Carlotta Chan:

Good morning, and welcome to PSEG's second quarter 2024 earnings presentation. On today's call are Ralph LaRossa, Chair, President and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today's discussion are posted on our IR website at investor.pseg.com and our 10-Q will be filed later today. PSEG's earnings release and other matters discussed during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income as reported in accordance with Generally Accepted Accounting Principles or GAAP in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today's material. Following the prepared remarks, we will conduct a 30 minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Dan Cregg:

Great. Thank you, Ralph. Good morning, everybody. As Ralph mentioned earlier, PSEG reported net income of $0.87 per share for the second quarter of 2024 and that compares to $1.18 per share in 2023. Non-GAAP operating earnings were $0.63 per share in the second quarter of 2024, compared to $0.70 per share in 2023. Slides 7 and 9 detail the contribution to non-GAAP operating earnings per share by business segment for the second quarter and first half of 2024. Slides 8 and 10 contain waterfall charts that will take you through the net changes for the quarter-over-quarter and six month periods in non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported second quarter net income of $0.60 per share for 2024 compared to $0.67 per share in 2023. PSE&G had non-GAAP operating earnings of $0.60 per share for the second quarter of 2024 compared to $0.68 per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth in rate base from higher regulated investments, offset by higher investment-related depreciation and interest expense, awaiting rate recovery in our pending rate case, as well as higher O&M costs due to regulatory, safety and weather-related activities. Compared to the second quarter of 2023, electric margin increased by $0.02 per share due to customer growth in the Conservation Incentive Program or CIP. And our final Energy Strong II recovery, an energy efficiency investment of $0.01 per share higher. Other distribution margin added $0.02 per share, while transmission margin declined by $0.02 per share due to timing of revenue and O&M, including our annual true up. Ralph referred to the heat wave we experienced in June, and this warmer weather combined with greater storm activity led to higher corrective maintenance costs during the quarter. Distribution O&M expense increased by $0.04 per share compared to the second quarter of 2023, also due to higher gas meter inspections and safety costs. Depreciation and interest expense increased by $0.01 per share and $0.02 per share, respectively. Compared to the second quarter of 2023, reflecting continued growth in investment and higher interest expense. Lower pension and OPEB income resulting from the cessation of OPEB related credits, which ended in 2023 resulted in $0.01 per share unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to zero over a full year and other taxes had a net unfavorable impact of $0.03 per share in the quarter, compared to 2023. Summer weather in the second quarter as measured by the temperature humidity index was 42% warmer than normal and 99% warmer than the second quarter of 2023. In fact, the second quarter of 2024 was the warmest second quarter in our records going back 55-years, mostly due to that June heat wave. As a reminder, weather variations have minimal impact on our utility margin, because of the Conservation Incentive Program or CIP mechanism, which limits the impact of weather and other sales variances positive or negative on electric and gas margins, while helping PSE&G broadly promote the adoption of its energy efficiency program. The number of electric and gas customers, which is the driver of margin under the CIP mechanism continued to grow by approximately 1% each over the past year. On capital spending, PSE&G invested approximately $900 million during the second quarter and we remain on track to execute on our 2024 regulated capital investment plan of $3.4 billion. It's focused on infrastructure modernization and decarbonization initiatives. These include upgrades and replacements to our T&D facilities, last mile spend in the infrastructure advancement program, ongoing gas infrastructure replacement spending and the continued lean energy investments across EE, smart meter installation and EV make-ready infrastructure. We are reaffirming our five year regulated capital investment plan of $18 billion to $21 billion from 2024 to 2028. The high end of this plan includes the $3.1 billion CEF, Energy Efficiency II filing made in December 2023 that would enable commitments from January 25 to June 27 based on the BPU's EE framework. As Ralph said earlier, this proceeding is expected to be resolved at the BPU later this year. Moving to PSEG Power & Other. For the second quarter of 2024, PSEG Power & Other reported net income of $0.27 per share compared to $0.51 per share for the second quarter of 2023. Non-GAAP operating earnings were $0.03 per share for the second quarter of 2024 compared to non-GAAP operating earnings of $0.02 per share for the second quarter of 2023. In the second quarter of 2024, net energy margin rose by $0.08 per share, driven by nuclear, including the net impact of the nuclear PTC that took effect January 1st, 2024. Partially offset by the anticipated reduction in generation due to the Hope Creek outage and capacity revenue. As a reminder, for 2024, there will be a shape to our quarterly results as we move through the remainder of the year. We anticipate realizing most of the increase in the 2024 gross margin over 2023's gross margin during the second half of the year, specifically in the fourth quarter based upon the shape of our underlying hedges. This differs from last year when PSEG Power realized most of the step up in the annual hedge price in the first quarter of 2023. O&M increased by $0.05 per share, mostly driven by the scheduled refueling at our 100%-owned Hope Creek nuclear unit. Interest expense was penny unfavorable reflecting incremental debt at higher rates, and taxes and other were $0.01 per share unfavorable compared to the second quarter of 2023, primarily reflecting the use of a higher effective tax rate in the quarter that will reverse over the balance of 2024. On the operating side, the nuclear fleet produced approximately 7 terawatt hours during the second quarter of 2024 compared to 7.7 terawatt hours in the year earlier period and ran at a capacity factor of 82.7%. Nuclear generation in the first half of 2024 totaled 15.2 terawatt hours, which was impacted by the Hope Creek refueling, but also benefited from high capacity factor performance at our two Salem units, which operated at 98.9% for the quarter and at 99.3% for the first half of 2024. Touching on some recent financing activity. As of the end of June, PSEG had total available liquidity of $3.1 billion, including $113 million of cash on hand. Following the issuance of $1.25 billion of PSEG senior notes in March, during the second quarter, PSEG paid off $500 million of a 364-day term loan in April and $750 million of PSEG senior notes in June. With the PSEG term loan redemption in March, PSEG variable rate debt at the end of June consisted of a $1.25 billion term loan maturing March 2025, the entirety of which has been swapped out from a variable rate to a fixed rate to mitigate the fluctuations in interest rates. At the end of June, given our swaps, we had minimal variable rate debt. On the credit ratings front, in June, Moody's updated PSEG Power's outlook to stable from positive. And this change is consistent with our future plans for leverage and our targeted credit rating. We continue to maintain a solid Baa2 investment-grade rating at PSEG Power. In closing, we are reaffirming PSEG's full year 2024 non-GAAP operating earnings guidance of $3.60 to $3.70 per share. Which reflects continued rate base growth from ongoing regulated investments, offset by higher depreciation and interest as we await resolution of our pending distribution rate case later this year. We are also reaffirming our forecast of long-term 5% to 7% compound annual growth in non-GAAP operating earnings through 2028, supported by our capital investment programs and the nuclear PTC. This concludes our formal remarks and we are now ready to begin the question-and-answer session.

Julien Dumoulin-Smith:

Hey, good morning, team. Thank you, guys for the time. It's nice to chat again. Back in action, as they say. Look, guys, nicely done. Seriously, a bunch of questions here, what you guys just said. First off, just talking about the data center opportunity, as is the buzz these days. Can you elaborate a little bit on what you're seeing today about your co-located opportunities? And how do you think about the economic benefit criteria that you would and other stakeholders would like to see contribute to the local community here? Obviously, that's a key element of bringing jobs to New Jersey here. So, can you elaborate on that? And then separately related, how would you characterize demand for data centers outside of perhaps co-located opportunities in New Jersey today? Any kind of quantifiable commitment numbers or soft numbers that you would kind of see today that you care to share?

Julien Dumoulin-Smith:

Excellent, guys. And just quickly, if I can just to clarify on the excellent on efforts, should we say complaint with Talend here, does that shift at all, your thought process on any co-located opportunities just out here, but I'm just curious.

Julien Dumoulin-Smith:

All right, great. I'll leave it there. Talk to you guys soon. See you soon.

Shar Pourreza:

Hey, guys. How are you?

Shar Pourreza:

No, no, thank God. Rob, just to follow up on Julien's question on sort of the protests at FERC against the Susquehanna ISA. Obviously it's not gonna have a bearing on you pursuing a deal, right, with artificial island. But if the protest turns into a hearing, an NOI or an RTO process, do you kind of wait before signing a deal?

Shar Pourreza:

Okay, perfect. Now that's helpful. It's a question we've been getting from investors. And then just last thing, obviously, you guys noted that the 5% to 7% growth rate kind of remains exclusive of upsides on kind of the nuclear business. So outside of kind of this data center opportunity, I guess, what progress have you made to implement some of the other upsides, right? So, any thresholds we should be thinking about on uprates as we head into sort of FIDs and some of these.

Shar Pourreza:

Okay, perfect. I appreciate it, guys. And big congrats on the execution. We'll be seeing you soon. Thank you.

Michael Sullivan:

Hey, good morning. Hey guys. Can you just comment, are you having discussions with your local transmission utility on an ISA for artificial island right now?

Michael Sullivan:

Okay. And then just, I mean, you're in maybe a little bit of a unique position, and owning both unregulated generation and regulated transmission in PJM. And I don't think you all have kind of weighed in officially on the FERC docket, whereas it seems like the rest of the industry has. Any reasoning behind that or any thoughts you want to share on your views there?

Michael Sullivan:

Yep. No, that's super clear. I appreciate that. And then just, like, pivoting over to along the same lines with the states goals. Any stance on offshore wind in the state. Just in light of the Nantucket news up there, is it still kind of full speed ahead from the governor's standpoint?

Dan Cregg:

Yes. There's an ongoing solicitation now, Michael.

Operator:

Our next question is from the line of Nick Campanella with Barclays. Please see with your questions.

Ralph LaRossa:

Yes, I look again, and Dan, if he wants to add anything, is he's a little bit closer to this in his, in his role with the development team. There's nothing that's that specific at this point for us. I think, look, there's so many different factors that'll be involved here. It'll be the ramp up that'll matter. It's going to be whether or not -- I've even heard some of these data centers are considering being a demand response resource. And that would certainly change the dynamics of any conversation. There's just so much uncertainty now, Nick, as to where you would settle with anybody on any of these cases. I don't want to talk about sizing. It would be really premature.

Dan Cregg:

Yes. And there's assumptions that are embedded within our overall longer-term plan. But if you think about what we are from a generation perspective, the nuclear units' capacity is not a very significant component of the overall mix. And so, there's a -- it is not, our five to seven overall, from an enterprise perspective, is not terribly sensitive to what that is. We'll see what comes out here, I think, where the parameters seem to point. And a lot of what I've read shows things may be a bit more bullish than we've seen recently, but we'll find out what that looks like at the end of the day. I don't expect it to be significant enough to move us within, certainly outside of the range, and barely move us inside the range.

Ralph LaRossa:

Hey, Jeremy.

Ralph LaRossa:

Yes, I think we'll roll forward our capital plan at the end of the year, beginning next year, as we have in the past. So, any updates on that front will come there. Jeremy, I tell you, I think, look, I'll walk you through a couple of scenarios that we're seeing in the utility space itself. One is you'll have, if anybody's familiar with Northern New Jersey, there used to be a big Nabisco plant up in the northern part of New Jersey that doesn't exist anymore. Greenfield is there and it's near a 69 KV sub transmission line that we just built out, which is very close to a substation. I wouldn't expect a lot of capital required if someone was to locate something there. But if you are talking about a data center that's going to go into an old industrial site in one of the cities that has used up most of its capacity, and they've chosen that location because the construction of the building is such that they won't really need to put up much capital to support all the servers that are there and the floor load and everything else that exists. And I think that one might need a little more capital that's going to be involved and it'll be a little more complicated and we'll see where things play out. So, every one of them are different. Right now, I would say that it's a mixed bag as to what we're seeing and where things are falling out. But it's positive for us in the fact that we continue to see the growth that's taking place here, and we're attracting the businesses. A number of AI folks have been working with the state and we're excited about it. We're never going to be maybe as big as some of the other states are going to be, just by the geographic size that we are. But I think it's going to make a difference for us here.

Ralph LaRossa:

Yes, I think Dan just hit on a key point, Jeremy, the next PJM solicitation, I think it's referred to as Window One, is a good signal as to what's going to be required on the transmission side. Again, every last mile sub transmission, last mile investment will be different, but Dan's absolutely right. Watch that load profile change of PJM to see what's coming down the pike.

Ralph LaRossa:

Yes, again, we're seeing steady, slow but steady growth on the EV front. And proud to say we're not turning down any EV interconnections. We have the capacity, but we're upgrading that last mile. So that's really playing out exactly the way we expected it to. New Jersey is, again, a little bit unique in the condensed nature of our housing and our commutes. So EVs have not had the same challenges and pressure that maybe the rest of the country has seen as far as the expansion that was expected. So, we're kind of moving along at about the pace that we thought we would, and it's having the impact on the last mile as we had planned.

Ralph LaRossa:

No, I really appreciate you asking that. Look, I take it as a big compliment to the team here that we're this far in, and that was the first rate case question we got. So, the team is executing as we expect they would execute in those conversations. And the Board of Public Utilities, as I have been saying multiple times, continues to really run a very efficient and thoughtful process. So, I don't see there's no red flags there either. But I would point out that that recent COVID settlement that we just had was exactly the way we had thought it would play out. The fact that we expected the conversations not to become public has played out exactly that way. And so, I just very grateful for the way this has all been portrayed.

Operator:

Our next question is from the line of David Arcaro with Morgan Stanley. Please proceed with your questions.

Ralph LaRossa:

No, David, we really haven't gone there. I appreciate the question, but we just try to be thoughtful about everything and make sure that the folks that we talk to are people that are aligned with the policies we have here in the state.

Ralph LaRossa:

Yes, David. So, I referred to several hundred megawatts that are at what I would consider to be the very firm stage that we would have. And again, every utility looks at that a little bit differently. The other two stages are even more robust than the very firm stage. The leads and the initial engineering analysis that would be done here somewhat double or triple in each one of those stages. From what we're seeing in the firm construction side, that makes sense projects to look at, but we -- any roll forward that we have from a capex standpoint, we will do at the end of the year, as I mentioned earlier. So, we're just we're happy to see it taking place.

Operator:

Our next question is from the line of Carly Davenport with Goldman Sachs. Please proceed with your questions.

Ralph LaRossa:

No, I don't think, I don't see any real risk from an investment standpoint here. I think most of those interconnections are done at the distribution level. There's not an election that's going to impact the state of New Jersey until next November. So, I think the only question, and we've talked about this before, is -- will you have 100% EVs by 2035 or will we get a 50 on that test? And a 50 on that test is still going to be quite a bit of market penetration for the electric vehicle industry here. So, I'm not concerned about an election change. Maybe it'll impact some of the tax incentives and some of the other things that we have. But again, the uniqueness of our condensed and compressed service territory, I think will keep electric vehicles at the forefront.

Dan Cregg:

Yep. We're thinking about it quite a bit, Carly, and it's very topical, given what you mentioned within your question. And so, there's been a fair bit of work that's been ongoing to move forward and extend out over time. And I would expect that, I don't know, maybe when we're sitting here at the next call, we'd have a little bit of an extension there we'd be able to offer. So, we're aware of it on top of it. It's not the most immediate, urgent thing that's going on from the standpoint of actually producing power, but we always have a lead time that we're interested in and continue to move forward on that. So, we'll continue to push that data out and give updates as we do it.

Operator:

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

Ralph LaRossa:

Yes, I think that, Ryan, that we're in the middle of trying to settle at, we refer to it as EE2, I think will be that response that you're kind of inferring there that people are going to be looking at from a policy standpoint to offset some of the other data center and other load growth. So, the VPU has those filings from all the utilities here in the state, and they're taking a look at it. I think their timeline was the end of the year to reach, I think it was October timeframe to reach settlement. So, I think they're on track for that and looking for some consistency across all the utilities. So, again, completely aligned with the policy there. And I don't expect a big jump in the next couple weeks, ask for a new filing or anything like that. I would just keep an eye on the filing that is in front of them today.

Ralph LaRossa:

Yes, no, I mean, look, a feasibility study is where -- where we haven't gotten an official request to go out and buy the copper, the transformers, and start digging a hole to install a wire. So, our engineers are out looking to see whether or not those megawatts that are being requested can be supported. And it is, again, I think if you talk to every utility, we would refer to that differently with a different acronym, and it might be at different spots in the process. I would say our feasibility studies are the middle of the road for us. When it becomes real in that last couple hundred megawatts, that's what we consider to be a new business request, an official request that comes in, and then we have leads that are coming in all the time. But both the feasibility side and the leads are about triple right now, the actual new business requests that we've started to work on.

Ralph LaRossa:

Yes, I mean, the only time it would become a regulatory issue is if there was a concern that somebody turned down, whether it was a solar panel that was trying to get installed on one side or a data center because they didn't have the infrastructure to support it in a timely fashion. It might be a regulatory issue raised in that scenario.

Ralph LaRossa:

You talk about a hyperscale data center we're handling through Dan's team in the commercial development side.

Operator:

Our next question is on the line of Sophie Karp with KeyBanc. Please proceed with your questions.

Ralph LaRossa:

Yes, I think the data center that's co-located, that doesn't exist right yet needs to be built. And so that's going to take some time, and that time is going to basically at some point, cross over what you're looking at from a BRA. But I think where we are right now, we're either not there or we'd be adjusted at the very [indiscernible]. So, I don't think that that's quite hit a crossover point yet. So, I don't think that's really critical to where we are.

Operator:

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

Ralph LaRossa:

Andrew, it's a great question, but one that we haven't really discussed. And obviously we were being talking to folks and would give a handle as to what other people are thinking about. So, I don't want to go down that path, but I would just say to you, qualitatively, I mean, big picture. Yes. I would simply say to you this. Any data center that comes in, each one of them have a unique configuration and design. Some of the data centers would be comfortable with multiple stories. Some are not comfortable with multiple stories. Some have certain cooling needs, others have different cooling needs. So, each one of them, it'd be really hard pressed to say one acre of land equals this many megawatts, and we're seeing multiple designs, whenever we would have a conversation with anybody, and they think about it. So, I kind of sidestepping that specific question, but really think that's better left for the negotiating team and any conversations they're having with developers.

Ralph LaRossa:

Yes. So again, I'll put on a couple different hats here, one of which is actually even a customer hat. I would say to you this, first of all, the ZEC program ends next March. So, start from -- next May, I'm sorry. So, start from that scenario so that we would certainly, there won't be any conversations or that would take place that would -- we would benefit from a data center before then. Second, I think any company would be very hard pressed asking for a subsidy on top of a revenue stream that was similar to what was we think was just negotiated at Talend. And I'll leave my comment there. That's my customer hat being on. I would be hard pressed to think that you would pancake that on top of something else, whether it be the state subsidy or a federal subsidy. Federal PTC, we don't know what the definition is yet for gross revenues. And when that comes out, we'll certainly take a look at it. Again, I would be hard pressed to believe that they're going to allow a PTC payment on top of X dollar payment per megawatt hour that we're seeing in the marketplace. So, there's a lot of TBDs in what I just laid out for you, but there's also a little bit of just reality. And I would not be thinking that we'd be asking New Jersey ratepayers to be subsidized in tech companies. In fact, I would probably step in front of that conversation myself personally.

Ralph LaRossa:

I don't -- well, again, look, I never want to say never, but I wouldn't. I can't see any other scenario.

Operator:

Thank you. Our next question is from the line of Anthony Crowdell with Mizuho Securities. Please proceed with your questions.

Ralph LaRossa:

Yes, Anthony. No, it's a great question, and it's one that we've been thinking about since 2008, right. We always go back and take a look when commodity prices were much higher and make sure that any projections that we have do not put us in that position. I've said it multiple times, and I'll say it again. Because of the good economic development work that we've done in this region, not just in this state, but in this region, the income has continued to do pretty well. And if you look at the share of wallet or pocketbook that anyone would have to put up to pay their utility bills, it's been pretty consistent over the last 20 years. So, I would expect that to remain the same. There's a lot of that information that's in our IR materials that we've gone over a bunch of times with you. So, I don't see anything that's on the horizon. Even in some of the conversations that are taking place that would lead me to believe that we're crowding out the required utility investment that's going to have to take place if we're going to have all this electrification.

Anthony Crowdell:

Great. Thanks so much for taking the question.

Bill Appicelli:

Hi, good morning. How are you doing? Just similar line of questioning of Anthony there, but just maybe around the demand and supply balance in PJM. So, going back to the point of you kind of being on both generation front and on TD, I mean, how are you viewing the demand growth broadly, whether it's behind the meter or otherwise? You did make that comment earlier about proliferation of colocation deals going forward in other sectors. I mean, do you have confidence in the current PGM process to ensure adequate reliability?

Bill Appicelli:

Right. I guess maybe to that last point then, I mean, some companies within PJM have contemplated maybe pursuing legislation that could allow for regulated generation and rate base at some point. Right. If you feel like the system isn't.

Bill Appicelli:

Well, I guess the question is for you, right? I mean, would that be a path you would ever consider?

Bill Appicelli:

Understood. Thank you very much.

Operator:

Correct. Yes. I was just going to hand the floor back to you for closing comments.

Operator:

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

Carlotta Chan :

Good morning and welcome to PSEG's first quarter 2024 earnings presentation. On today’s call are Ralph LaRossa, Chair, President and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today’s discussion are posted on our IR website at investor.pseg.com and our 10-Q will be filed later today. PSEG’s earnings release and other matters discussed during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income as reported in accordance with generally accepted accounting principles, or GAAP in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today’s materials. Following the prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Dan Cregg :

Thank you, Ralph. Good morning everyone. As Ralph mentioned earlier, PSEG reported net income of $1.06 per share for the first quarter of 2024 compared to $2.58 per share in 2023. Non-GAAP operating earnings were $1.31 per share in the first quarter of 2024 compared to $1.39 per share in 2023. We provided you with information on Slide 7 regarding the contribution to non-GAAP operating earnings per share by business for the first quarter, and Slide 8 contains a waterfall chart that takes you through the net changes quarter over quarter and non-GAAP operating earnings per share by major business. Going with PSE&G, which reported first quarter net income of $0.98 per share for both 2024 and 2023, PSE&G had non-GAAP operating earnings of $0.98 per share for the first quarter of ‘24 compared to $0.99 per share in 2023. The main drivers for both net income and non-GAAP results for the quarter were growth and rate based from continued investments in infrastructure replacement offset by higher distribution, investment-related depreciation and interest expense, not yet reflected in rates as well as higher O&M costs compared to the first quarter of 2023. Margin was $0.07 higher in total driven by transmission at $0.03 per share, gas margin at a penny per share and other utility margin added $0.03 per share. Distribution O&M expense increased $0.05 per share compared to the first quarter of 2023, primarily due to gas meter inspections and overhead corrective maintenance following severe rain, wind, and flooding events early in the year, and tree trimming. Appreciation and interest expense increased by a penny per share and $0.03 per share respectively compared to the first quarter of 2023. Reflecting continued growth and investment, these costs of weight recovery in our pending distribution rate case anticipated to be settled later this year. Lower pension and OPEB income resulting from the cessation of OPEB-related credits, which ended in 2023, resulted in a penny per share, unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an annual effective tax rate, which nets to zero over a full year had a net favorable impact of $0.02 per share in the quarter compared to 2023, whether during the first quarter as measured by heating degree days was 17% warmer than normal, but 9% colder than the first quarter of 2023, which was the warmest first quarter in PSE&G’s records. As we've mentioned, the conservation incentive program or SIP limits the impact of weather and other sales variances positive or negative on electric and gas margins. While helping PSE&G broadly promote the adoption of its energy efficiency programs. The number of electric and gas customers, which is the driver of margin under the SIP mechanism, continue to grow by approximately 1% over the past year. On capital spending, as Ralph mentioned, PSE&G invested approximately $800 million during the first quarter, and we remain on track to execute on our 2024 regulated capital investment plan of $3.4 billion focused on enter on infrastructure modernization and electrification initiatives. These include upgrades and replacements to our T&D facilities, last mile spend in the Infrastructure advancement program, ongoing gas infrastructure replacement spending, Energy Strong II investments, and the continued rollout of the clean energy investments in EE, smart meter installation, and EV make-ready infrastructure. We are reaffirming our five-year regulated capital investment plan of $18 billion to $21 billion. This 2024 to 2028 plan includes the $3.1 billion CEF EE2 filing made in December, 2023, which would enable commitments starting January, 2025 through June of 2027. Based upon the BPU’s EE framework with investments being made over a six-year period. This proceeding is expected to be resolved at the BPU later this year. Moving on to PSEG Power and other, for the first quarter of 2024 PSEG Power and other reported net income of $0.08 per share compared to $1.60 per share for the first quarter of 2023. Non-GAAP operating earnings were $0.33 per share for the first quarter of 2024, compared to non-GAAP operating earnings of $0.40 per share for the first quarter of 2023. For the first quarter of this year, net energy margin rose by $0.03 per share, including $0.02 favorable contribution from nuclear driven by the net impact of the nuclear production tax credit, which went into effect January 1st of this year, partially offset by reduction in capacity revenue. Also, in energy margin gas operations increased by a penny per share compared to the year earlier quarter. Importantly, for 2024, while the PTC begins this year, there will be a shape to our results per quarter as we move through the year. We anticipate realizing the majority of the increase in the 2024 gross margin, over 2023s gross margin during the second half of the year based upon the shape of our underlying hedges. This will differ from last year when PSEG Power realized most of the step up in the annual hedge price in the first quarter based on lower pricing in the winter of 2022 compared to 2023. O&M increased by $0.03 per share, mostly driven by the start of the scheduled refueling at our 100% owned Oak Creek nuclear plant. Interest expense was a penny unfavorable reflecting higher interest rates partially offset by lower short-term debt balances. Taxes and other were $0.06 per share unfavorable compared to the first quarter of 2023, primarily reflecting the use of a higher effective tax rate in the quarter. That will reverse over the balance of 2024. Operating standpoint, the nuclear fleet produced approximately 8.2 terawatt hours during the first quarter of 2024 compared to 8.4 terawatt hours in the year earlier period, and ran at a capacity factor of 96.8%. Our Hope Creek Nuclear Unit is undergoing its scheduled refueling outage, which will include preliminary work on the fuel cycle extension project. As a result, as is always the case with outages for our a hundred percent owned Hope Creek Unit, we expect a little higher O&M and lower generation in the second quarter. Touching on some recent financing activity at the end of March, PCG had a total available liquidity of $5 billion, including $1.2 billion of cash on hand. Our revolving credit facilities totaling $3.75 billion were also extended by one year to March of 2028. During the first quarter at the end of March, PSEG had $500 million outstanding of a 364-day variable rate term loan, which subsequently matured in April of 2024, and PSEG Power had $1.25 billion outstanding of a variable rate term loan maturing March of 2025. The entirety of these term loans were swapped from a variable rate to a fixed rate, mitigating the fluctuations in interest rates as of the end of March. Given our swaps in cash position, we had minimal variable rate debt in early March. PSE&G issued $1 billion of 10 and 30 year secured medium term notes consisting of $450 million at 5.2% due March, 2034 and 550 million at 5.45% due March, 2054. A portion of the proceeds was used to pay the maturity of $250 million of 3.75% secured MTMs on March 15th. Later in March, PSEG issued $1.25 billion of senior notes consisting of 750 million at 5.2% through April 2029 and 500 million at 5.45% due April, 2034. A portion of the proceeds will be used to pay the maturity of $750 million of 2.875% senior notes in June. We continue to maintain solid investment-grade ratings. Looking ahead, we expect that PSEG's considerable cash generation combined with PSEG powers enhanced cash flow visibility from the nuclear PTC will support the execution of PSEG's five-year capital spending plan dominated by regulated CapEx without the need to issue new equity or sell assets. In closing, we are reaffirming PSEG’s full-year 2024 non-GAAP operating earnings guidance for $3.60 to $3.70 per share, which reflects continued rate-based growth from ongoing regulated investments offset by higher depreciation and interest expense that will build over the balances of 2024. As we await resolution of our pending distribution rate case later this year, we are also reaffirming our forecast of long-term 5% to 7% compound annual growth and non-GAAP operating earnings through 2028, supported by our capital investment programs and the new nuclear PTC. That concludes our formal remarks, and we are ready to begin the question and answer session.

Nicholas Campanella :

Thanks for all the context around the direct power sales opportunities with your nuclear facilities. Can you just kind of comment on the potential, just the timing around any potential announcement and then how we should kind of think about when that could contribute to EPS if it were to be achieved. Then just, I know you kind of talked about being in like the nexus between economic development and energy policy. Is there something that you're looking for from the state before moving forward with this? Or just what are the data points that investors should be looking for to know whether this is becoming more of a reality or not? Thanks.

Nicholas Campanella :

I appreciate that. I guess, I think you also said in your remarks that you would maybe provide an update later in the fall. I guess that would be, dependent on how the rate case kind of progresses, but to the extent that you're giving a refreshed kind of financial outlook, when would that be? And then also is the data center opportunity something that could be included in that, or it would really kind of be post that ‘25 and beyond?

Operator:

Our next question is from the line of Jeremy Tonet with JP Morgan. Please proceed with your question.

Ralph LaRossa:

Jeremy, I think, it's really my advice is to keep a very close eye on the PJM -- process as they continue to re-evaluate the topology of the transmission grid. I think there'll be opportunities across the PJM footprint. Look, you got to just take a look at what happened at with -- as a very simple example. That power plant was connected to our Susquehanna Roseland line. That power, at least a hundred megawatts or so of it won't be flowing out of the power plant into the grid. And so that'll have an impact on the topology in a very simple term. Then you've got data centers popping up in different locations. We have a number of requests that have come into our utility that we're processing not of the magnitude of a hyperscale, but smaller edge-type computing solutions. And so, each one of those will have an impact and the place where it all comes together, and I would encourage you to take a look at is through that -- tech process. Offshore wind will be one of the generation solutions for it, but there will be need for additional modifications to the grid and it's a TBD for all of us.

Operator:

Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Dan Cregg:

To guess, I wish I had a better answer for you, but we continue to wait for guidance to come out of treasury. I know that there's been a host of different approaches to treasury to try to spur some information to come out. But I know that you know that the PTC began January 1st, so we are in it. And I continue to think that the most important definition is as we've all thought about it, is the definition of gross receipts. And so that's what we're waiting for more than anything else. I think we're moving forward. We're finding out a little bit more about what ‘24 looks like every day that goes by in ‘24. And we continue to do what we've been doing is trying to think about what different potential outcomes could come from treasury and try to position ourselves as ideally as we can against the backdrop of that uncertainty. And I think we're doing fine there, but we would prefer to have it. I don't have a date for you. I don't have an estimated date. And I've not heard that one is forthcoming. So, I think we're in the same boat. I think we're just waiting.

Dan Cregg :

Yes. I think that's exactly right.

Dan Cregg :

Yes, and we've talked about, it's going to come off of the FFO to debt. And I think that, one of the things that when you did see that increase in capital that you referenced, there are different FFO to debt implications depending upon exactly what the capital it is. And kind of on the opposite ends of the spectrum, our energy efficiency program has a recoverable life, depreciable life, amortizable life, whatever you want to call it, closer to 10 years to 12 years and are more infrastructure-oriented investments have a longer, recoverable life. And so, when you look at those particular investments, you're going to see much less of an impact on your FFO to debt. Because you're going to see a lot of cash coming back to you quicker. To the extent that it's EE benefits, that's something that's more steel on the ground, whether it's on the transmission side or electric or gas side. And then to your other point, I totally agree with your comment that, on the power side it would be capital light, but it could be FFO positive in a fairly significant way. So, those are the elements that move around. If we're in the mid-teens, our current threshold for where we are is 13, 14, depending upon whether you're talking about Moody's and S&P. So, we've got some room in there, but I think it's not -- it's going to depend a little bit on the nature of the investment and I think as you saw more of that increase coming from EE of late, it was more credit friendly for us to move in that direction.

Shar Pourreza:

It's actually Constantine here for Shar. Thanks for taking the questions. I really appreciate the commentary on the nuclear opportunity. Maybe a bit of nuance from your perspective, is behind the meter a scalable opportunity for data centers in New Jersey, or is it a bit more kind of one off as you look at it? And maybe as you mentioned, there's a level of potential grid dependence and do you see that becoming a concern at all for regulators or is that kind of getting addressed in other forms, regulatory forms?

Dan Cregg:

It's a great question, but if I try to think about exactly then the nature of how you're asking, I think that by definition, if you're going to do something behind the meter, you're going to do it at scale. And so, I think that you wouldn't move into that situation with something that was not of scale and grow at the scale other than the natural fact that I think you're not going to have a data center of scale appear immediately. And so, it's more likely, and from what we have seen, you would see something that would be agreed to be upscale that would come in over time.

Shar Pourreza:

That's abundantly clear. And maybe as we look a little bit more broadly at just supply and demand in power markets and power prices are now well north of the PTC levels for the ‘25, ‘26 trip, which kind of continued to be the PTCs that were the core planning input. Do you plan to update guidance as you kind of recontract or start realizing those revenues and do those become ACC creative to the credit metrics and kind of the investment capacity that you talked earlier about?

Ralph LaRossa:

And just a reminder, Constantine, the highly visible and liquid PJM West top is not necessarily reflective of the entire PJM marketplace. So those numbers aren't dead on for everybody.

Carly Davenport:

Maybe just on the Hope Creek outage, you mentioned that you're doing some of the initial work on the kind of fuel cycle shift there with the outage. Could you just talk a little bit about sort of the scope of what's getting done and how much will be left in order to make that shift as we get to 2025.

Carly Davenport:

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

Operator:

Our next question is from the line of Andrew Weisel with Scotiabank. Please proceed with your question.

Ralph LaRossa:

Yes, Andrew, I think, look, you can look at what happened at Talend as a placeholder for size of units at hyperscalers are thinking about. Just a reminder, our state plan kind of ends in May of '25, right? So, we're -- I don't see a data center being built before May of '25 down at that site. We may be in discussions with folks and have something to say sooner than that. But I don't expect any power to be flowing into a data center before May of 25 when that program ends. And then we'll see what the rules say on the IRA and how the PTCs interact with any of this kind of agreements that are reached.

Ralph LaRossa:

I think, the entire portfolio could be available for long-term contracts. And again, I think that that falls into a bunch of different scenarios. I don't think there's anything that's a restriction and we'll continue to work forward and keep you posted.

Ralph LaRossa:

Andrew, it's kind of simple as to why the dollar per megawatt saved goes up. I mean, you're going from changing light bulbs, which was the first effort that we started way back when and thermostat changes to now you're upgrading HVAC units and moving into commercial and industrial operations. That's very different just from a dollar per megawatt hour save standpoint. As far as the pushback, this was all part of the BPU's triennial, so a lot of what was submitted was based upon the needs identified by the Board of Public Utilities and really are not a surprise. The question will be just from a total spend standpoint, how far they would like to go. I don't think there'll be a lot of arguments about the cost per based upon one historic performance, which has been really good. And then second the types of work that we'll, the type of work that we'll be doing going forward. Andrew, also, within what the BPU -- I think to their credit, they tried to take a philosophy in approaching this, that they wanted to target things through this program that they viewed would not happen otherwise. And so, these light bulbs is an example of that given that incandescent are off the shelf, but in other examples too things that were going to happen anyway are not a great target for this kind of a program is to try to expand what would otherwise happen. And so that I think expands the reach a little bit moves them to a better place, but may cost a little bit more to get it done.

Steve Fleishman:

Sorry, another nuclear question. We've talked about this hypothetically the last -- let's say six, nine months hydrogen, I think there's supposed to potentially be like offshore wind port next to the plants around there, and then obviously data centers. Now just should we think about these as things, all things you can do there or you have to kind of focus to one and data centers is now kind of top of the list?

Dan Cregg :

An on the hydrogen front, Steve, as just a reminder, an upgrade there would meet both additionality and hourly matching to the extent that those limitations continue on hydrogen. So, I do think we feel pretty good about what we have the ability to do down there and don't see limitations on having to pick one or the other.

Ralph LaRossa:

Yes. So, Steve, that power flows a whole bunch of different ways, right, not just in New Jersey, but other states, right? So, it's more of a PJM question as to that specific unit in those specific megawatts. But I will say this, and what we've set it in multiple settings, I apologize if it's a repeat, but that 2003 blackout gave us the opportunity to rebuild the transmission infrastructure and we did that. And as Sandy comes along when we rebuilt the switching stations and substations. So, we're well prepared for this. I think New Jersey is uniquely prepared and I've got my economic development hat on here for a second, but I think we're in a really good place. and the margins aren't quite as tight as some others might have. So, I think we're looking at this and trying to figure out what's the best solution for the state and we're doing it in a partnership that one-off of the states plans. So, we feel pretty good.

Ryan Levine :

Had a, I guess, one or two more on nuclear. In terms of the duration of contracts that your counterparties may be willing to sign. I think in your comments, you mentioned long term, any color you could share around how long term is as you look at it? And then to the extent that there's transmission constraints in PJM, how does the timeline of any investment there play into ability to serve that longer term?

Ryan Levine:

And then to follow-on the last line of questionings, to the extent that there is policy opportunities to maybe attract this customer base to the state, are there any legislation initiatives that you're keeping an eye on that may make it more palatable for other stakeholders to attract this load to the service territory?

Operator:

Our next questions are from the line of Travis Miller with Morningstar. Please proceed with your question.

Ralph LaRossa:

Travis, I would simply tell you way too soon for us to be talking about anything like that. We're not in a position to talk about any details of any discussions. I would say this to you though, we've answered the question a bunch of times. And I'll tie it back to the hydrogen opportunities. We don't want to get into the commodity risk commodity risk situation. What we basically look at this is, we put a meter at point A and folks can pick it up from there and figure out what they're going to do with the electricity. And I don't see data centers or electrolyzers or anything else that might happen in that space as different.

Travis Miller :

And then one other question on the transmission in your bids and proposals there. How much does what you proposed or put in those bids depend on a second round of offshore wind projects coming in, is any of it or some of it.

Travis Miller :

Okay. And would that be through the PJM process or through New Jersey process?

Operator:

Our last question is from line of Paul Patterson with Glenrock Associates. Please proceed with your question.

Ralph LaRossa:

No. I think -- look, there's 5 or 6 items that are there. We have some folks that are heavily involved in transmission in our wire’s organization, so many other ones. So, we're staying abreast of it. I think FERC has remained balanced under the current share. And I don't expect some wild swings in the outcomes there, but we're monitoring it closely right now, Paul, and I wouldn't have much more to add than that.

Ralph LaRossa:

Yes. So, some of that grid enhancing has really been focused. I think there was a New York Times article on it about the upgrades of some of the conductors that people have installed. And we've looked at some of that and piloted some of that. As we've talked about, we've done a lot of transmission upgrades. We've also built into our system, the ability to do some additional upgrades. But I think that just becomes a cost benefit for the consumer based upon what additional capacity we would get out of it and whether or not we wouldn't want to front run the need. So, it's something we'll monitor and it's something that PJM again, will have in their tool chest to make some determinations upon how they want to solve some of the gaps that might get created as we move forward here with electrification.

Ralph LaRossa:

I just simply want to thank you all for your continued confidence and support, we welcome all these questions and we really look forward to getting together with most of you at AGA later in May. Again, thank you to our employees, to our customers, and to and to our investors, and we'll see you all in California. Take care.

Carlotta Chan:

Good morning and welcome to PSEG’s fourth quarter and full year 2023 earnings presentation. On today’s call are Ralph LaRossa, Chair, President and CEO and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today’s discussion are posted on our IR website at investor.pseg.com and our 10-K will be filed later today. PSEG’s earnings release and other matters discussed during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income as reported in accordance with generally accepted accounting principles, or GAAP in the United States. We include reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements on our IR website and in today’s materials. Following the prepared remarks, we will conduct a 30-minute question-and-answer session. I will now turn the call over to Ralph LaRossa.

Dan Cregg:

Thank you, Ralph and good morning everyone. As Ralph mentioned earlier, PSEG reported net income of $5.13 per share for the full year of ‘23 compared to net income of $2.06 per share for 2022. Non-GAAP operating earnings for the full year of 2023 were $3.48 per share compared to $3.47 per share for 2022. For the fourth quarter of 2023, net income was $1.10 per share compared to $1.58 per share in 2022, and non-GAAP operating earnings were $0.54 per share for the fourth quarter of 2023, compared to $0.64 per share in 2022. We’ve provided you with information on Slide 7 and 9 regarding the contribution to non-GAAP operating earnings per share by business segment for the fourth quarter and full year of 2023. Slides 8 and 10 contain waterfall charts that take you through the net changes, the quarter-over-quarter and full year periods and non-GAAP operating earnings per share by major business. Starting with PSE&G, we reported fourth quarter 2023 net income of $0.58 per share compared to $0.70 per share in 2022. The PSE&G had non-GAAP operating earnings of $0.59 per share for the fourth quarter of 2023 compared to $0.70 per share in 2022. The main drivers for both net income and non-GAAP operating earnings results for the quarter were growth in investments in transmission and gas distribution. These favorable items were offset by the expected decline in pension income and lower OPEB-related credits as well as anticipated higher depreciation, amortization and interest expense resulting from higher investments, not yet reflected in rates and the timing of O&M in the quarter that was within our expectations for the full year. Compared to fourth quarter 2022, margin was $0.03 higher, driven by transmission at $0.01 per share, and gas margin also at $0.01 per share higher, primarily driven by the clause recovery of our GSMP investment. Other utility margin was also $0.01 per share favorable. Distribution O&M expense increased $0.05 per share compared to the fourth quarter of 2022, reflecting seasonality and operational timing. But for the full year, distribution O&M was flat versus 2022. Depreciation and interest expense each increased $0.02 per share compared to the fourth quarter of 2022, reflecting continued growth in investment. Lower pension income resulting from 2022’s investment returns, combined with lower OPEB credits, which ended in 2023, resulting in a $0.04 per share unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an effective tax rate, which nets to zero across the full year and other flow-through taxes had a net unfavorable impact of $0.01 per share in the quarter compared to 2022. Weather during the fourth quarter, as measured by heating degree days, was 15% warmer than normal and 13% warmer than the fourth quarter of last year. As we’ve mentioned, the Conservation Incentive Program, or SIP mechanism limits the impact of weather and other sales variances positive or negative on electric and gas margins while helping PSE&G broadly promote the adoption of its energy efficiency programs. Growth in the number of electric and gas customers, the driver for margin under the SIP mechanism has remained positive with each up by about 1% in 2023. On capital spending, as Ralph mentioned, PSE&G invested approximately $1 billion during the fourth quarter and completed its largest single year investment program at $3.7 billion for the full year. The program included upgrades and replacements to our T&D facilities, Energy Strong II investments, last mile spend in the infrastructure advancement program, ongoing gas infrastructure replacements via base and GSMP II spending, continued rollout of the clean energy investments in energy efficiency, smart meter installation and EV make-ready infrastructure. We recently rolled forward our 5-year regulated capital investment plan to 2028, amounting to $18 billion to $21 billion, which incorporates both the new $3.1 billion CEF-EE II filing as well as the $300 million expansion of the existing EE program through the end of 2024. For 2024, our regulated capital investment plan totals approximately $3.4 billion. Moving on to PCG Power and Other. For the fourth quarter of 2023, PCG Power & Other reported net income of $0.52 per share compared to net income of $0.88 per share for 2022. Non-GAAP operating loss was $0.05 per share for the fourth quarter of 2023 compared to a non-GAAP operating loss of $0.06 per share for 2022. For the fourth quarter of 2023, net energy margin rose by $0.05 per share after including lower capacity revenues that were $0.03 per share unfavorable and gas offset were lower by $0.01 per share compared to the year earlier quarter. O&M comparisons in the fourth quarter improved by $0.01 per share, driven by the absence of a Hope Creek refueling outage. Lower interest expense was $0.01 per share favorable, primarily the result of lower collateral requirements. Lower pension income from ‘22 investment returns and OPEB credits from the lower amortization benefit were $0.03 per share unfavorable versus fourth quarter of 2022. And taxes and other were $0.03 per share unfavorable compared to the fourth quarter of 2022, reflecting a partial reversal of the effective tax rate benefit from the first quarter of 2023. On the operating side, the nuclear fleet produced approximately 7.3 terawatt hours during the fourth quarter and 32 terawatt hours for the full year of 2023, running at a capacity factor of 86% and 93% for the quarter and full year, respectively. At year-end 2023, PCG Power had hedged approximately 90% to 95% of its expected generation for 2024 and at an average price of $38 per megawatt hour, up from $31 per megawatt hour in 2023. Touching on some recent financing activity. As of December 31, PSEG had total available liquidity of $3.4 billion, including $54 million of cash on hand. PCG Power had net cash collateral postings of approximately $113 million at December 31, more consistent with historical experience and substantially below the elevated levels seen during 2022. This reduction in collateral also helped to bolster PSEG’s cash from operations to $3.8 billion for the full year 2023 versus $1.5 billion for the full year of 2022. At year-end 2023, PSEG had $500 million outstanding of a 364-day variable rate term loan maturing in April 2024 and PCG Power had $1.25 billion outstanding of a variable rate term loan maturing in March of 2025. We’ve swapped a total of $1.4 billion from these two term loans at PSEG Power and PSEG from a variable to a fixed rate to mitigate variability in interest rates. As of December 31, reflecting our swaps, approximately 4% of our total debt was at a variable rate, which is down nearly 8% since year-end 2022, driven by a reduction in parent short-term debt of nearly $1.7 billion. We continue to maintain solid investment-grade ratings. Looking ahead, we expect that PSE&G’s considerable cash generation combined with PCG Power’s enhanced cash flow visibility from the nuclear PTC will support the execution of PSEG’s 5-year capital spending plan, which is dominated by regulated CapEx without the need to issue new equity or sell assets. In closing, we executed on our 19th year in a row of meeting or exceeding our non-GAAP operating earnings guidance. We are reaffirming PSEG’s full year 2024 non-GAAP operating earnings guidance of $3.60 to $3.70 per share, and we are reaffirming the extension of our 5% to 7% operating earnings compounded annual growth rate through 2028. That concludes our formal remarks and we are now ready to begin the question-and-answer session.

Constantine Lednev:

Hi, good morning, team. It’s actually Constantine here on for Shahriar. Congrats on a great quarter.

Dan Cregg:

Hello, Constantine.

Ralph LaRossa:

Constantine, I think we’ve been mentioning for quite some time that we’ve got – we potentially have some upside down from PPAs or something similar to that. But we’re going to look at what the state – how the state moves from an economic development standpoint and then make some decisions from there. And let me give you a very specific kind of thought process. We’ve done a lot of work down and around the plan in anticipation of the wind port. And so that work progressed and the state has been very happy with it. They have got some manufacturers that are either in the process of moving into that area or still considering it. But if they don’t use all of that area, maybe we could look at electrolyzer set up that could be down in that vicinity that could provide us with an opportunity. Maybe there could be a data center down in that area. But all of those things really are driven by the growth that the state is looking to do from an economic development standpoint. And as we have done for many years here aligns with the policy of the state and that’s going to enable us to continue to excel. So I think there is some upside. None of that is in our plan. None of it has been in our plan, and we’re just going to keep our options open.

Ralph LaRossa:

No, no. I think once we get a couple of years out here, we will be able to see – there is exert still in place through ‘25 and as all the companies are talking about a noise on the PTC rules need to come out. And once all of that comes together, we will be able to look at a plan to optimize the revenues from those plants.

Ralph LaRossa:

Yes. Constantine, I think the biggest lesson learned is that New Jersey has its act together. I really think that the state – if you look at what has happened recently with JCP&L and Atlantic City Electric, really good outcomes. And I wouldn’t say everybody is always – people are always looking for a little more here or there. But the process and the methodology that’s been used has been consistent with in the past. There hasn’t been any real deviations and we don’t expect there to be anything different with our case, going in with a case that’s not as big as some others have gone in with. And as we mentioned in the prepared remarks, if you look at Page 12 in the deck, we’ve done really well by our customers over a time period that has seen a lot of inflation. We’re really not anticipating this to be a very contentious case.

Ralph LaRossa:

Thanks, Constantine.

Ralph LaRossa:

Hi, David.

Ralph LaRossa:

How are you?

Ralph LaRossa:

Yes. So a couple of pieces there, David. First of all, on the state level, we were very happy to see the PJM listened to our recommendations and most importantly, to the state’s policy. And so they have reflected both of those things in their latest forecast. That being said, PJM is a lot bigger than the state of New Jersey. And so we’re hoping that PJM takes a look across its entire footprint and make sure that the same methodologies are being used and a consistent methodology in all the states. States have different policies. So they may have different outcomes, electric vehicles being a great example, but how that – how any of those loads are being looked at should be consistent in our opinion, across the entire footprint of PJM. And then specifically in our backyard, we are starting to see some data centers pop up here. I would say – so far, what we have seen is somewhere in the neighborhood of 50 megawatts to 100 megawatts, but those conversations are just starting. Again, if you think about what the state has been pushing from an economic development standpoint, there is a lot of AI activities. The Governor is trying to entice some companies to move into the area. Once that happens, there might be some more opportunities for us. And our system is really well positioned. We have talked for years about the build that we did on the transmission side and the self transmission upgrades that we have been doing. It’s driving some last mile investments for us, but that’s also, again, consistent with what we have talked about with you all in the past.

Ralph LaRossa:

Yes. And the only – think about it this way, too, David, is if Dan is putting in a data center, he is going to use 100 megawatts, that’s 100 megawatts more to spread the costs over for all the customers. So, it also creates more headroom for our residential customers. So, all bits of it come together in a positive way.

Ralph LaRossa:

Yes. We would certainly signal that to you if we did. But I think what Dan and Carlotta and I have been saying wherever we have been going has been, right now, we have got our last mile investments that we need to make. And then if you look at our CapEx bar charts, we have a few – a little bit of upside that’s built into the high and the low, but there is nothing that I would say is incrementally driving us above those charts that we have provided in the past.

Ralph LaRossa:

Yes, David, I am going to let Dan walk you through that, but because there is a lot of puts and takes that we have been taking people through, but start with Page 12 and take it from there.

David Arcaro:

Great. Thanks so much. Appreciate it.

Operator:

[Operator Instructions] Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Ralph LaRossa:

Good morning.

Ralph LaRossa:

Yes. So, great questions, Durgesh. And it can be a little confusing because they do talk about the period as a triennial period. And so that ‘25 to ‘27, it’s actually 2.5 years, which is the reason for some of the extensions that you have seen and that we remarked upon earlier in our prepared remarks. Think about that 3-year period as being the period during which you are going to get the commitments to actually have the work get done. But we have described for folks, and it’s important given the magnitude of the numbers that it’s understood that the actual spending to satisfy those commitments is going to be done closer to a 5-year to 6-year period. So, I think that’s how to think about it. It is described as a triennial period, but that’s more about getting the commitments. The spend will be over a little bit longer period. And the schedule that’s in place right now is for us to move forward. We made that filing, if you recall, December 1st. We did that at the same time as all of the utilities in the state. And you should see in the third quarter to fourth quarter. I think it’s October of this year coming up is the estimated date for us to get an outcome there.

Ralph LaRossa:

Yes, that is correct.

Dan Cregg:

Yes. We are still in a waiting game to guess. I wish I had a different answer for you. Treasury, as we have spoken to them last, which is just a couple of months ago, we made them aware as we do every time that we can, that it’s important for them is try to get the rules out sooner rather than later. But as we sit here today, they have not issued a date by which that they will provide that guidance. So, we are just awaiting their answer. I don’t have anything more specific, I wish I did.

Dan Cregg:

You bet.

Carly Davenport:

Hey. Good morning. Thanks for taking the questions.

Carly Davenport:

Maybe just to quickly follow-up on Durgesh’s question there. As we think about the interim before we get the PTC guidance, how should we think about the hedge program in the meantime, should we expect to see any potential incremental ‘24 hedges or starting to layer in ‘25 hedges between now and then?

Carly Davenport:

Got it. Okay. That’s really helpful. And then maybe just as you think about managing O&M, can you just talk about some of the moving pieces we should be keeping in mind for 2024. I know that there might be some upward pressure from some of the nuclear outages that you have, but anything that you would flag on O&M for ‘24?

Dan Cregg:

And even just to follow-on Ralph’s comments for ‘24 the nuclear fuel comment, most of what we will incur for 2024 is what’s in the reactor already. And so as we do step through the time, you have seen some increment in those markets. But for 2024, you shouldn’t expect anything very different.

Dan Cregg:

Thanks.

Ryan Levine:

Good morning everybody.

Ryan Levine:

One follow-up on nuclear, should we expect that there is a plan in place on what you would do once you get the treasury regulation around tax policy that you could roll out shortly thereafter or is there a more delayed timeline in terms of response that we should look for?

Dan Cregg:

Yes. I mean I think Ralph said it, we have done a lot of work trying to understand where this could come out. I guess I would say the treasury has given us the time to do that work by not having some guidance out as early as we might have liked. So, in those situations, what you do is you try to think about where they may come out with guidance and to prepare yourself to be ready for any of those outcomes. And so that’s what we have been doing. To your – the other part of your question, yes, we would let you know what our response will be after it does come out, we are able to thoroughly read through everything and make sure that we understand all the nuances that may or may not be in what comes out. I hope when it does come out, it will be won [ph] and done. Instead of guidance that we will have incremental guidance to follow, it would be great if it was – if it comes out on full form, but we will definitely share how we are approaching things once we know what the final rules are.

Dan Cregg:

Yes. So, maybe a little bit less from a data center perspective, but certainly from a broader perspective, if you think about EVs, one of the things that we did touch on was that time of use rates is a topic that we would anticipate that we would work through within this rate case. And I think in Ralph’s prepared remarks, you talked about that being helpful to those that ultimately have EVs and could encourage some incremental adoption there. But that’s more where you would find it in the rate case and less about data centers more about electrification and EV.

Ralph LaRossa:

Which is really well positioned, Ryan, between the SIP that we have had in place for some time and where we are from a rate structure standpoint that Dan’s comments were bid on.

Dan Cregg:

Thanks Ryan.

Ralph LaRossa:

Great. Thanks. Listen, this – I think the fact that we have got, we only have five questions on this call, folks asking questions that at the end of the day, it was another uneventful call for us. And that is just really what we are hoping to put in place as we have worked really hard as a team to close out our first full year together. 2023 was the year of execution that came across from a number of different areas in our company. But it’s all built on the base of a utility that’s really uniquely positioned. It’s got – it’s provided affordable service for its customers, it’s provided reliable service for its customers and its continued to deliver high-quality service based upon the results of all the polling that we do with our customers and J.D. Power just being one of those examples. And then you just combine that with a nuclear fleet now has continued to be more predictable, not only because of what we are seeing from the revenues side and the PTCs, but from an operating standpoint, you see in our deck, we went from 92% capacity factored and 93% capacity factors this year, and we will continue to improve on that. That’s our expectation. We want to continue to provide that great revenues from those plants that’s going to provide us with the opportunity to continue to not issue equity, and not sell any assets and continue the growth that we have had on the utility side. So, we thank you for all the support that you have given us over 2023, and you can expect from us the same consistent and uneventful progress that we have made throughout this past year. So, thanks and have a great day.

Carlotta Chan:

Good morning, and welcome to PSEG's third quarter 2023 earnings presentation. On today's call are Ralph LaRossa, Chair, President and CEO; and Dan Cregg, Executive Vice President and CFO. The press release, attachments and slides for today's discussion are posted on our 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 principle, 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.

Dan Cregg:

Thank you, Ralph, and good morning, everybody. As Ralph mentioned earlier, PSEG reported net income of $139 million or $0.27 per share for the third quarter of 2023 compared to net income of $114 million or $0.22 per share for the third quarter of 2022. Non-GAAP operating earnings for the third quarter of 2023 were $425 million or $0.85 per share compared to $429 million or $0.86 per share for the third quarter of 2022. We've provided you with information on Slides 9 and 11 regarding the contribution to non-GAAP operating earnings per share by business for the third quarter and year-to-date of 2023. Slides 10 and 12 contain waterfall charts that take you through the net changes for the quarter-over-quarter and year-to-date periods and non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported third quarter 2023 net income of $401 million or $0.80 per share compared with $399 million or $0.80 per share in the third quarter of 2022. The PSE&G had non-GAAP operating earnings of $403 million or $0.80 per share for the third quarter of '23 compared to $399 million or $0.80 per share in the third quarter of 2022. The main drivers for both GAAP and non-GAAP results for the quarter were growth in transmission and distribution margins resulting from continued investment in infrastructure replacement and clean energy programs as well as lower O&M expense. These favorable items were offset by our anticipated lower pension income and OPEB credits, along with higher depreciation and interest expense resulting from incremental investments since the year earlier quarter. Compared to the third quarter of 2022, transmission was $0.03 per share higher. Electric margin was $0.02 per share higher, reflecting investment returns from Energy Strong II. Gas margin was $0.01 per share higher, primarily driven by the clause recovery of our GSMP investment. Lower distribution O&M expense added $0.01 per share compared with the third quarter of 2022, and depreciation and interest expense increased by $0.01 and $0.02 per share, respectively compared to third quarter 2022, reflecting continued growth in investment. Lower pension income resulting from 2022's investment returns, combined with lower OPEB credits scheduled to end in 2023, resulted in a $0.05 per share unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an effective tax rate, which nets to zero over a full year and other flow-through taxes had a net favorable impact of $0.01 per share in the quarter compared to third quarter of 2022. Weather during the third quarter, as measured by the Temperature-Humidity Index, was 11% warmer than normal, but 5% cooler than the third quarter of 2022. As we've mentioned, 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 program. Growth in the number of electric and gas customers, the driver of margin under the SIP mechanism continues to be positive and will each up by approximately 1% year-to-date. On capital spending, PSE&G invested approximately $1 billion during the third quarter and is on track to execute its largest ever investment program of $3.7 billion in a single year. The program includes upgrades and replacements to our T&D facilities, Energy Strong II investments, last mile spend in the infrastructure advancement program, our ongoing GSMP II program continued rollout of the clean energy investments in energy efficiency and the energy cloud, including smart meters and adding new electric infrastructure to accommodate an increase in EV penetration. During 2023, we've taken actions to limit the impact of our pension on earnings and increase the predictability of our financial results. In February of 2023, the BPU approved an accounting order authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component for ratemaking purposes. This change is effective for the calendar year 2023 and forward. For the full year 2023, PSE&G's forecast of non-GAAP operating earnings is unchanged at $1.5 billion to $1.525 billion. Moving to PSEG Power & Other. For the third quarter of 2023 PSEG Power & Other reported a net loss of $262 million or $0.53 per share largely reflecting the pension settlement charge associated with the lift-out transaction. This compares to a net loss of $285 million or $0.58 per share for the third quarter of 2022. The onetime noncash settlement charge of $332 million, $239 million net of tax was related to the approximately $1 billion of PSEG Power & Other pension obligations and associated plant assets transferred to the Prudential Insurance Company. After providing for the effect of the lift out, our pension plans remain well funded, and there is no material impact on our non-GAAP operating earnings in 2023. Non-GAAP operating earnings were $22 million or $0.05 per share for the third quarter of 2023 compared to non-GAAP operating earnings of $30 million or $0.06 per share in the third quarter of 2022. We previously mentioned that during the first quarter of 2023, PSEG Power realized the majority of the approximate $4 per megawatt hour increase in the average price of our 2023 hedged output which rose to approximately $31 per megawatt hour with higher winter pricing driving most of that increase. For the third quarter of 2023, gross margin rose by a total of $0.03 per share primarily reflecting the roll-off of certain full requirement BGS load contracts and had a higher cost to serve, resulting in a $0.04 per share of benefit compared to the prior year. The gross margin improvement also included higher generation which added $0.01 per share, resulting from the absence of a Hope Creek refueling outage that started at the end of last year's third quarter. These positive variances were partially offset by lower capacity revenues of $0.02 per share compared with the year ago quarter consistent with prior year capacity auction. OEM cost comparisons in the third quarter improved by $0.03 per share, driven by the absence of Hope Creek refueling outage expenses that were partly incurred in 2022's third quarter. Lower depreciation expense was $0.01 favorable compared with the year ago quarter, while higher interest expense was $0.01 unfavorable. Lower pension income from 2022 investment returns and OPEB credits from the lower amortization benefit were $0.03 per share unfavorable versus third quarter 2022. Taxes and other were $0.04 per share unfavorable compared to the third quarter of 2022, reflecting a partial reversal of the effective tax benefit from the first quarter of 2023. On the operating side, the nuclear fleet produced approximately 8.1 terawatt hours during the third quarter and 24.3 terawatt hours for the year-to-date period in 2023, running at a capacity factor of 95.3% and 95.8% for the quarter and year-to-date periods, respectively. For the full year 2023 PSEG is forecasting generation output of 30 to 32 terawatt hours and has hedged approximately 95% to 100% of this production at an average price of $31 per megawatt hour. For 2024, the nuclear fleet is forecasted to produce 30 to 32 terawatt hours of baseload output and has hedged 85% to 90% of this generation at an average price of $38 per megawatt hour. The forecast of non-GAAP operating earnings for PSEG Power & Other is 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 hedge price in the first quarter of '23, as we previously discussed. For the balance of the year, higher interest expense largely captured in our November 22 update is expected to reduce PSEG Power & Other results. Touching on some recent financing activity, as of September 30, PSEG had total available liquidity of $3.8 billion, including $57 million of cash on hand. PSEG Power had net cash collateral postings of approximately $350 million at September 30, which is substantially below the elevated levels seen last year. In August, PSE&G issued $500 million of 5.2% secured medium-term notes due August 2033 and issued $400 million of 5.45% secured medium-term notes due August 2053. In September, PSE&G retired $325 million of 3.25% secured medium-term notes at maturity. Subsequent to the end of the third quarter, PSEG issued $600 million of 5.88% senior notes through October 2028 and $400 million of 6.13% senior notes due October 2033. Prior to pricing these notes, $800 million of treasury locks were executed, which had a positive fair value of $14 million, and this benefit will be amortized over the life of the senior notes, partially offsetting interest expense. Proceeds from the sale of the senior notes will be used for general corporate purposes, including the repayment of $750 million of PSEG debt maturing this November. As of September 30, 2023, PSEG had $500 million outstanding of a 364-day variable rate term loan maturing in April 2024 and PSEG Power had $1.25 billion outstanding of a variable rate term loan maturing March of 2025. As of the end of the quarter, PSEG had swapped $900 million of the power term loan from a variable to a fixed rate serving to mitigate the impact of higher interest rates. As of September 30, reflecting our swaps, approximately 5% of our total debt was at a variable rate, which is down by half since year-end 2022. We continue to maintain a solid financial position with limited exposure to variable rate debt given the improvement in our collateral position, a staggered maturity schedule and PSEG Power cash generation to support funding our regulated business. In closing, we are reaffirming PSEG's full year 2023 non-GAAP operating earnings guidance of $3.40 to $3.50 per share. PSE&G is forecasted between $1.5 billion to $1.525 billion and PSEG Power & Other is forecasted at $200 million to $225 million. That concludes our formal remarks. And operator, we are ready to begin the question-and-answer session.

Nicholas Campanella:

So I just -- I wanted to ask on looking forward to '24, if the broad market kind of underperforms here that could maybe affect your pension headwind, but also kind of understanding that you've done a lot of derisking this past year to take the volatility out, you had the lift out, you have the accounting order. Just -- could you just give us any sense how we should think about kind of pension contribution as a percentage of earnings for '24 or just even relative to the drag you've had year-to-date? Is there a drag that we should be thinking about for '24? And any detail on how pension has performed year-to-date versus your expectations as well would be helpful.

Dan Cregg:

Yes. And think that's really what we set out to do. It doesn't eliminate the effect of markets moving because we still do have attention, but we've been able to minimize the magnitude of what we would see. So, as we step through the year, markets have moved, they've been off a little bit in the last few months. We got another couple of months to go to we see where we land. I think that we're not immune to some of those movements, but I think the work that we've done will lessen that effect. And as we're looking at it now, the magnitude of what we intend to see or what we anticipate seeing as we move through year-end is something we can still manage through the overall O&M budget.

Dan Cregg:

No. There is no -- there has been no and there is no intention to have any equity issuance as we go through the capital plan that we have in front of you. So we've had $15.5 billion to $18 billion for the utility through '27 all year. We're still within that range as you look across the five years, that $3.7 billion is a great performance. So, we've been able to continue to move forward on that. But what you're seeing there is great and it's helpful, but it is still within our overall range. And there is no equity that we're going to need to fund even the high end of that range.

Operator:

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

Ralph LaRossa:

Yes, Shar. All great questions. And again, I'll give Dan some chance to answer details here, but you hit on all the moving parts that we're considering. And a lot of that has to do with driving for what our time frame is that we're going to come out with the -- with our earnings in December. So Dan, can you just give any more on some of those items.

Shar Pourreza:

And again, I don't want to put you in a corner, but it seems like there's probably more tailwinds and tail risks that as we're thinking about that shift from '23 to '24. Is that a fair assessment?

Shar Pourreza:

Got it. And then just lastly, just -- I mean, I guess, what are you hearing on the nuclear PTC guidance? And I guess, how do you plan a business case around it? I mean you have a refueling cycle, you've had some modest CapEx improvements on the back burner for nuclear, are those plans getting closer to a decision point, especially with the guidance?

Shar Pourreza:

Got it. And again, sorry, just getting hit with a lot of questions from one of my questions. When do you plan on giving '24 guidance?

Operator:

Our next question is from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Ralph LaRossa:

Yes. So look, I'll give it to Dan again, give you some details, but that -- both of those things are very good news for us. The transmission opportunity as well as the energy efficiency growth that we see from the triennial at the BPU put forth. But Dan's answer, I believe, is going to be exactly the same to you. We do not need equity or anything that looks like it.

Durgesh Chopra:

Excellent. Very clear there. And then just maybe just on the topic of nuclear PTCs. I saw you've increased hedges for 2024, the percentage of output hedged. How are you thinking about '25? I mean, obviously, we are still awaiting guidance here. But are you like -- as you roll forward to 2025, are you going to be less hedged than before anticipating some clarity on nuclear PTC? Or what is your thought process there?

Operator:

Our next question comes from the line of David Arcaro with Morgan Stanley. Please proceed with your question.

Ralph LaRossa:

Yes. No, there's nothing really that I said -- we've been saying all along with what our plans are. I think the only thing that you'll see is that this rate case gives us the opportunity to roll in a lot of the other things that people have been asking about, whether it be interest rates or pensions, right, and the impact that pension expenses might have on us. So -- that's -- those are the only two real updates, I would say that we have, and we're keeping an eye on the CapEx, but most of those items that we talked about, whether GSMP, which we closed on, transmission opportunity exists, which will not be with the state of New Jersey, our energy efficiency would be a clause mechanism. So nothing really that I would say is driving a big change to us. Dan, anything you want to add?

David Arcaro:

Yes. Got it. Okay. Great. That's helpful. And then we've got new leadership at the commission. I was just wondering if you could give perspectives on if you think the overall kind of priorities of the commission, and how they're going to treat maybe settlements or just overall views on your opportunities to work with them now going forward under new leadership in a different set of commissioners?

Operator:

Our next question is from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.

Ralph LaRossa:

Yes. So look, here's the way I would frame it. The two years that we agreed upon are at a higher run rate than they would have otherwise been based upon our filing. So that's a real positive. I think when you look at the two areas that were of concern in the conversation they were minimal from an investment standpoint. One was the renewable natural gas piece of our filing and the other was the hydrogen blending. And those are fair policy conversations that need to take place. So, the Board wanted to move ahead from a commitment standpoint to get the work done to continue to methane reductions. So, we're completely aligned there. The run rate was higher. And I think we just participate and see where policy wants to go on those other two items and make a decision on that. But from a long-term strategy standpoint, our commitment to reduce the cast iron in our system remains and it's supported at this time by the commission. So I see nothing really changing from that standpoint.

Jeremy Tonet:

Got it. That's very helpful there. And then following up with hydrogen, if I could. What's the latest messaging progress behind the hydrogen hub evaluation in the Northeast Mid-Atlantic there? And how should we think about the hydrogen opportunity across local industry, PEG’s nuclear fleet, gas blending, regional renewable electrification overall. What can you share there?

Jeremy Tonet:

Got it. That's very helpful. And I think you guys have been pretty clear on no equity. So I will fully refrain from that part.

Jeremy Tonet:

No, we heard you loud and clear. But just, I guess, in December, any updates to get there. I mean, will we be getting kind of a CapEx update in December, and then would that be updated kind of later on '24 as we kind of -- some of the incremental items come through? And just clarity comes through on some of the different items. And if so, how does the expected EE filing match up with how you're thinking about it at last year's CapEx update?

Operator:

Our next question is from the line of Julien Dumoulin-Smith with Bank of America. Please proceed with your question.

Ralph LaRossa:

I'm going to give Dan a crack at some of this, too, but I just want to reinforce -- I apologize if I said we were at the low end. I definitely is in that -- I did not mean to say that if I said it earlier, it was not my intention. So we're within the range. We've said that. And I would agree with you that there's a lot of positive momentum here, but nothing is firmed up yet. And so that's why we're where we are. And we will give you that information when we get later in December for the two items that I mentioned, the GSMP and then we'll give you some more in January. But Dan, do you want to add anything to that?

Julien Dumoulin-Smith:

Got it. A couple of clarifications there. If you don't mind, I was saying earlier, 6% to 7.5%, at least the -- the low end of 6% seems like it needs to come up through '27 -- would you be rolling forward the plan to '28? And then even more specifically within that, how do you think about the linearity if we're going to bring up this term again in terms of earnings, not just off of '23, but maybe off of a '24 baseline, if you will, if you don't mind?

Operator:

Our next question is come from the line of Michael Sullivan with Wolfe Research. Please proceed with your question.

Ralph LaRossa:

That will be in the January time frame. That's what we said in the prepared remarks, and we will be giving that update at that time, exactly.

Dan Cregg:

Yes.

Ralph LaRossa:

Yes. Nothing that we're aware of on the parent level, but I will tell you, I was getting some good work by Dan and his team treasury department to explain what's going on in our -- on the power side. And we were very happy, and I appreciate you recognizing Moody's letter it went out. So, thanks on that front.

Operator:

Next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question.

Ralph LaRossa:

Yes. Look, I'll take the last one. The team continues to perform excellent work there, and there's nothing that we have there to discuss other than a normal average consistent with our business plan, so just a great opportunity for me to give kudos to the team down there. So thank you for that and Dan will give you the PTC piece.

Operator:

Next question comes from the line of Travis Miller with Morningstar. Please proceed with your question.

Dan Cregg:

Yes. Travis, I think what that really is, is the team has been doing a great job of knocking out the work that we have in front of us, and there are a couple of things that, that is think of it as just getting some of the work done a little bit quicker than anticipated, and we'll follow up with a more fulsome update as we go forward.

Dan Cregg:

No. Well, I would argue that you may be able to think about it that way. But as we give you an update, you'll be able to see what happens because 2025 could get pulled back into '24. It's a little bit fluid as they go forward. And if they're ahead on where they are right now, you can see some other things coming back into '24. So I wouldn't think about it as a reduction in '24. I think about it as just getting a little bit more work done early, and we'll continue to true that up as we go forward.

Travis Miller:

Okay. Perfect. That's helpful. And then a high-level question on offshore wind, I know you're not involved in that anymore, but obviously, a lot of stuff coming out in New York. Any thing you're hearing in regulatory discussions, political halls, anything you're hearing in terms of New Jersey's offshore...

Operator:

Our next question is from the line of Anthony Crowdell with Mizuho. Please proceed with your question.

Ralph LaRossa:

That's about the rhythm we expect. I don't want to be tied into an hour or a day, but yes, that's the rhythm we expect.

Dan Cregg:

Yes. So, we'll take that out and step forward. And Anthony, I think the important element is that last November, as we gave that update, we presume rates including spreads that were pretty comparable to where we are. We didn't capture every single dollar of it. But I think the delta between what we thought it was going to be and where we are currently from a market perspective is within the range. So, I think we've done a nice job of getting ahead of it, and we will take that out. And like a lot of our refinancing, we will see some higher rates as we flip them, but they're a caution our forecast.

Dan Cregg:

Yes. I mean if you take a look at it, they didn't move the rating on power. It's just a positive outlook there. And so I think that ripple effect would be would be lesser as you look at the parent. But I think on balance, just if you think about the overall business mix reflective of PTCs and what we've done from an overall strategic set of decisions I think we're in a better position going forward.

Ralph LaRossa:

Yes. No. Thank you very much, and try -- sorry, we had so much interest, but sorry, we had to move on. Listen, I just want to thank you all for your continued interest. The work that our team continues to produce amazes me. I'm really happy with the stability that we've created here and the certainty. We put out some internal information earlier today, and it's just amazing the amount of things that we continue to execute on. And I'll just highlight a few of them here. One was this gas system monetization plan and the work that we completed. We've continued to be recognized in awards different things that have come out of best employers and best companies to work for. We lowered our gas bills again for customers effective October 1, and we refreshed our Board of Directors. So, things that a lot of people sometimes struggle with, we just seem to be executing time and time again. So a big thanks to our team. Hopefully, you hear that not only in our voices, but from others that we're a company you can count on, and we're executing on the work that we said we would. And I'll just leave with this. Anthony said it, but happy Halloween to everyone. I hope you all have a safe and healthy Halloween, and that's not just for yourselves but also for your families. Enjoy the day. Take care.

Carlotta Chan:

Good morning, and welcome to PSEG's Second 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.

Daniel Cregg:

Great. Thank you, Ralph, and good morning, everybody. Earlier, Ralph mentioned that PSEG reported net income of $591 million or $1.18 per share for the second quarter of 2023 compared to net income of $131 million or $0.26 per share for the second quarter of 2022. Non-GAAP operating earnings for the second quarter of 2023 were $351 million or $0.70 per share compared to $320 million or $0.64 per share for the second quarter of 2022. We've provided you with information on Slides 9 and 11 regarding the contribution to non-GAAP operating earnings per share by business for the second quarter and year-to-date periods and Slides 10 and 12 contain waterfall charts that take you through the net changes for the quarter-over-quarter and year-to-date periods in non-GAAP operating earnings per share by major business. Starting with PSE&G, which reported second quarter 2023 net income of $336 million or $0.67 per share. This compares to $305 million or $0.61 per share in the second quarter of 2022. The second quarter 2023 non-GAAP operating earnings were $341 million or $0.68 per share compared to $305 million or $0.61 per share in the second quarter of 2022. The main drivers for both GAAP and non-GAAP results for the quarter were growth in rate base reflected in higher transmission formula rate, recovery of infrastructure investments with roll-in mechanisms and a benefit from the reversal and timing of taxes, which we mentioned on the first quarter call, nets to 0 over the course of the year. These favorable items were partly offset by our anticipated lower pension income and OPEB credits, along with higher depreciation and interest expense from increased investment versus the year earlier quarter. Compared to the second quarter of 2022, transmission was $0.02 per share higher, gas margin was $0.01 per share higher driven by the clause recovery of GSMP investment. Electric margin was $0.01 per share higher, reflecting investment returns from Energy Strong and other electric and gas margin added $0.02 per share based on a benefit from the tax adjustment credit and appliance service results. Lower distribution O&M expense added $0.02 per share compared to the second quarter of 2022, primarily reflecting reduced weather-related corrective maintenance. Depreciation and interest expense increased by $0.01 and $0.02 per share, respectively, compared to the second quarter of 2022, reflecting continued growth in investment. Lower pension income resulting from 2022's investment returns, combined with lower OPEB credits scheduled to end in 2023, resulted in a $0.04 per share unfavorable comparison to the year earlier quarter. Lastly, the timing of taxes recorded through an effective tax rate, which nets to 0 over a full year and other flow-through taxes had a net favorable impact of $0.06 per share in the quarter compared to the second quarter of 2022. Second quarter weather typically contains both heating and cooling sales. For 2023, winter weather during the second quarter was 23% warmer in terms of heating degree days than the second quarter of 2022, and summer weather was 34% cooler than second quarter 2022 as measured by the temperature humidity index. As we've mentioned, 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 importantly, enabling PSE&G to promote the widespread adoption of its energy efficiency programs. 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. On capital spending, PSE&G invested $900 million during the second quarter and is on plan to deliver its largest annual capital investment program at $3.5 billion. The program includes upgrades to our T&D facilities, Energy Strong II investments, last mile spend in the infrastructure advancement program and the continued rollout of the clean energy investments in energy efficiency and the Energy Cloud, including smart meters. Related to our pension, in February 2023, the BPU approved an accounting order authorizing PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component for ratemaking purposes. This change is effective for the calendar year ending December 31, 2023 and forward. For the full year 2023, PSE&G's forecast of non-GAAP operating earnings is unchanged at $1.500 billion to $1.525 billion. Moving on to Power & Other. Just as a reminder, Power & Other includes our nuclear fleet, gas operations, Long Island and parent activities, including interest expense. For the second quarter of 2023, PSEG Power & Other reported net income of $255 million or $0.51 per share and non-GAAP operating earnings of $10 million or $0.02 per share. This compares to second quarter 2022 net loss of $174 million or $0.35 per share and non-GAAP operating earnings of $15 million or $0.03 per share. We previously mentioned that during the first quarter of 2023, PSEG Power realized the majority of the approximate $4 per megawatt hour increase in the average price of our 2023 hedged output, which rose to approximately $31 per megawatt hour with higher winter pricing driving most of the increase. For the second quarter of 2023, gross margin rose by a total of $0.05 per share reflecting the absence of certain full requirement BGS load contracts that remain following the sale of the fossil business in 2022 and resulted in a lower cost to serve compared to the prior year. The increase in gross margin includes higher generation of $0.01 per share from fewer refueling outage days in the second quarter of 2023, offset by lower capacity revenues of $0.01 per share compared to the year ago quarter. O&M cost comparisons in the second quarter improved by $0.01 per share in 2023. Higher interest expense covering PSEG Power and parent financings were $0.02 per share unfavorable compared to the year ago quarter from higher variable rates on term loans and refinancing maturing debt at higher rates. Lower pension income from 2022 investment returns and OPEB credits from the lower amortization benefit mentioned earlier were $0.03 per share unfavorable versus the second quarter of 2022. And taxes and other were $0.02 per share unfavorable compared to the second quarter of 2022, reflecting a partial reversal of the effective tax rate benefit from the first quarter and lower investment income. On the operating side, the nuclear fleet produced approximately 7.7 terawatt hours during the second quarter and 16 terawatt hours for the year-to-date period in 2023, running at a capacity factor of 91.2% for the quarter and 95.8% for the year-to-date period. For the full year 2023, PSEG is forecasting generation output of 30 to 32 terawatt hours and has hedged approximately 95% to 100% of this production at an average price of $31 per megawatt hour. For 2024, the nuclear fleet is forecasted to produce 30 to 32 terawatt hours of baseload output and has hedged 75% to 80% of this generation at an average price of $38 per megawatt hour. The forecast of non-GAAP operating earnings for PSEG Power and other is 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 hedge price in the first quarter of '23, as we previously discussed. Touching on some recent financing activity. As of June 30, 2023, PSEG had total available liquidity of $4 billion, including $500 million of cash and cash equivalents on hand. PSEG Power had net cash collateral postings of approximately $400 million at June 30, which is well below the levels experienced during 2022. Through the second quarter, we've repaid $2 billion of term loans, which were entered into during 2022 to support our collateral needs. In April, we entered into a $750 million 364-day variable rate term loan to support our liquidity needs. As of June 30, 2023, PSEG had $750 million outstanding of a 364-day variable rate term loan and PSEG Power had $1.25 billion outstanding of a variable rate term loan maturing March of 2025. As of the end of the quarter, PSEG had swapped $900 million of the power term loan from a variable rate to a fixed rate. And in May, PSE&G paid at maturity $500 million of secured medium-term notes. As Ralph mentioned earlier, PSEG recently executed an agreement for a pension lift-out that will further increase the predictability of our financial results. This transaction covers approximately 2,000 retirees from PSEG Power & Other, and will transfer approximately $1 billion of related obligations and associated plan assets. This transaction will have no material impact on PSEG's non-GAAP operating earnings in 2023. Upon completion of the pension lift-out, we anticipate taking a onetime noncash settlement charge in the third quarter of 2023 related to the immediate recognition of unamortized net actuarial loss associated with a portion of the pension involved in the transaction. After providing for the effect of this transaction, our pension plans remain well funded. As Ralph mentioned, we are reaffirming PSEG's full year 2023 non-GAAP operating earnings guidance of $3.40 to $3.50 per share, with PSE&G forecasted to contribute between $1.500 billion to $1.525 billion and PSEG Power & Other forecasted at $200 million to $225 million. The settlement charge related to the lift-out is not included in the full year 2023 non-GAAP operating earnings guidance for PSEG, PSE&G or PSEG Power & Other. That concludes our formal remarks. And operator, we are ready to begin the question-and-answer session.

Shahriar Pourreza:

Dan, you talked about some uncertainties remaining with power and energy prices until we get that PTC guidance. Any update on conversations with treasury? There seems to be some delays, obviously, in other tax credit issues. So does that potentially push out like the PTC implementation. And does that change the calculus for power as you think about earnings hedging in any of the efficiency projects like refueling gas, et cetera.

Shahriar Pourreza:

And then just on the '24 case expectations, I mean, you guys have highlighted the need to recover base spending that's not in much mechanisms to the tune of $0.30 earnings in '25. As we're getting closer to a filing, can you maybe just talk a little bit about how we should think about the revenue deficiency and the overall rate impact as we are seeing higher cost of capital? It's certainly a different inflationary environment in the last [indiscernible].

Shahriar Pourreza:

Okay. Perfect, very clear-cut quarter. So that's all I had.

Jeremy Tonet:

Just wanted to get into the pension lift a little bit more. Just wondering if you could provide some more details such as is there any cash changing hands here? And how does the equity fixed income mix and the lifted out portion compare to the rest? And any thoughts on the equity fixed income mix going forward with the strength in equity markets?

Daniel Cregg:

Yes. So Jeremy, to your more particular questions. So your first question about cash transacted. By its very nature of what the transaction is, is a liability for future pension payments that will move out of the company and that liability will be matched basically with cash that's going to go out with it. And so yes, there is a cash element to the transaction. However, you should think about that cash as coming out of the pension trust where those liabilities will be paid from. And so from more general corporate cash, don't think about any cash from that perspective solely from the trust. That said, and I think that is very a logical way to think about it, given your second question, which is where does that cash come from? And so we have investments across a bunch of different elements of spectrums of investments that we have made through different managers in the pension trust. And I think just the most natural way to think about it without putting too fine a point on it is, it's roughly 20% of the pension, and you could think of us as essentially taking about 20% of our investments across the board and moving them over. There's -- that won't be a perfect interpretation but pretty close to how to think about what it would look like on a go-forward basis from the remaining mix within the funds. So I think that's a simple way to think about it, but an appropriate way to think about it.

Daniel Cregg:

No, you should not -- I think the 5% to 7% you should think about as being intact. Really, Jeremy, this was all about looking to the potential variability and results that we could see corporately because of the size of the pension. And that was the driver behind the transaction. Ralph made a hugely important point. We've said all along, the first thing that we needed to do with our diligence wasn't sure that this was going to be a move that would protect the benefit to our retirees. We did significant diligence there, I felt very comfortable there. And then secondarily, it needed to ultimately come through in a way that made sense for the company as well. And so that's exactly what we did. I think that managing that variability going forward is what we have talked about for a while and what we wanted to deliver on. And you could see some very, very de minimis effects as we step forward within the plan, but nothing that's going to move us out of that range at all.

David Arcaro:

Quick follow-up on the lift-out. What does that leave you in terms of a funding ratio post the transfer there?

David Arcaro:

Okay. Got it. Perfect. And then on the Hope Creek fuel cycle extension, is that kicking off earlier here than you had anticipated previously? Or is that still on track toward the potential fall 2025 outage that you had mentioned previously in the Investor Day?

David Arcaro:

Yes. Great. And then just one other minor question related to that, just as a follow-on. Are you -- how are you thinking about hydrogen and the prospects of potentially producing hydrogen at your nuclear facilities. Do you have involvement or any perspective on the discussions going on now in terms of framing up that policy structure and how additionality might be considered. Just wondering if that's front of mind for you.

Operator:

Next question is from Durgesh Chopra with Evercore ISI.

Daniel Cregg:

Yes, your order magnitude is right there, Durgesh. And essentially, the transaction and the go-forward pension plans would have been more complicated to do this kind of a transaction with active employees because you kind of got a moving target, right? Your service cost continues to go forward. And those kind of elements come into play. And so right now, just think about what sits outside of this lift-out in Power & other as just being status quo.

Ralph LaRossa:

Durgesh, I'll give you a couple of pieces. Yes, last night was the first public hearing that we had on the GSMP filing. 17 individuals spoke in favor of the filing, 1 against. So just in sheer numbers and conversation, it was a very positive outcome. 4 public officials spoke in favor of the project and the work that's been done so far by our folks out in the field. So really, really positive there. So I'm very optimistic that public sentiment is in the right direction. That should all lead to a continuation of our opportunity to settle. I would be surprised if we were in a situation that was anything about a settlement when we get to the end of this.

Carly Davenport:

Maybe just to start, as you think about the regulatory environment in New Jersey, a couple of new commissioners have joined the commission there. Anything that you would highlight in terms of changes or expectations around the regulatory landscape there following the personnel additions?

Carly Davenport:

Great. That's helpful. And then just on collateral postings, it looks like that was down to about $400 million at quarter end. Any thoughts on how we should think about the cadence of incremental hedges rolling off from here?

Operator:

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

Ralph LaRossa:

Yes. No, Julien, listen, I don't think those numbers you just quoted would be aligned with the words de minimis. So I think that would be a little bit more than what we would certainly expect and not aligned with what our expectations are.

Ralph LaRossa:

No, I could understand why people would make that argument. So it might make sense in some circles to do that, right? It certainly would make the most sense from a -- if you just want to generate hydrogen and create hydrogen from the nuclear plants, but I could understand why people make that argument from a tax credit standpoint, right? Because if you're getting tax credits for providing clean energy into the grid and then you convert that to hydrogen, then you get both tax credits. And I could understand that, right? Just the legitimate argument to make. So is that something we're taking a position on one way or the other, but I could certainly understand why some people would approach it that way. And I could understand why other people would approach it, "Hey, listen, we really have to kick start the hydrogen generation. And so therefore, we want to see that -- we want to see all those tax credits go to that angle. I think that's a -- it's a real policy call. It's -- some folks are going to need to make within Washington. So we'll see where it goes.

Ralph LaRossa:

Yes. So again, I think what Dan has been saying from the beginning, and I'm just going to reinforce here is, we really need to understand what treasury is going to seem to be the revenues. And once we understand that, then we can optimize that for our shareholders. Everything that I've been saying up to this point is just respectful of the conversation that's been taking place. It's not meant to take sides on anything. So even whether it's data centers and I -- we try to do what's right for New Jersey and New Jersey customers. And so, hey, does that make sense? Is it a data center here? Where is that data center? Are we wheel in power. There's all sorts of things that are going to go into our thought process as we go forward. And the number one is what Dan has been saying, let's see what rule of treasury say as to how revenue is going to be calculated.

Ralph LaRossa:

Yes, 100%. And -- but again, give us a week to digest the rules when they come out, and then we'll have a plan ready. We're -- those conversations are not -- they're already -- we're already looking at things inside. We'll figure it out.

Ralph LaRossa:

Always. That's why we're able to move as fast than we did on pension. Yes.

Paul Patterson:

So just -- almost all my questions have been answered. But just on -- I apologize for missing this. What is the expected GAAP impact of the lift-out?

Daniel Cregg:

Yes. So Paul, what we said is both -- as we look at 2023, de minimis impact, not even worth kind of including within any models, very, very small impact anticipated. And then going forward, I'd say the same, right? There's a very modest positive arbitrage. But by the same token, what we're -- what we've also talked about here is we will see a onetime charge come through from the standpoint of the unrecognized element. And so the absence of that going forward does provide somewhat of an offset. So I would not think about it as having much of an impact, '23 or going forward. So the main tracker that we talk about is mitigating the volatility.

Daniel Cregg:

No, that 1 charge -- so if you take a look at our year-end 2022, that unamortized amount was about $2 billion. So we've disclosed that we would see something in the low 200s after tax from the standpoint that was in the release of the amortization of that charge. So think about the pension as a whole, having that unamortized balance. And if this is about a 20% impact you're seeing about that coming through on the onetime charge.

Anthony Crowdell:

You may have addressed this in Durgesh's question, so I apologize. But if we think about from year-end to now, you had the approval from the BPU on the pension smoothing and now the lift-out. How much of your pension volatility have you reduced or removed from the end of 2022?

Anthony Crowdell:

Okay. And then I appreciate you did go through that this is for the PEG Power employees unregulated. And in the fourth quarter, you're going to file the general rate case where I believe you're going to request a pension tracker. If the company is unsuccessful or the regulators do not approve the pension tracker, I mean, is this an option that you would look deeper into for the regulated employees? Or just structurally, it just makes -- it's very hard to do it for existing employees, this type of lift-out?

Operator:

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

Daniel Cregg:

Yes, I think, Ryan, it's a tough question to answer, given that we don't have what we need to have from treasury. We have been stepping into hedges as we've approached the year fairly similar to what we've done in the past to be as prepared to mitigate the market volatility as we can. And so I think the question is going to be best answered when we do have that guidance and as we continue to go through the rest of the year.

Daniel Cregg:

Well -- and Ryan, the other thing I would add to that is we've said in the past that we've tended to work our way through a 3-year period within a range kind of a band of hedges across those 3 years. And so there are periods of time where we will try to take a look at what the market looks like within that range to take advantage of market opportunities. And so if you just think about where we've been historically from a price point perspective and where we are now, I think the opportunities led us to be a little bit higher within that band before and a little bit lower within that band compared to last year right now.

Ryan Levine:

Interesting topics. How does the recently approved second energy efficiency framework impact the company's approach to energy efficiency into the next filing later this year?

Carlotta Chan:

Rob, we'll take 1 last call and then we'll turn it back to Ralph for closing comments.

Unidentified Analyst:

Quick question on generation gross margin year-to-date and how we should think about generation gross margin for your following your hedges?

Unidentified Analyst:

So if I look at next year, you would expect the gross margin to be roughly comparable in terms of how it's calculated or the differential to the hedge price as it is this year?

Operator:

I would now like to turn the floor back over to Mr. LaRossa for closing comments.

Operator:

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

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.

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.

Shar Pourreza:

Hey guys. Good morning.

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?

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.

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.

Dan Cregg:

Thanks Shar.

Operator:

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

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.

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.

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.

Ralph LaRossa:

Thanks.

Operator:

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

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.

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?

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?

Julien Dumoulin-Smith:

Excellent. Good luck guys. See you soon.

Dan Cregg:

Thanks Julien.

Travis Miller:

Good morning everyone. Thank you.

Dan Cregg:

Hey Travis.

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.

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.

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.

Operator:

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

Ralph LaRossa:

Hi Andrew.

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.

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.

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.

Dan Cregg:

Thanks, Andrew.

Paul Patterson:

Hey, good morning.

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.

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?

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?

Paul Patterson:

Okay, great. Thanks so much.

Ralph LaRossa:

Hey Ryan.

Ralph LaRossa:

You want to give that one with Dan?

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?

Ryan Levine:

Okay. I appreciate the color. Thank you.

Operator:

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

Dan Cregg:

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

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.

Dan Cregg:

Thanks, Anthony.

Operator:

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

Ralph LaRossa:

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%.

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?

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?

Ross Fowler:

All right. Perfect. That's all I had. Thank you.

Ralph LaRossa:

Thanks Ross. And I'll fill you in on my Panthers’ connection later.

Ralph LaRossa:

Hey, Michael.

Ralph LaRossa:

Good.

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.

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.

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.

Michael Sullivan:

Understood. Thanks guys, appreciate it.

Operator:

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

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.

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?

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.

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.

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.

Operator:

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

Carlotta Chan:

Thank you, Shamali. Welcome to PSEG's fourth quarter and full year 2022 earnings presentation. Joining us on the call today are Ralph LaRossa, Chair, President and CEO of PSEG; and 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-K will be filed shortly. The earnings release and other matters discussed during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We will also discuss non-GAAP operating earnings, which differs from net income or net loss as reported in accordance with generally accepted accounting principles 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 material. Following Ralph and Dan's prepared remarks, we will conduct a question-and-answer session. I will now turn the call over to Ralph.

Dan Cregg:

Thank you, Ralph. Good morning everybody. For the full year 2022 GAAP earnings were $2.06 per share, compared to a GAAP loss of $1.29 per share for the full year of 2021, which included fossil sale related impairments. Non-GAAP results for $3.47 per share for 2022 compared to 2021's non-GAAP results of $3.65 per share, which you may recall excluded depreciation related to the fossil assets held for sale in the fourth quarter of '21 and retirement of power debt. For the fourth quarter of 2022 GAAP earnings improved to $1.58 per share, compared with $0.88 per share for the fourth quarter of 2021. Non-GAAP operating earnings were $0.64 per share compared with $0.69 per share for the fourth quarter of 2021 which contain the fossil sale related items I just mentioned. We provided information on slides 9 and 11 regarding the contribution to non-GAAP operating earnings by business on the fourth quarter and full year periods ended December 31. Slides 10 and 12 contain waterfall charts that take you through the net changes quarter-over-quarter and year-over-year and non-GAAP operating earnings by major business which I will review now starting with PSE&G. Full year 2022 net income rose by $119 million or over 8% to $1.565 billion compared to 2021 net income of $1.446 billion reflecting higher earnings from continued investment in TND programs and the favorable impact of a full year of decoupling in 2022. For the fourth quarter of 2022, the utilities net income rose by $81 million to $352 million or $0.70 per share compared to $0.53 per share in the fourth quarter of 2021. As you can see on Slide 10 transmission margin and a penny per share compared to the year earlier quarter, reflecting growth and rate base partly offset by the timing of O&M recovery. Gas, electric and other margin contributed combined to add $0.07 per share compared with last year's fourth quarter reflecting GSMP II roll-ins the Conservation incentive program or CIP decoupling for both electric and gas, appliance service and other margins. On the expense side, O&M was flat versus the prior year quarter. Higher distribution depreciation and interest expense each reduce results by a penny per share reflecting higher plant in service and investment. Lower pension expense added a penny per share versus a year ago quarter and flow through taxes the impact of lower outstanding shares and other items added $0.10 per share compared to the fourth quarter of '21 with $0.07 of that amount reversing the timing impact of taxes from prior quarters in 2022. During '22, PSEG invested over $3 billion in planned capital spending to upgrade transmission and distribution facilities, enhance reliability and increased resiliency. In 2022, we also launched the IAP our $511 million infrastructure advancement program, which the BPU authorized last June to improve the reliability of the last mile of our electric distribution system and address aging substations and gas M&R stations. As Ralph mentioned a year in 2022 PSE&G's rate base stood at approximately $26.4 billion a 7.7% increase over year end 2021. Last Friday, the Board of Public Utilities approved an order authorizing PSE&G to modify its method of pension accounting for ratemaking purposes, which will mitigate variability in the calculation of PSE&G's pension expense for calendar year 2023 and beyond. The backdrop of economic conditions continue to improve in New Jersey during 2022. New Jersey's unemployment rate return to pre-pandemic levels of 3.3% in September, and remain below the national average at year end. System peak load reached 10,147 megawatts on August 9, exceeding the 10,000 megawatt level for the second year in a row. Weather normalized electric sales increased by 2% for the year with residential sales flat and CNI sales increasing by 3%. Weather normalize gas sales were flat for the year with residential gas sales down 1% while CNI sales increased by 2%. [The sale] mechanism because the impact of most customer usage from margin subject to earnings or rate cap limitations, leaving the change in the number of customers as the major driver of margin growth going forward. The number of electric and gas customer rose by approximately 1% each in 2022. Wrapping up the utility update. We've narrowed our forecast of PSE&G's net income for 2023 To $1.5 billion to $1.525 billion which reflects pension and OPEB updates compared to 2022 offset by the benefit of contemporaneously recovered investments, predictability of utility margin from the safety coupling, as well as the implementation of the pension accounting filing effective for calendar year '23. Now turning to carbon free infrastructure another. For full year 22 CFIOs net loss of $534 million or $1.06 per share reflected higher losses on both mark to market transactions and nuclear decommissioning trust fund related activity. The full year 2021 net loss included impairments and debt extinguishment costs related to the fossil sale. Non-GAAP operating earnings declined $174 million or $0.35 per share from $407 million for full year '21 reflecting the absence of the fossil assets. The fourth quarter 22 CFIOs net income improved to $436 million or $0.88 per share from $174 million in the year ago quarter, reflecting higher gains on both mark to market transactions and NDT fund related activities. Net income for the fourth quarter ‘21 included debt extinguishment costs and other charges related to the sale of fossil. For the fourth quarter 2022 the non-GAAP operating earnings loss of $34 million or $0.06 per share reflected the absence of the fossil assets compared to the fourth quarter 2021 non-GAAP earnings of $81 million or $0.68 per share, which reflected the cessation of depreciation and lower interest costs related to the fossil sale. Referring again to Slide 10, non-GAAP operating earnings were $0.22 per share lower in the fourth quarter than the fourth quarter of 2021 driven by lower capacity prices for the remaining nuclear fleet, but regeneration volume recontracting lower prices and lower deck revenue compared to the year ago quarter. Combined these items drove electric gross margin to decline $0.34 per share. Gas operations improved by $0.04 per share, reflecting higher off system sales, higher commodity pricing and higher stores. Power related cost comparisons for the fourth quarter 2022 improve his overall O&M expense was $0.07 per share favorable compared to the year ago quarter. Again reflecting fossil assets sale, partly offset by the plan refueling at the 100% owned Hope Creek nuclear plant in this year's fourth quarter. Appreciation and interests were higher by a penny per share that reflected the March 2022 debt issuance of power versus the year earlier debt retirements related to the fossil sale. Activity was a pay per share favorable compare the fourth quarter of 2021 primarily reflecting the essence of 2021's donation to the PSEG foundation, partly offset by higher parent interest of $0.04. Taxes and other improved by a penny per share over the fourth quarter of 2021 and includes the accelerated receipt of expected tax carried out claim in '22 instead of '23, which is partially offset by the reversing of a timing impact from tax benefits in prior quarters in 2022. Turning to ops. The nuclear fleet operated and an average capacity factor of 85.8% during the fourth quarter, which included the Hope Creek and 7.3 terawatt hours requirement for generation. An unplanned outage at Salem unit two in late December 2022 occurred during a PJM region wide generation emergency action and resulted in capacity performance penalties. The net financial impact of the outage including replacement power, capacity penalties, as well as bonuses earned by the other operating PSEG units did not expect it to be material. For the full year the nuclear fleet operated at an average capacity factor of 92.2% producing 31.3 terawatt hours of generation. PSEG's forecasting total baseline baseload nuclear generation of approximately 31 terawatt hours for the full year of 23 hedged 95% to 100% and an average price of $31 per megawatt hour an increase of about $4 per megawatt hour compared to '22. For '24 total nuclear generation is forecast also to be approximately 31 terawatt hours, and 55% to 60% hedged than an average price of $32 per megawatt hour. In addition, in December, we exited certain legacy BGS or basic generation service contracts in order to rebalance our hedge portfolio and realign it to our baseload nuclear fleet and reduce volatility in 2023. Wrapping up CFIO we've narrowed our forecast of non-GAAP operating earnings to $200 million to $225 million from $185 million to $235 million. A quick update on financing activity and collateral postings. As of December 31, 2022, total available credit capacity was $3.7 billion including a billion at PSE&G. In addition, we have total cash and cash equivalents on hand of approximately $465 million. PSEG power had net cash collateral postings of $1.5 billion at December 31 primarily related to as a money hedge positions resulting from higher energy prices, which declined to $700 million through last Friday. Given the recent improvement in our collateral position, in January of this year, we prepaid $750 of a $1.5 billion short term loan that was due in April. Following the repayment of this term loan, PSEG had outstanding a total of $1.25 billion of 365 day term loans expiring this spring to support powers collateral needs and power had an outstanding a $1.25 billion term loan expiring in March of 2025. Combined, these term loans comprise $2.5 billion a variable rate debt. As we mentioned during our third quarter call, we entered into interest rate swaps during September and October of last year, which converted $1.05 billion of our outstanding term loans from floating to fixed rate reducing our variable rate debt exposure. Following the measurement of the pension at year end 2022, we've incorporated the impact of the actual 2022 investment returns, discount rate and interest rates into the 2023 pension [calculations]. Our expected return on plan assets increased to 8.1% for 2023, as the declining value of the fixed income securities due to higher interest rates during '22 enables a higher yield on them going forward. While 2022 investment returns has a negative impact on 2023 pension calculations, the increase in interest rates serves to reduce the pension liability with the funded status of a pension plan, ending the year at a solid 87%. In addition, the county settlement approved by the BPU will create a regulatory asset or liability to overlay our current accounting, which will partly mitigate the impact of certain expense related pension calculations going forward. As Ralph mentioned earlier, we've narrowed our 2023 non-GAAP operating earnings guidance to $3.40 to $3.50 per share around the same $3.45 per share midpoint, with regulated operations continuing to contribute approximately 90% of that total. As a reminder, PSEG does not forecast GAAP earnings related and related long term growth rates. PSE&G's forecast of 2023 net income is narrowed to $1.500 billion to $1.525 billion reflecting the predictability provided by the expected transmission distribution investment recovery, and focus on owned and cost control. Non-GAAP operating earnings guidance for CFIO is now forecasted at $200 million to $225 million. CFIOs narrowed guidance also removed the previously expected benefits of the tax carry back claim from PSEG's 2023 operating guidance. That concludes our prepared remarks. So Shamali please open the line. And we'll take some questions.

Unidentified Analyst:

Good morning Ralph and team. It's actually Constantine here for Shar. Congrats on the quarter.

Unidentified Analyst:

Just wanted to start off with '23 guidance updates, and specifically on the utility. Do you have any updates on the O&M cost initiative targets and interest costs that are embedded in guidance versus what was presented in November especially as you're finding down some of the collateral needs. And just maybe to clarify, was the pension outcome the main driver for the 15 million decrease at the top end of the guidance?

Dan Cregg:

Yes Constantine the only I would add from O&M standpoint, we would have been a culture of continuous improvement. And we'll continue to look for opportunities when they arise, but we don't normally publicize any specific numbers on that area.

Ralph LaRossa:

Yes, I think, we sell on it that that exit from motion when one would be at our cost to date. And we've characterized it as being right around $200 million just in just an excess of $200 million, so that it certainly is nice to have back but it's not a major item to move the needle with respect to the broader numbers. I think we've talked about having an overall as a footstep threshold 13% to 14%. And we've talked in the past about living somewhere north of that into the 15, 16 area. And I think that's a fair way to continue to think about where we are.

Ralph LaRossa:

Yes. So we'll have our normal run rate operating capital. And to the extent that there's an opportunity to deploy capital to enhance results overall. Obviously, that analysis is going to go through just like any other analysis, we would do and be up against the hurdle rate that's going to show that it's going to make sense for us to do that. I think we have some promise on some things going forward. And maybe we'll give you a little bit more color about that, as we get a little further down the road on it.

Ralph LaRossa:

About the CapEx?

Ralph LaRossa:

We talk to our callers all the time. I mean, that's just the normal operating but nothing specific. Yes.

Operator:

Our next question comes from the line of Jeremy Tonet with JPMorgan. Pleae proceed with your questions.

Ralph LaRossa:

Sure. Yes.

Ralph LaRossa:

Yes. So Rich, just unequivocally we're not going to be in the offshore generation business. I mean that and the timing of what we do, we'll just be keeping an eye on the market and see what makes sense.

Ralph LaRossa:

So I would kind of say, there's a lot of good news in that announcement last week for a company like ours, and especially one, it's been focused. We kicked off this effort on the last mile last year and I think this just kind of reinforces the need for it from a customer standpoint, and from a reliability standpoint. So lots of opportunities. We'll certainly be engaged in that. I personally am tripling down on electric vehicles as much as we can in this area, and that's driving the decarbonisation in the state. And then from a gas system standpoint, certainly some push on whether or not there's a lot of expansion of the gas system, we have about a high 80% saturation rate for our customers. So we never had our business plan set up for growth on the gas side. That's not in our numbers. We just kind of hook up customers, as they call this, but our replacement plans are completely aligned. If you look at the wording that's in the executive order by reducing methane emissions. So we think there's just a lot of positives in that announcement. And we'll work with the state and policy makers on whatever we can self drive that in the Energy Master Plan.

Ralph LaRossa:

It’s 35,000 acres, and so there's about 35,000 acres that are still available to some degree, we've committed some of that are set if they go ahead skip check. I don't have the exact numbers in front of us, but it's a de minimis amount of that 35,000.

Unidentified Analyst:

Great. Thank you for the time today.

Operator:

Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Dan Cregg:

Yes. I guess I'm the first question. I think that's a reasonable way to think about it, although you will see as you step through time, some of the components elements under changing. So it's not a I think it's a fair way to think about where we sit today. But as we step through time, some of that could move as some of the component elements end up changing. I think with respect to the list that we've talked about a little bit in the past, we are continuing to explore that as a potential. Again, as a reminder really what that does is just shrink the overall size of the pension for us. And I think that potential still exists for us we're still doing diligence on it and we're working our way through the process. And we'll have some more information for you as we go through the year. But I wouldn't expect anything to be imminent but I would hope to see something happen this year [indiscernible] Durgesh.

Operator:

Durgesh are you on mute? Not sure he's still connected but --

Operator:

Sure. No problem. Our next question comes from the line of David Arcaro with Morgan Stanley. Please proceed with your question.

Ralph LaRossa:

Hey Dave.

Ralph LaRossa:

Yes. So a couple of things on that front, on the just from an O&M standpoint, as you recall, the inflation reduction act required anyone who wanted to participate in the PTC or not participate, but fully participate in the PTC to pay prevailing wages at the sites. And we have been doing that for years here at PSEG. So no awkward O&MM impact for us. I don't know if there's anything beyond that the others are talking about, but specifically for us, I don't see anything that would be driving additional O&M expenses at those plants. And then on a fuel supply. We were not as dependent on Russian fuel supply, as at all for our fuel supply. So it's not an issue for us that we needed to get in front of, and I think we'll talk a little bit more about that at the, at our investor meeting. But I just it's, again, that's something that was forefront for us or something that we had to proactively address. Because we're not, we're just not in that marketplace. I think there's an impact on the entire market. There'll be an impact for everyone. But that's something we are trying to jump in front of right now.

David Arcaro:

Got it. Got it. Thanks. That's helpful. And then I just wanted to clarify on the collateral postings. It's great to see that they've come down maybe sooner than expected. I was wondering if you could just remind us of how the collateral kind of falls off through the year and is that earlier than you had previously anticipated I think $800 million that you were able to pay down earlier? Is that helpful for EPS in terms of taking some of the short term debt off the balance sheet for this year?

David Arcaro:

Okay, great. Thanks so much.

Operator:

Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.

Durgesh Chopra:

I am. Can you hear me now?

Durgesh Chopra:

Okay, sorry about that. It was actually my headset. So Dan, thank you. I heard all of that. I appreciate it. Just the lift that was roughly another 20% to 30% that would reduce the pension volatility by and so if you were able to get that successfully, the uplift successfully executed that would essentially basically kind of the 50% of the pension expense volatility would have been taken care of includes [indiscernible] order last week. Am I thinking about that correctly?

Durgesh Chopra:

Yes. That's right.

Durgesh Chopra:

Okay, perfect. And just one last one again in terms of timing, you might have said that, expect an update sometime this year. So by Analysts Day or Investor Day in March, we shouldn't be expecting that you get a you get a bench and lift out, right. That's coming later in the year?

Durgesh Chopra:

Thank you so much. I appreciate it again, guys. And thank you for bringing me back in time to ask my questions.

Ralph LaRossa:

Take care of the headset.

Ralph LaRossa:

Hey, Michael.

Ralph LaRossa:

Yes. No, that's not. Look I would say this The Michael, if you walk out of that meeting with even more confidence in our ability to execute on the things that we've been talking about that would be my goal for that investor meeting. We've done that over the last year in some crazy turbulent times. And I think that you'll see more of that. And I want you to walk out of that meeting with more confidence. So more than doubling down on some of the things that we've got planned in the utility. And that should be the real highlight of the conversation a little more about our thoughts about how to respond to the governor's call for action.

Ralph LaRossa:

Yes, and just so we are 100% clear, we have not received the $200 million back yet, right? That's in the process with our partner, and we're going through dotting the I's and crossing the T's in that whole conversation. So more to come on that front. But I think the materiality of the GSOE is a TBD. And we'll see what the market gives us on that front. And then Dan, and the team will do what Dan and the team have done for many years and put it to the best use.

Ralph LaRossa:

No, I just don't want to, we're not building a plan that's built that's based on getting some New York bight multiples on it. So I don't want people to walk away with some inflated opinion on what those acres are going to be worth. We'll see what the market comes back with.

Ralph LaRossa:

Yes.

Julien Dumoulin-Smith:

Hey, good morning team. Thanks for the time. Appreciate it. Good to chat with you guys.

Julien Dumoulin-Smith:

It's been a second year. Absolutely. I'm so just with respect to how you guys want to come back to this real quickly. A couple different moving pieces. First off, if I heard right in the comments, BGS here, you guys are moving away from that seems like a slightly more important strategic decision after years of benefiting there. Can you talk about that a little bit here, again, obviously not a big contribution. But then also related here, probably more critical and looking forward here what's your latest interpretation of the PTC and how that interplays with your 24 hedges and ultimately how you think about hedging right now, considering what IRS may or may not do?

Dan Cregg:

Yes, just to just to be super clear, Julian if you think about it, the BGS product is a default product in New Jersey on the electric side of the business. And so PCG power has used that as a hedge for a long time and PCG power had nuclear and fossil units and had a very shaped output, seasonality by virtue of having both nuclear and fossil generation. And as we sold the fossil units, and we still had some BGS obligations you think about those are three years at a time that was not an ideal fit for nuclear, which is more shaped in a more of a block power. And so really don't take too much from the sale of the BGS. It just those remaining legacy tranches were not a good fit for a nuclear output that looks more like block shape power. What is not is related to the BGSS, which is basic gas supply service that we provide to PSE&G Ng, and actually can leverage some of that excess capacity in a way that we've done for many years and will continue to do that. So the move away is for just the small remaining legacy tranches that we had on BGS on the electric side, that were taken on three years at a time and unrelated to BGSS. With respect to the interpretations, I would love to have more of an interpretation than I do right now. But we don't have guidance from Treasury related to how they will define grocery seats in determining what the PTC will be based upon. And so we are still a little bit at the mercy of what Treasury will do. I think the outcome of the PTC's is going to be positive and supportive. But the exact dynamics of exactly what numbers you would use to figure out what that's going to be is undetermined by that I mean to the other part of your question how they will account for hedges in their calculation. And so that's the guidance we're still waiting upon. I think that the outcome will influence how we will end up hedging the nuclear units. We will try to align with how they will define grocery seats so that ultimately the PTC that we get will kind of fit the overall mechanism as it's supposed to work. And we can end up with that steady ultimate result at the PTC threshold or above if the markets are higher and so we're still a little bit of a waiting game. And I don't even have a date to tell you when Treasury is going to come out with it. The PTC has come into play for the first time in Cal 24. Obviously, companies like ours hedge in advance of that. So I'd love to have information sooner rather than later. But other elements of the IRA do kick in 2023. So we have not heard back from Treasury, any guidance with respect to how they're thinking about that exact definition.

Ralph LaRossa:

No, I mean, look, I think the upshot is that to the extent that PTC is a payment for the attribute, and ZEC is the payment for the attribute, we will net back that amount to the state. And that was in the original ZEC legislation that was put together. And so I think if that's net over the long run, this is going to be a very good thing for New Jersey because the payment for the attribute that's going to help nuclear ensure that it does have financial backing is going to be borne by the federal government rather than just New Jersey, and that'll be a positive thing on the bills over the long run.

Julien Dumoulin-Smith:

Got it. Understood what you mean by that. Appreciate that. All right. Excellent. Thank you guys very much. Appreciate it. Actually one last quick one on power, just if you don't mind with respect to all the commentary from the governor's office, etc. are you thinking about updating investments around power and the opportunities to maximize value of those assets here? And we've seen some commentary again, from some of your peers there but again, given what's going on with the governor, etc. I'm just curious if that is even more of an opportunity.

Julien Dumoulin-Smith:

Got it. All right. That's what I thought. Thank you guys. Appreciate it. Good luck.

Paul Patterson:

Hello good morning.

Paul Patterson:

Just really quick just the extension of the licenses. Is that already reflected in the depreciation schedule of the assets?

Paul Patterson:

And how much might that lower the level of depreciation?

Paul Patterson:

Okay. Just over the years, we've seen different companies recognize these depreciation changes because of license extensions at different times. Some do it even before they file with the NRC. Some do it only when they get the NRC is official ruling on it. Any thoughts about when we might see the depreciation benefit show?

Ralph LaRossa:

And Paul let me just reiterate what Dan said about the timing. You got 36, 40 and 46 on these units. And normally, you would apply in about 10 years in advance. So just to kind of set the timeframe for you as to when the application going, we're just talking about it because it would be within the five years of our business plan.

Ralph LaRossa:

For the work done. Probably not for the receipt of the extension.

Ralph LaRossa:

Sure.

Travis Miller:

Hi, everyone. Thanks for taking my question.

Travis Miller:

On the transmission, the onshore of the offshore transmission, any update on solicitations or development there anything along those lines?

Travis Miller:

Okay, is a gating factor is the development in future off for when or would there be additional transmission for current?

Travis Miller:

Okay, makes sense. And then I said I mentioned about the rate case at the end of the year. Anything unusual about that that would come out or just typical operating costs, capital updates?