Ladies and gentlemen, thank you for standing by. And welcome to PSEG 4Q and Full Year 2020 Earnings Conference Call and Webcast. Please be advised that today's conference is being recorded. I would now like to turn the conference over to Carlotta Chan, VP, Investor Relations. Thank you. Please go ahead, ma'am.

Good morning and thank you for participating in our earnings call. PSEG's fourth quarter and full year 2020 earnings release, attachments and slides, detailing operating results by company, are posted on our website at investor.pseg.com, and our 10-K will be filed shortly.

Thank you, Carlotta. Good morning, everyone. And thank you for joining us for our 2020 review and future outlook. PSE&G reported non-GAAP operating earnings for the fourth quarter of $0.65 per share. Non-GAAP operating earnings for the full year rose by 4.6% to $3.43 per share, and mark the 16th year in a row that PSE&G delivered results within our original earnings guidance. PSE&G GAAP results were $0.85 per share for the fourth quarter of 2020 compared with $0.86 per share for the fourth quarter of 2019. In addition for the full year PSE&G reported 2020 net income of $3.76 per share compared with $3.33 per share in 2019. Details on the results for the quarter and the full year can be found on slides 12 and 14. I am pleased to report that the PSE&G's fourth quarter and full year results reflected solid contributions from both PSE&G and PSEG Power. And I'm particularly proud of the achievements of our employees during this past year as it was one of the most challenging in recent memory. Their efforts have kept our customers connected to essential energy services to power their homes, businesses, and vitally important institutions. We have also made steady progress in several key business priorities, the most important of which is our transition to becoming primarily a regulated utility, with contract and generation comprise about zero carbon nuclear fleet and future investments in regional offshore wind. In the past six months, we've announced the exploration of strategic alternatives for PSEG Power's 7,200 plus megawatts of non Nuclear Generating assets, and received initial indications of interest for both the fossil and solar source assets. PSE&G successfully initiated its landmark clean energy future program, securing approval to spend nearly $2 billion in energy efficiency, smart meter installations and electric vehicle charging infrastructure, all of which will enhance New Jersey's environmental profile for years to come. In addition, the New Jersey Board of Public Utilities, I'll refer to them as the BPU recently concluded public hearings regarding PSE&G nuclear application to extend the zero-emission certificate. I think I'll shorten that to ZEC from now on through May 2025. Our service area experience milder than the normal weather during the fourth quarter, book ending the week heating season of the first quarter in 2020.

Terrific. Thank you, Ralph. Good morning, everybody. As Ralph said, PSE&G reported non-GAAP operating earnings for the fourth quarter of 2020 of $0.65 per share. And we provided you with information on slides 12 and 14 regarding the contribution of non-GAAP operating earnings by business for the fourth quarter, and for the full year of 2020. Slide 13 and 15 contained waterfall charts that take you through the net changes quarter-over-quarter and year-over-year, and non-GAAP operating earnings by major business. I'll now review each company in more detail starting with PSE&G. PSE&G's net income for the fourth quarter of 2020 increased by $0.04 to $0.58 per share, compared with net income of $0.54 per share for the fourth quarter of 2019 as shown on slide 17. For the full year PSE&G's net income increased by $0.16 per share, or 6.5% compared to 2019 results. This improvement reflects an 8% increase in rate base at year end 2020 to just over $22 billion, which as we note on slide 22 does not include approximately $1.8 billion of construction work in progress or see what that's mostly a transmission. The continued growth in utility earnings resulting from investments in transmission added $0.2 per share versus the fourth quarter of 2019. Gas margin was $0.02 favorable, reflecting GS&NT roll in and higher weather normalized volume. Electric margin was flat compared to the fourth quarter of 2019. As higher were the normalized volumes will offset by lower demand? Mild temperatures during the quarter had a negative $0.03 per share impact, mostly reflecting recovery limitations under the earnings test of the gas weather normalization clause. O&M expense was flat versus the fourth quarter 2019. Higher distribution depreciation expense of a $0.01 per share offset lower pension expense of a $0.01 per share in the quarter. Taxes and other were $0.03 per share favorable, partly reversing the negative $0.07 per share impact that the timing of taxes had on third quarter of 2020. Recall in the third quarter flow through taxes and other items lower net income by $0.07 per share compared to the third quarter of 2019. And we indicated at that time that about half of the $0.07 would reverse in the fourth quarter. The balance is related to bad debts which we anticipate reversing in the future based upon the timing of actual write-offs. Early winter weather in the fourth quarter as measured by the heating degree days was 9% milder than normal and 14% milder than in the fourth quarter of 2019. The full year PSE&G weather-normalized residential electric sales increased by 5.6% due to the COVID-19 work from home impact, but a larger decline in commercial sales resulted in total electric sales declining by 2%. Total weather-normalized gas sales were up 1.2% for 2020 by a 4.9% increase in residential use partially offset by a smaller decline in the commercial and industrial segment. For both electric and gas sales, higher residential uses largely offset declines in commercial and industrial sales, resulting in stable margins overall. PSE&G invested $700 million in the fourth quarter as part of its 2020 Capital Investment Program of approximately $2.7 billion directed to infrastructure upgrades of transmission and distribution facilities to maintain reliability, increase resiliency, make lifecycle replacements and clean energy investments. PSE&G updated five-year capital spending plan includes investing $2.7 billion in 2021. And as detailed on slide 21, approximately $960 million is allocated to transmission; $700 million to electric distribution, which includes approximately $200 million for Energy Strong Two, $875 million to gas distribution, which includes over $400 million for GSMP2 and $200 million for new clean energy future EV programs and the beginning of the AMI rollout. The clean energy future EV investment will ramp up to approximately $125 million in 2021 before reaching a full annual run rate of about $350 million in 2023. As Ralph mentioned the BPU approved two CF settlements in January, totaling approximately $875 million covering energy cloud and electric vehicle investments. The capital and operating costs of these programs will begin to be recovered in PSE&G next rate proceeding, expected to be filed in the second half of 2023. From the start of the programs until the commencement of new base rates estimated in late 2024, the return on other non-capital will be included for recovery in these rates as well as operating costs and stranded costs associated with retirement of the existing leaders. Of these amounts, the vast majority about 90% received contemporaneous or near contemporaneous regulatory treatment either through the first formula rate, or clause recovery mechanisms or recovered and rates as replacement spend or new business. As Ralph also mentioned, we continue settlement discussions with the BPU staff and re-counsel regarding our FERC transmission return on equity. Although our forecast for 2021 as soon as the resolution effective in the near term, those discussions remain confidential and ongoing. PSE&G net income for 2021 is forecasted at $1,410 million to $1,470 million which reflects an assumed reduction of our transmission formula rate, as well as incremental investment in EV infrastructure and energy efficiency. So moving to power, PSEG Power reported non-GAAP operating earnings of $0.10 per share in the fourth quarter unchanged from the non-GAAP results in the fourth quarter of 2019. Results for the quarter brought Power's full year non-GAAP operating earnings to $430 million or $0.84 per share. Compared with 2019 non-GAAP results of $09 million or $0.81per share. Non-GAAP adjusted EBITDA total to $182 million for the quarter and $990 million for the full year of 2020. And this compares to non-GAAP adjusted EBITDA of $198 million, and $1,035 million for the fourth quarter and full year 2019 respectively. Non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure, as well as income tax expense, interest expense, depreciation and amortization expense. The earnings release and the waterfall on slide 13, and 15 provides you with a detailed analysis of the items having an impact on PSEG Power's non-GAAP operating earnings relative to net income, quarter-over-quarter and year-over-year from changes in revenue and costs. We've also provided you with added detail on generation for the fourth quarter and full year on slide 26. PSEG Power's fourth quarter non-GAAP operating earnings were aided by the scheduled increase in PSEG Power's average capacity prices in PJM, covering the second half of 2020 and higher gas operations, which resulted in improved non-GAAP operating earnings comparisons of $0.04 and $0.01 per share respectively, compared to the fourth quarter of 2019. However, lower generation output and re-contracting at lower market prices reduced non-GAAP operating earnings by a total of $0.08 per share versus the year ago quarter. The decline in O&M expenses in the quarter improve results by a $0.01 per share and reflects the absence of the Hope Creek refueling outage that occurred in the fourth quarter of 2019. The extension of the Peach Bottom Nuclear operating licenses contributed to lower depreciation expense of a $0.01 per share and lower taxes improve non-GAAP operating earnings by a $0.01 over the year ago quarter. Gross margin for the quarter was $32 a megawatt hour, a $1 per megawatt hour improvement over the fourth quarter of 2019, mainly reflecting the scheduled increase in capacity prices that began June 1, 2020 and remain in place through May of 2021. For the full year 2020 gross margin was flat at $32 per megawatt hour compared to full year 2019. Mild fall temperatures and holiday related spikes and COVID-19 positivity rates dampen market demand in New Jersey and kept our prices and natural gas prices lower than the quarter and year ago comparisons. So let's turn to Power's operations. Total output from Power's generating facilities declined 9% in the fourth quarter of 2020, compared to the fourth quarter of 2019. Unplanned outages at fossil and an extended outage at the sale of one nuclear unit reduced fourth quarter generation levels compared to the fourth quarter in 2019. However, full year 2020 output of 53 terawatt hours came in above our 50 to 52 terawatt hour forecast. The nuclear fleet operated at an average capacity factor of 78.9% in the quarter, and 90.3% for the full year, producing nearly 31 terawatt hours of zero carbon base load power. The combined cycle fleet operated an average capacity factor of 46.2% in the quarter, and 48.3% for the full year, generating approximately 22 terawatt hours in 2020. The three new combined cycle generating units, Keys, Sewaren and Bridgeport Harbor 5 posted an average capacity factor of over 75% for the full year 2020. And this coming June PSEG Power will complete the planned early retirement of the 383 megawatt coal fired Bridgeport Harbor 3 generating station, eliminating the last coal unit in power's fleet. For 2021, Power has hedged approximately 90% to 95% of its expected output of 48 to 50 terawatt hours, at an average price of $32 per megawatt hour, which represents an approximately $2 per megawatt hour decline from 2012. In addition 2021 average hedge prices no longer include cost-based transmission charges for New Jersey's basic generation service contracts due to a change in how they are billed and collected. This change further reduces revenues by approximately $3 per megawatt hour starting on February 1 of 2021. And is often on the cost side so there's no P&L impact as a result. We're forecasting 2021 non-GAAP operating earnings and non-GAAP adjusted EBITDA PSEG Power to be $280 million to $370 million and $850 million to $950 million, respectively. Power segment guidance reflects a full year of fossil and solar operations, lower expected generation volume and lower market prices, as well as the absence of a one-time tax benefit realized in 2020. Now, let me briefly address operating results from enterprise and other which reported a net loss that increased by $0.03 per share, compared to the fourth quarter of 2019. And reflects lower tax benefits compared with the fourth quarter of 2019 and lower results from KCG Long Island. Regarding PSEG Long Island, following several challenges related to our response to tropical storm Isaias. We've made significant improvements in our outage management to lessening business continuity and other systems and processes. The Long Island Power Authority filed a complaint against PSE&G Long Island in New York State court last December, alleging multiple breaches of the operating services agreement or OSA in connection with PSE&G Long Island's preparation and response to tropical storm Isaias. We are in discussions with LIPA to address their concerns, which could include potential amendments to our OSA with LIPA and to resolve all claims. As a reminder, our 12-year contract is scheduled to run through 2025. We are committed to addressing the identified performance issues and to continue our strong track record of performance for Long Island customers since taking over operations. For 2021, PSEG Enterprise and other are forecasted to have a net loss of $15 million as parent financing and other costs exceed earnings from PSEG volume. PSEG ended 2020 with approximately $3.8 billion of available liquidity, including cash on hand of $543 million, and debt representing 52% of our consolidated capital. In December PSEG issued $96 million of 8.63% senior notes due April 2031, in exchange for like amount of 8.63% senior notes due April 2031, originally issued at Power, which were cancelled following the completion of the exchange. PSEG also retired a $700 million term loan at maturity. Power's debt as a percentage of capital declined to 27% on December 31 from 28%, at September 30. To summarize non-GAAP results for the quarter was $0.65 per share; full year non-GAAP operating earnings were $3.43 per share. And as we move into 2021, our guidance for the year is $3.35 to $3.55 per share, with regulated operations expected to contribute over 80% of consolidated results, arranged for 2021 reflects incremental investment in our T&D infrastructure, and a ramp up of a new clean energy future programs, as well as an assumed reduction return on equity of our transmission formula rate during the year at PSE&G. And a full year of fossil and solar operations at PSEG family. PSE&G also raised its common dividend by $0.08 per share for the indicative annual level of $2.04, a 4% increase over 2020. The 2021 indicative rate continues to represent a conservative 59% payout of consolidated earnings at the midpoint of 2021 guidance and utility earnings alone are expected to cover 140% of the dividend at the midpoint of 2021 guidance. We still expect our strong cash flow will enable us to fully fund PSE&G's five year $14 million to $16 billion capital investment program, as well as our plan to offer when investment during the 2021 to 2025 period without the need to issue new equity. That concludes my comments. And Shelby we're now ready to take questions.

Your first question is from Jeremy Tonet of JPMorgan.

Hi, good morning. I'm just wanted to start off with the Power by sales if I could, if there's any additional color that might be possible, including maybe the relative progress of solar versus the wind assets they're in, if the events in Texas last week have any impacts on the process overall.

So I'll handle it because Dan will be too modest when Dan laid out for the board in July. But this process would look like in terms of participants timing, expected outcomes. I knew he'd done good work in terms of assessing it and coming up with some predictions. But I got to tell you, he's nailed every element of it. So the process is going exactly as planned. Our near-death experience in January of 2014 with our own polar vortex really has winterized these assets in a way that I'm sure Texas will now follow suit with. So no, Texas has not had any impact on us. I don't apologize for not being able to give more information, we will give greater clarity sometime in the summer, I'm sure as we get past the round two bids but so far, no surprises, the process is going well. And our assets are fully winterized as a result of the 2014 polar vortex we experience.

Got it, that makes sense. Maybe just kind of flipping over to the transmission ROE and just what time expectations per transmission ROE reduction are incorporated into your 2021 guide here? And should we assume any changes on a prospective basis versus having a retroactive impact as well?

Yes. The second question, when I can give greater specificity on, yes, it would only be prospective. Typically, when something is filed in FERC, notwithstanding the time lapse to the actual decision, the tariff adjustments go to the filing date and not sooner. So yes, it would be prospective as you can appreciate, just given the nature of the negotiation that we're involved in, we really can't disclose what we've assumed in terms of the guidance. But that shouldn't be a big surprise. I mean, we don't break out the guidance in terms of individual components, whether it's weather or outage durations of plants and things of that nature. So we are where we were for a while now, we're close, both sides are eager to resolve this. But in deference to the BPU, they've had an incredibly active agenda for the better part of two years. And they are dealing with the same challenges everyone else's in terms of working from home. And despite that they've successfully done one offshore wind solicitation and in the middle of the second one. They've done stakeholder prophecies to energy efficiency, so they're getting a lot done. And this ROE discussion is part of that - is part of the portfolio activities, but not resolved yet.

Got it, fair enough. Figured I'd give it a try. Thank you.

You won't be the first; you won't be the last I am sorry. You were the first.

Your next question is from Julien Smith of Bank of America.

Hey, good morning, team. Thanks for the time and the opportunity. So what intriguing in your slides, you talked about potential investments in offshore wind here as well. Can you talk about; obviously, this is dynamic, and certainly evolving from quarter-over-quarter. Can you talk about your latest expectations on offshore and how they could fit into your capital budgeting process and earnings all together as best you see to date between expanding ownerships and potential new leases, et cetera?

So, just a high level, Julien, I'm sure you're aware that there's an ongoing solicitation in Maryland. There's a second round in New Jersey, we have not fully developed our jointly owned Garden State Offshore Energy site jointly owned with Ørsted down off of the coast of Cape May. So there have been 29,000, I think, megawatts of hopes and dreams announced by states up and down the East Coast and 9,000 megawatts of awards granted. So even if we were to just focus in the Mid-Atlantic region, going from Maryland to Delaware to New Jersey, there are ample opportunities. And as I said, a moment ago, we still have leasehold that's not fully developed. So I don't think we've set it any more specific than that right, Dan. So we'll just probably leave that there.

But maybe if I can ask you to put parameters or how you think about this business, maybe either be more palatable, right? For instance, how do you think about return metrics? And palatability obviously, we see some data points out there, and the Americas and Europe of late and separately, you have any thoughts about what percent ownership in a given project, et cetera, what size it should be relative to the business, anything that you're thinking about to help size it out? And even at the minimum or how you think about the return palatability, if you will?

Yes, I mean so first of all, I think is that we don't view ourselves as the lead developer, we do this in partnership with others. And we have an option for 25% on ocean land, and we have entertained, possibly going as high as 60% previously on this project, there is likely to be a transmission solicitation that will be managed by PJM on behalf of New Jersey, that we feel very confident that we could do something of that sort without necessarily needing partners although we will be welcomed to partnerships in that regard too. I think at the end of the day, our number one growth engine remains rate base growth and PSE&G. Having said that, there's a window of opportunity here as states aggressively pursue offshore wind, and we don't - have ourselves excluded from that. The commercial risk is completely mitigated by the PPA or the orders. And the operational risk is mitigated by making sure you partner with a world class partner. And we think we have that in Ørsted. So the risk profile is something that we're now comfortable with. It took us the better part of I guess it was close to two years of us kind of inching along, and we're very grateful for Ørsted's patience. But on the transmission side, I think the risk reward and we're very comfortable with, we always were and on the wind farm side, having the right partner mitigates that. We've never disclosed what our hurdle rates are, but suffice to say we, even though I think we can manage the risk, both the commercial and the operational risk, as I just mentioned, we wouldn't do these projects alone and we would only do these projects for about utility returns.

Actually I know think about too is if they come about solicitation by solicitation. So as far as what the ultimate end game is going to be, it gets determined in those bite sized chunks as we work our way through both New Jersey, Maryland and transmission opportunity that Ralph talks about, so that will be the manner in which we will come to what the ultimate outcome is.

Your next question is from Michael Lapides of Goldman Sachs.

Hey, Ralph, thank you for taking my question. One on the utility just looking out at the CapEx guidance. I want to make sure I understand something, I'm looking out at this and it basically has transmission spins falling off a cliff. Meaning spending levels year by year. Just curious, when you think about the type of things that may backfill it to maybe where it doesn't fall off as much in years, three to five? What are the types of things-- what are the type of opportunities that your engineering teams are looking at?

Yes, a couple things that happened, Michael is that even though the numbers look like they're coming down in years, four and five, as we get closer to that point in time, we learn more, and that very spend comes back up. So one thing you could see is just more of the same, you're not going to see us thus plan rose one mega project at least that's not readily predictable. But you could see more of the 69 kV upgrade and just the transmission budget coming up, as we get more knowledgeable about what the good status is. I think one of the areas though, that we are increasingly paying attention to and it's difficult to quantify is as a result of the pandemic, I believe long term patterns, lifestyle titles are going to change. I know a PSEG, were already telling our employees that many more than we'll be able to work from home. The combination of the household becoming now a place of business and greater penetration of electric vehicles, which are charged at the household. And the growth of electric devices in the home, whether it's smart devices, communication devices, is really changing the whole calculus behind the importance of reliability into the home. So I'm right now in the office with Dan and Carlotta, and we've got multiple 26 kV feeds into this building. Because Newark is a commercial center for New Jersey. That's true in New Brunswick, and many other downtown commercial areas of New Jersey. That's not true in my hall. And it's not true anybody's hall New Jersey, so the need to invest in the last mile to reflect the reliability expectations, as the home becomes a commercial center. And really a bunch of small business operations is a public policy discussion that I think is just beginning to take place. And there's no way reflected in our numbers. So I'd say you'll see those numbers come up in the future, they always come up in the future, either, because we'll just get smarter about the traditional stuff we need to do. Or there's this whole last mile question that we'll need to grapple.

Got it. And then my question is this a little bit of maybe one for Dan, in the rate based by your exhibit, one of the footnotes talks about the billion a day and you brought it up the billion eight of transmission that is construction work in progress. Can you remind me you earn on that quip you just don't necessarily earn a cash return even that prompt here?

Yes, we aren't on equipment, frankly. Michael, the reason that it really is in there is from the concept of when folks have done the calculation and tried to figure out whether or not there was over earning going on. The people sometimes would miss the equip component. And so all we really tried to do was lay that out so that people were aware.

But if I think about the true earnings power of the business meaning of transmission rate base, I would actually add that on top of the fact bars.

Yes, right. Exactly.

Your next question is from Steve Fleishman with Wolfe Research.

Hey, good morning. Hey, guys. So just a question on the 80% to 90% from PSE&G that you highlighted Ralph. So that's a little bit less than I would have thought after selling these fossil assets. And I know you mentioned offshore wind, but that's not for a while. So could you just give us is it more like 90% once the sale is done and before the offshore wind? And then it kind of comes down again, some or how should I think about that range?

Yes, so listen building blocks that I'm sure you're aware of it, Steve, right, so the foundation, the house, the roof, everything, but maybe the unnecessary furniture is the utility. And that's got a rate base CAGR of 6.5% to 8%. And that'll do a little worse, because of O&M are a little better because the load growth. But as you know, both those numbers have hovered around zero. And they'll be some regulatory lag, maybe in some of the final years as clause mechanisms have some non clause recovery back into them. But that's utility is what 80% this year close to that, and continue to grow. Then this year, we're still including all fossil that'll go away. But hopefully, New Jersey will abide by their own energy master plan, and nuclear will still be around. So that'll be on top of the utility. You may recall our BGSS that sticks around that's on top of the utility. Long Island notwithstanding, you saw its challenges worse and we will stick around. That's why I'm talking truly. And then yes, we're making some assumptions in year 2024, mostly 2025, on Ocean Wind. So those are making up the other 10% to 20%. And I'd rather not narrow that and I certainly don't want to give it to you by year, I do want to remind you that we are very much interested in willing after the, if we sell the fossil units or when we sell the fossil units, once this process is over, going to revisit the notion of multiple year earnings guidance and investor meeting where we kind of recalibrate everyone and try to provide greater clarity of what the company looks like with those different components. But right now we're in the middle of a competitive solicitation for the assets in the middle of the ZEC negotiation and ROE negotiation that's what I can give for you so.

Okay. And then one other question just on nuclear, if I heard you right, I think you reiterated that you would shut the nuclear plants. But I think you said if the ZEC is anything but the $10 it currently is given the market prices are even lower. Is that correct or?

That was correct, Steve. We value our corporate citizenship in the state. And I think we've shown over the past few months, how important it is to follow the BPU's leadership in terms of its clean energy aspirations and Governor Murphy's aspirations, we've had some very constructive outcomes because we have followed their lead on energy efficiency, on AMI, on electric vehicles. Having said that, the nuclear plants need more than $10. And what we've said is we'll look at longer term solutions for that and hopefully coming out of the federal government with a price on carbon. Hopefully, if that doesn't work coming out of the FRR process. And that's the only reason. And the only reason why we would accept $10 now is because that's what the state can do. So that's really not a negotiation, that's just kind of a match the state has available to it. That's why we need it. And we need more than that. So that's kind of where we start, right? If you need more than $10, you can't accept less than $10. And whenever the party can only offer you $10, then that Venn diagram ends up at one point and only one point, which is $10. But that does not preclude the need for additional work after that. And at the risk of stating the obvious if you don't get the $10 then what confidence can you possibly have, that the longer-term solution can be realized, and that's why we would shut the unit. So I guess I could have simply said yes to you but I gave you maybe wife's explanation over that.

Your next question is from David Akira of Morgan Stanley.

Hi, good morning. Thanks so much for taking the question. I was going to ask a basically a follow up on that last line of thinking with the new FERC in place, do you think there is chance that New Jersey doesn't end up pursuing FRR if it sees a new path ahead for morpher and how do you think about your strategy with a nuclear plant if that were to happen?

So I mean the short answer is anything is possible, right? And I think what New Jersey's goal is at least what we've encouraged New Jersey to set as its goal. And it wasn't because we any better insights than the state already did are to not pay twice the capacity. And under the current construct, without question, offshore wind will not clear the market. At some point in the future, it's likely nuclear won't clear the market; I'm referring to the capacity market. And solar certainly won't clear the capacity market. So as New Jersey grows its carbon free footprint and even its existing carbon free footprint from nuclear, you'd have increasing double payments for capacity, and it is about $25 million to $30 million per gigawatts that you end up paying. So that starts adding up very quickly. Now, if you went to a unit specific FRR, which is something that we were supportive of, during the original capacity market discussions, if PJM could come up with some sort of stakeholder process that has a reasonable price on carbon, there's a whole bunch of ifs and no, bore you with the litany of them, because they're all equally improbable, then yes, maybe the state can do something differently than simple, broad based FRR. But at the end of the day, the mechanism has to be one that avoids the customer a burden of paying twice for capacity that truly would be outcome.

And David, to some degree, it also comes down to timing. So as things stand today, you do have that double payment issue that Ralph talked about. And so your question is, if something changes at work with something changed in New Jersey, and so part of it comes down to how quickly might you see something change at work? And where would New Jersey be in their process, and these things tend to not happen extremely quickly. So against that backdrop, you do start to have that double payment Ralph talked about in 2025. So it's a bit of unnecessarily raise but it's two timelines coming to that year's capacity determination with respect to how quickly FERC can move, and what New Jersey's reaction would be to whatever it is they do and how much of a solution it is to the double payment problem. So those are some of the things to think about with respect to how the parties might be approaching that change from the

Got it, that's helpful color. And just in terms of how that influences your strategic thinking around the nuclear plant, it sounds - is it fair to say, if you do get a $10 ZEC, you still think there's more that would be needed for the nuclear plants to provide longer term clarity beyond just getting that though?

Yes, chipping become obvious since the passage of the law 2018, how markets continued to decline is more so than we expected them to. That's only going to get worse as more zero marginal cost renewables are introduced to the market. And we're in a market that dispatches on marginal costs. And nuclear plants rely on those infra marginal revenues to make their economics work. And that dispatch curve is getting flatter and lower each passing year. Secondly, the state has very ambitious carbon free energy goals which are great, which we completely applaud. But they're so ambitious that they exceed the current licensed life of the nuclear plants. And you're not going to go into re-licensing, and you're not going to make capital improvements on the basis of the three-year ZEC process, even if it was adequately compensated, which it isn't. So the two problems with ZEC law are the overall dollar amount and the duration of the review process. So and we've sworn that over the past few years, if the market continues to implode on itself, so for nuclear plants, our fossil does right, they're running 70 plus percent of the time and Dan said they're enjoying nice spark spreads and they're working beautifully. So yes, longtime nuclear questions and equalization, but there are multiple pathways to get there.

Your next question is from Paul Fremont of Mizuho.

Hey, how are you? Just a quick question on the hedging. There were, I think some other adjustments that were originally in your hedge calculations, like some renewable programs and maybe ancillary charges. Are those eliminated as well for now? Should there be sort of no adjustment whatsoever to the $32 number that you're providing?

No, think about the opposite way, Paul, the single change is the Delta with respect to transmission charges.

So you would continue to add the other charges into your number?

Yes, or stated another way, not try to back out those pieces as a revenue-oriented number, we've stripped out capacity as a separate item. And now, since transmission is not in the revenue, it will not be in the revenue.

Okay. And then the other question I have is you have a 25% option, obviously, on Ocean Wind, if you were to go to a higher level, would that just be a separate negotiation that you would need to have with Ørsted or are there any contractual rights that you have to go higher?

We have to get there, Paul, yes.

Okay, and then the last. If I take your comments, you guys don't want to be sort of a majority project. So the limit of where you would be is roughly 50% or less?

That's correct.

So I think we're at the appointed hour. Thank you all for joining us. Just by way of recap. The rate base grows with the utility as it has for the past decade and plus continues to drive the EPS growth at PSE&G, all the while, doing things that are vitally important to customers. And we continue to project now a 6.5% to 8% CAGR in that rate base over the next five years, doing things that are really driven by state policy leadership and an aging infrastructure that has to attract our attention to meet the need of customers. I think an add is a positive outcome from what has occurred last year is this consolation incentive program providing much greater even greater stability to utility revenues. The positive constructive outcomes we've had with the BPU, again, at the risk of repeating myself, by virtue of us following their lead on energy master plan and public policies, accomplishments that they had targeted, have all just made for a terrific, terrific set of outcomes. Yes, we do have an ROE and negotiation and A ZEC application that is in front of the BPU. Resolution to those two items will introduce a prolonged period of regulatory comm and significant execution of these great programs that we've gone through before. We will give you a greater clarification on the strategic alternatives in a couple of months. But I said a moment ago, I couldn't be happier with the fact that it's met every one of our expectations so far, and I think it will continue to do so. I would be remiss if I didn't close my remarks that I have, sadly, for each of the last three quarters by expressing my thanks to all of you who have family members or loved ones who are frontline workers and what is an improving situation to support a tragic situation related to COVID-19. I know that it's got to be a tremendous burden on you and your families, but please, from our family at PSEG a sincere thank you to anyone who knows is engaged in that. Otherwise, we look forward to seeing you albeit as pixels over the next few weeks. I know the budget conferences coming up and maybe in the not-too-distant future. Seeing you live into the flesh. Thank you. Have a great day everybody.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.