Good morning, Andrew. First question on the new four-year labor agreement. First of all, I'm glad you had more success than the Hollywood writers did. My question is, given the inflationary pressures, how do the cost structures compare to prior deals, and how will that affect customer bills? Andrew, a couple things there. Let me, let me start backwards with the customer bills. I think there's been a few reports out that I just would encourage everybody to take a look at. You know, New Jersey from 2021 to 2022 was, I think the fourth lowest state in the U.S. as far as residential electric rate increases. 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. Kudos to the BPU on that and the process that's been in place. Because of that rolling nature, you know, any kind of increase that we would have is gonna be minimal to start with. That said, labor is a large component of our O&M, and the largest component of our O&M expenses within the utility. It will be a piece that goes into our rate case filing that we have. The 4% increase that we were able to negotiate, and 3% in the out years is 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. The fact that, you know, in prior years, when we had a 3% labor increase and inflation was at 1%-2%, the unions recognized that. The unions recognize now when inflation is higher than 3%-4%, they had some benefit in prior years. 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, 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. Exactly what we expected and should give you some confidence and others on the call as to our O&M projections in the out years, because it is the biggest component of our expenses. Great. That's very helpful. Yeah, 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? 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? 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 New Jersey Turnpike rest stops. We're seeing it in some of the large commercial organizations that were just granted approval by the BPU that will install the charging infrastructure. That activity has started. And, you know, we're gonna keep an eye on that and see about what kind of capital is required for each one of those installations on a standalone basis. It'll help with some projections going forward, but it's just a start. As far as load increases go and individual residences, we'll know more about that as we deploy AMI. We have our AMI 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 connecting their EVs. We had an engineer that had worked here for... He 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. It'll happen. It'll happen sporadically, and then it'll take off just like that deployment took place you know, we'll 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 this first set of grants came out from the BPU last week, so. On the affordability side of things, Andrew, too, I think that, you know, there will be infrastructure improvements that'll need to be made. You know, that last mile of our system is pretty dated. There's a lot of work that'll need to be done. I think part of what you're gonna see is a shift where a piece of the wallet that used to end up at the gas station is gonna end up on the electric bill. That helps things as well. That's only for the commodity because again, as you mentioned from the CIP, we're not gonna collect any more for the pipes or the wires other than for what we deploy additional capital on. Okay. Thank you very much. Thanks, Andrew. The next question is from the line of Paul Patterson with Glenrock. Please proceed with your question. Hey, good morning. Good morning, Paul. You mentioned the selection of the offshore wind injection point. I'm just wondering if you could elaborate a little bit more what that actually might mean for you. If you could just elaborate a little more on that, I guess. Yeah, sure, Paul. 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. 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 to 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'm 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 Deans substation. I wouldn't go beyond that at this point, but I'm happy to see 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. Our engineering team has done a really nice job of readying the system for what might come, and here it is. Is there any potential, I guess when we talk about inside the fence, do you have any number about how much that might be? No, Paul, I wouldn't know. We won't know until we actually see the size and magnitude of what comes in there versus, you know, down to the area JCP&L just is rebuilding and maybe even some down in the Atlantic City Electric territory. A lot of flow is to be figured out by PJM between now and then. Okay. That's something to watch, I guess. With respect to the going from an 18-month fuel cycle to a 24-month fuel cycle, can you tell us what the potential impact of that might be, I guess, starting in 2025? well, from a capital expenditure standpoint, I think we told you it's gonna 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 will be some savings in O&M that we'll have as a result of that. We're also obviously gonna get additional megawatts. We have not... I don't think we've published that anywhere yet, so I'd stay away from disclosing any of that information until we get the engineering completed, which is what that $30 million... You know, there's 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're gonna interact with each other. As that's completed, then we're gonna tell what additional power we're gonna get out of the unit. Okay, great. Thanks so much. The next question is from the line of Ryan Levine with Citi. Please proceed with your question. Hey, Ryan. Hi, how are you? Good. 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? Yeah, we'll give that one to Dan. Yeah. Ryan, I the, there's really no change in schedule. I think we think about it as being a 23 event, but we'll continue to watch what's going on. We'll continue to watch the, what the market looks for. There's a large deal announced today on that front. We'll make sure that as we do move forward, first and foremost, you know, continuation of benefits and certainty around all that and all that diligence that we're gonna do and that everything works well is gonna be super important. We'll also keep an eye on what the overall market conditions are to move forward on that. Appreciate the color. Then as in terms of Salem, what's the remaining process to extend the fueling cycle there? Are there any other capacity additions or changes to maintenance or refueling that you're contemplating in the near term? 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. More to come on that. We have not disclosed anything further than what we talked about at the investor meeting. Okay. Appreciate the color. Thank you. Thank you. Our next question comes from the line of Anthony Crowdell with Mizuho. Please proceed with your questions. Hey, good morning, Ralph. Good morning, Dan. Good day. Good morning, Anthony. Is your first comment gonna be congratulations, Devils? It was. Congratulations, Devils. There we go. Big win last night. Congratulations. I'm a little sad with my Rangers. I know. Most of my questions are answered. Just one super quick one. Following up on Shar question earlier on, I think the thought of maybe using a hybrid maybe for financing. I guess, are you guys forecasting additional debt at the parent to fund CapEx either at Power or the utility? Yeah, we gave a little bit of an 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. Over time, we do expect, as we continue to fund the capital plan that we have, we do anticipate some incremental financing over time. So, you know, when Char 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. Is it something that we would look at just to make sure we're not missing anything? I think that answer is yes. Great. That's all I had. Thanks so much. Thanks, Anthony. Thanks, Anthony. The next question is from the line of Ross Fowler with UBS. Please proceed with your question. Morning. Morning, Ross. I'll echo the congratulations, Devils, and my Bruins laid a big egg, so they cleared the way for you... Oh. For sure. Most of my questions have been answered. Just maybe a couple for you, Dan. Customer growth came in pretty good in the quarter, tracking around 1%. Yeah. Can you just kind of remind us with the SIP what you've assumed for customer growth in your, in your go-forward earnings growth guidance? Yeah. Less than or between 0% and 1% is kind of the range that we've assumed for customer growth over time. Again, that's number of customers. That's the important element for us, right? Right. Right. There was this $0.10 of expected tax carryback in your walk from 2022 to 2023. That ended up coming in in 2022. You know, what other things are now sort of in 2023, given the absence of that $0.10 that get you back to sort of your 2023 guidance range? Yeah. It's a great question. That $0.10 was not entirely the carryback, but that was the biggest chunk of it. That did come in early. What we're seeing in 23 really that offsets 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. A headwind from the former, a tailwind from the latter, and we're still in the same place from an overall guidance perspective. All right. Perfect. That's all I had. Thank you. Thanks, Ross. Thanks, Ross. I'll fill you in on my Panthers connection later. Thank you. The next question is from the line of Michael Sullivan with Wolfe Research. Please proceed with your question. Hey, Michael. Hey, hey, Ralph. How are you? Good. 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? 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? No. -using the Deans substation? 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're hearing now is that the work that we have been doing at Deans has readied our system already. We're in a little better place from a readiness standpoint at Deans. I think that you're 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." Our Deans substation switching station allows them to execute on that plan. Okay, that's very helpful. Then just in terms of the timeline for any spend related to this. Solicitation is next year. Yeah. Yeah. It's all end of the decade, Michael. We've been saying from the beginning, they'll go through the solicitation process. Again, they're still waiting for Treasury as well to figure out the tax rules. Once they get there, we will determine what's gonna be transmission, what's gonna be generator leads, and we'll be off to the races at that point. That still puts us at the end of the decade before anyone's deploying capital on this. Okay. Very helpful. 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? I think we said in March that there's about 95% of our overall revenues covered by the SIP, and there is some component that is not. We do have some variability, albeit much more on the smaller end. I think the variance you're talking about was $0.01. Mm-hmm. It was not a significant amount, but there is some element that falls outside of it, some of the larger customers, that's all. It's the I&C. It's a small piece of the I&C customer base. Right. Understood. Thanks, guys. Appreciate it. You got it, Michael. Our next question is from the line of Angie Storozynski with Seaport Global. Please proceed with your questions. Thank you. I know you guys covered this in detail during the analyst day, but I still wanna ask a question about the future of your nuclear plans. 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. My question is it just a question of timing in the sense that you're not ready yet to separate these assets? Or maybe there is no easy way to separate these assets without any tax leakage, so it could still come in the future? Or is it just a, you know, 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? 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 waver from that. So I just wanna be as clear as I can and crisp as I can be on 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're a great cash flow. They've been run really well, and they continue to be run really well. 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. You know, hopefully, you know, for across the board today, you're seeing that differentiation. Hard to think of a more valuable asset in these times, Angie. Yeah. I mean, I don't disagree. Lastly, so we're waiting for that guidance on nuclear PTCs, and it sounds like it's only gonna come in the fourth quarter. Like, what is the main question mark here? You know, what is it? Is it, you know, is it about below-market hedges? Is those getting, if those are gonna get recognized in that true-up associated with the nuclear PTC? I'm just wondering what is it that we're really waiting for. Yeah, I'll give it to Dan to give you some more details on this. Look, at the very high level, it's the definition of revenues and how that's gonna be treated by Treasury. Dan can give you a lot more. Yeah. I mean, just this is the mechanics of how it works, Angie. As I'm sure you know, there's a calculation of gross receipts and then a comparison to what the PTC threshold is, and the credit kind of fills that gap. How that definition is determined, and you went to exactly some of the areas that I would reference. 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? 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. That's what we're waiting on. I think that at the end of the day, we'll get a reasonable answer. I think that there's a significant support for what's there. I think Treasury's gotta work their way through what's gonna make the sense across units that are in various situations across the country. Okay. Lastly, you know, we've heard from Constellation, for example, that they are thinking about replacing some of the state support for their nuclear plants with that, with those federal subsidies. You know, in your case, I'm just thinking about it. The nuclear PTCs would accrue in 2024, but you would collect them only in 2025. New Jersey's ZECS expire in May of 2025. Is it fair to assume that it's unlikely that there would be any changes in the current structure given that, again, the payments roughly coincide with the expiration periods for the current ZECS? Yeah, Angie, I think those mechanics are still ahead of us to be worked out. I do think, you know, look, I think that all along, one of the things that we were saying that was so important is that we had a long-term solution for nuclear. I think that we were very happy to see that the PTCs did create that and honestly did create that at the federal level. 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. That's another element that I think is very important within this, and that's what we'll end up moving towards once this, the PTC amounts start to kick in. Awesome. Thank you. Operator, we're gonna conclude the Q&A session at this time, and I'll turn it over to Ralph for just the closing comments. Yeah. No, thanks. 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. 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 we've been able to achieve. We're just trying to build on 120 years of great history that we've been able to inherit. As we've said multiple times, we wanna leave it better than we found it. Thank you for calling in, and I appreciate the time. Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.