Ladies and gentlemen, thank you for standing by. My name is Christy and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group First Quarter 2021 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session for members of the financial community. At that time, if you have a question, you need to press the star and the number one on your telephone keypad. To withdraw your question, please press pound and the number one. As a reminder, the conference is being recorded today, May 5, 2021, and will be available for telephone replay beginning at 2:00 P.M. Eastern Time today until 11:30 P.M. Eastern Time on May 11, 2021. It will also be available as an audio webcast on PSEG's corporate website at investor.pseg.com. I would now like to turn the conference over to Carlotta Chan. Please go ahead. Thank you, Christy. Good morning. PSEG released first quarter 2021 earnings results earlier today. The earnings release attachments and today's slides can be found on the PSEG Investor Relations website, and our 10-Q will be filed shortly. The earnings release and other matters we will discuss on today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. We also discuss non-GAAP operating earnings and non-GAAP adjusted EBITDA, which differ from net income as reported in accordance with generally accepted accounting principles in the United States. Reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements are posted on our IR website and included in today's earnings materials. I will now turn the call over to Ralph Izzo, Chairman, President, and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on today's call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Ralph. Thank you, Carlotta, and thank you all for joining us today. I'm pleased to report that PSEG has achieved several major milestones on our path to becoming a primarily regulated utility company with a complementary and significantly contracted carbon-free generating fleet. PSEG posted solid results earlier this morning, reporting non-GAAP operating earnings for the first quarter of 2021 of $1.28 per share versus $1.03 per share in last year's first quarter. Our GAAP results for the first quarter were also $1.28 per share versus $0.88 per share in the first quarter of 2020. Results from ongoing regulated investments at PSEG and the effect of cold weather on PSEG Power drove favorable comparisons at both businesses. We present details of the quarter's results on slide five of the earnings presentation. We are well-positioned to execute on our financial and strategic goals for the balance of the year, given this eventful quarter. Beginning with our nearly $2 billion of Clean Energy Future programs, which have moved from approval to execution, PSEG is helping to advance the decarbonization of New Jersey in a sizable and equitable way. Our Clean Energy Future investments are paired with a jobs training program that offers opportunities to low and middle-income New Jersey communities. Last week, the New Jersey Board of Public Utilities voted unanimously to award a continuation of the full $10 per megawatt hour Zero Emission Certificates, I'll just call them ZECs from now on, for all three New Jersey nuclear units, that would be Hope Creek, Salem Unit 1, and Salem Unit 2, through May of 2025. This was the maximum amount that the BPU could have awarded. We are appreciative of the support received from the many community, labor, business, environmental, and employee organizations that participated in this enormously important process. Each of these groups recognizes the value of the reliable, around-the-clock, and carbon-free electricity supply our nuclear plants provide. Throughout this process, our nuclear team has approached operations at the units with the utmost professionalism and dedication to safety. I congratulate PSEG Nuclear for being recognized by INPO as an industry leader in operational reliability. One of only two nuclear fleets across the industry with no scrams over the past 365 days. The BPU's decision to extend the ZEC program will advance climate action in New Jersey by helping to preserve the state's largest carbon-free generating resource and is consistent with a growing interest at the federal level in preserving existing nuclear as an essential part of a clean energy mix. We applaud the BPU for its decision, which is in the best interest of the State of New Jersey and its ability to achieve its long-term clean energy goals without compromising reliability or going backward on environmental gains made to date. Looking ahead, we will soon work with stakeholders to obtain alignment of state and federal climate goals in seeking ways to extend the duration of support for carbon-free nuclear power. During the quarter, the BPU also approved PSEG's 25% equity investment in Ørsted's Ocean Wind project. In addition, Ocean Wind received a notice of intent to prepare an environmental impact statement from the Bureau of Ocean Energy Management, or BOEM, which will also review the project's construction and operations plan. In April, PJM, in close cooperation with the BPU, opened a four-month solicitation window to seek transmission solutions to support New Jersey's offshore wind generation target. This process is PJM's first public policy transmission solicitation, and we will participate in this proceeding. The recent Biden administration proposal focusing on climate action is clearly supportive of offshore wind, existing nuclear generation, and electrification of transportation, all of which are aligned with PSEG's business plan and strategy for sustainability. PSEG eagerly encourages and advocates for a national approach to accelerate economy-wide net zero emissions even sooner than 2050 in a constructive manner that expands green jobs by investing in clean energy infrastructure. I am more optimistic than ever that the momentum for real climate action is taking hold. PSEG continues to press ahead with our Powering Progress Vision that incorporates energy efficiency in the electrification of transportation to help our customers use less energy. We are pairing that with our move to make the energy our customers use cleaner, which aligns with our efforts to preserve our existing nuclear units and pursue strategic alternatives for our fossil fleet. We strive to deliver with high reliability and resiliency, which ties to our investments in energy infrastructure and the Energy Cloud. Today, we are also announcing progress on our strategic alternatives exploration with an agreement to sell our Solar Source portfolio to an affiliate of LS Power. The sale resulted from a robust marketing process, and we're pleased with the outcome of the sale. Having determined that the transaction is modestly accretive on the sum of the parts and on an operating earnings basis going forward. We expect the Solar Source portfolio deal to close in the second or third quarter of 2021, subject to customary, regulatory, and other closing conditions. PSEG Power is continuing the exploration of strategic alternatives for its fossil generating fleet and currently anticipates reaching an agreement around mid-year. These expected transactions, along with over a decade of capital allocation directed mainly toward PSEG, position the remaining company as a primarily regulated electric and gas utility with a complementary carbon-free nuclear fleet and offshore wind investments that will be highly contracted. The COVID-19 pandemic and its economic impacts continue to affect the New Jersey economy. The large contribution of the transmission and residential electric and gas components to our overall sales mix has had a stabilizing effect on the margins of our utility business, as does a supportive regulatory order that authorizes deferral of certain COVID-19 related costs for future recovery. Governor Murphy recently announced that a significant easing of COVID-19 restrictions on the state's businesses, venues, and gatherings would begin on May 19th, following progress in vaccinating over half of the state's population and a sustained reduction in positivity and hospitalization rates. PSEG has begun implementing the Clean Energy Future energy efficiency programs by initiating customer engagement and outreach, as well as advancing the clean energy jobs training program I mentioned earlier, and related IT system build-out activities. Following the BPU approval of our $700 million AMI proposal in January, we have begun implementation of the four-year program. Our current focus is on planning the AMI communications network, customer outreach, and developing the installation schedule of the new meters. On the regulatory and policy front, there are several upcoming developments at the FERC, the Federal Energy Regulatory Commission, the BPU, and PJM that could influence future results. Last month, FERC promulgated a new proposed rule to limit the 50 basis point RTO return on equity incentive to a three-year period. Given the Biden administration's interest in a significant transmission build-out to expand the integration of clean energy into the nation's power grid, this development was disappointing. We have long supported the need for higher incentives for transmission investment over distribution returns based on the added complexity and risk of these projects. Coordination through the RTO has benefits, myriad risks and complications must be considered as well. Based on the short comment window provided, the proposed rule could be enacted as early as the third quarter. We will file comments to recognize the merits of continuing the RTO adder, this looks to be an uphill battle given the chair's support for the supplemental rule. While we await the results of the first PJM capacity auction in three years, which PJM will announce on June 2nd, PSEG is continuing to advocate for a minimum offer price rule, I'll just call that MOPR going forward, that will avoid double payment for resources such as offshore wind and nuclear or other carbon-free supplies needed to achieve state goals. FERC Commissioner Danly has developed a state option to choose resources proposal or SOCR intended to achieve the major goals of establishing the right to states to choose their preferred capacity resources to achieve their energy policy objectives and eliminate double payments by states for the capacity they choose. This proposal could have the added benefit of keeping much of FERC's capacity market reform rules intact while addressing state objections. New Jersey is expected to issue its consultant's report and recommendation for resource adequacy this month. This report could determine whether a fixed resource requirement, or FRR, will be chosen to satisfy the state's future capacity obligations beyond the 2022 and 2023 energy year. We continue to believe that the state could pursue an FRR without legislation, and will suggest options to minimize the cost impact of first capacity ruling on New Jersey customers. Earlier in April, the BPU released its draft proposal to address the design of the Solar Successor Program. Stakeholder meetings are being conducted to consider a solar financial incentive program that will permanently replace the Solar Renewable Energy Certificate, or SREC program, and the temporary Transitional Renewable Energy Certificate, or TREC program, which was instituted in 2020 upon the state's attainment of 5.1% of kilowatt-hour sold from solar generation facilities. Given the substantial increase in New Jersey solar targets, the high cost of solar, and the solar cost caps in the Clean Energy Act of 2018, we believe it is critical to develop a cost-effective approach to incent future solar generation. By far, the most efficient and cost-effective way for New Jersey to optimize what solar can bring to the achievement of its clean energy goals, is to maximize grid-connected utility-scale projects by involving the state's electric distribution company. To wrap up my remarks, we are reaffirming non-GAAP operating earnings guidance for the full year of 2021 of $3.35 to $3.55 per share. Our guidance assumes normal weather and plant operations for the remainder of the year and incorporates the conservation incentive programs that begin in June for electric and in October for gas to cover variations in revenue due to energy efficiency and other impacts. In addition, as we mentioned on our year-end call, our 2021 guidance assumes a prospective settlement of our transmission return on equity at a lower rate and the inclusion of fossils results for the full year. We are on track to execute PSEG's five-year $14 billion-$16 billion capital program through 2025, and have the financial strength to fund it without the need to issue new equity. Over 90% of the current capital program is directed to PSE&G, which is expected to produce 6.5%-8% compound annual growth in rate base over the 2021 to 2025 period, starting from PSEG's year-end 2020 rate base of $22 billion. As we've noted previously, PSE&G's considerable cash-generating capabilities are supported by over 90% of its capital spending continuing to receive either formula rate, clause-based, or current rate recovery of and on capital. Finally, I thank our employees for their exceptional contributions to a compelling PSEG story this quarter. From nuclear operations marking a second breaker-to-breaker uninterrupted run at Hope Creek, to a cross-functional regulatory legal finance and government affairs group that multitasks on Clean Energy Future, ZEC, and a host of other regulatory proceedings, to our field crews in New Jersey and Long Island who exemplify a safety-conscious mindset. I could not be prouder of our entire PSEG team. Now I'll turn the call over to Dan for more details on our financial and operating results, and will be available for your questions after his remarks. Dan? Great. Thank you, Ralph, and good morning, everyone. As Ralph mentioned, PSEG reported non-GAAP operating earnings for the first quarter of 2021 of $1.28 per share versus $1.03 per share in last year's first quarter. We've provided you with information on slide 12 regarding the contribution to non-GAAP operating earnings by business for the quarter. Slide 13 contains a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business. I'll now review each company in more detail. PSE&G, as shown on slide 15, reported net income for the first quarter of 2021 of $0.94 per share, compared with $0.87 per share for the first quarter of 2020, up 8% versus last year. Results improved by $0.07 per share, driven by revenue growth from ongoing capital investment programs and favorable pension OPEB results. Transmission capital spending added $0.02 per share to the first quarter net income compared to the first quarter of 2020. On the distribution side, gas margin improved by $0.03 per share over last year's first quarter, driven by the scheduled recovery of investments made under the phase two of the Gas System Modernization Program. Electric margin was $0.01 per share favorable compared to the first quarter of 2020 on higher weather-normalized residential volume. O&M expense was $0.02 per share unfavorable compared to the first quarter of 2020, reflecting higher costs from several February snowstorms. Depreciation expense increased by $0.01 per share, reflecting higher plant and service. Pension expense was $0.02 per share favorable compared to the first quarter of 2020. Flow-through taxes and other were $0.02 per share favorable compared to the first quarter of 2020. This tax benefit is due to the use of an annual effective tax rate that will reverse over the remainder of the year and was partly offset by the timing of taxes related to bad debt expense. Winter weather, as measured by heating degree days, was 4% milder than normal, but was 18% colder than the mild winter experienced in the first quarter of 2020. For the trailing 12 months ended March 31st, total weather normalized sales reflected the higher expected residential and lower commercial and industrial sales observed in 2020 due to the economic impacts of COVID-19. Total electric sales declined by 2%, while gas sales increased by approximately 1%. Residential customer growth for electric and gas remained positive during the period. PSE&G invested approximately $600 million in the first quarter and is on track to fully execute on its planned 2021 capital investment program of $2.7 billion. The 2021 capital spending program will include infrastructure upgrades to transmission and distribution facilities, as well as the rollout of the Clean Energy Future investments in energy efficiency, Energy Cloud, including smart meters and electric vehicle charging infrastructure. PSE&G is continuing to defer the impact of additional expenses incurred to protect its employees and customers as a result of the COVID-19 pandemic. PSE&G has experienced significantly higher accounts receivables and bad debts, and lower cash collections from customers due to the moratorium on shutoffs for residential customers that began last March and has been extended through June of this year. We've launched an expanded customer communications program designed to inform all customers about payment assistance programs and bill management tools. As a reminder, PSE&G continues to make quarterly filings with the BPU detailing the COVID-19 pandemic-related deferrals. As of March 31st, PSE&G has recorded a regulatory asset of approximately $60 million for net incremental costs, which includes $35 million for incremental gas bad debt expense. Electric bad debt expense is recovered through the societal benefits charge and trued up periodically. With respect to subsidiary guidance for PSE&G, our forecast of net income for 2021 is unchanged at $1.41 billion-$1.47 billion. Now, moving to Power. In the first quarter of 2021, PSEG Power reported net income of $161 million, or $0.32 per share. Non-GAAP operating earnings of $163 million or $0.32 per share, and non-GAAP adjusted EBITDA of $321 million. This compares to first quarter 2020 net income of $13 million, non-GAAP operating earnings of $85 million, and non-GAAP adjusted EBITDA of $201 million. The earnings release and slide 21 provide you with a detailed analysis of the items having an impact on Power's non-GAAP operating earnings relative to net income quarter-over-quarter. We have also provided you with more detail on generation for the quarter on slide 22. PSEG Power's first quarter results benefited from a scheduled improvement in capacity prices for the first half of 2021, a favorable weather comparison to the mild winter in the first quarter of 2020, and other items, some of which are expected to reverse in subsequent quarters. The expected increase in PJM's capacity revenue improved non-GAAP operating earning comparisons by $0.03 per share compared with last year's first quarter. Higher generation in the 2021 first quarter added $0.01 per share due to the absence of the first quarter 2020 unplanned Salem-1 outage. Favorable market conditions influenced by February's cold weather benefited results by $0.03 per share compared to last year's first quarter. We continue to forecast a $2 per megawatt-hour average decline in recontracting for the full year, recognizing that the shape of the annual average change favors the winter months of the first quarter. The weather-related improvement in total gas sendout to commercial and industrial customers increased results by $0.04 per share. We expect some of this increase to gas ops will reverse later in 2021, reflecting the absence of a one-time benefit recognized in the third quarter of 2020 related to a pipeline refund. O&M expense was $0.03 per share favorable in the quarter, benefiting from the absence of first quarter 2020 outages at Bergen 2 and Salem- 1. A lower depreciation and lower interest expense combined to improve by $0.01 per share versus the year-ago quarter. Generation output increased by just under 1% to total 13.3 TWh versus last year's first quarter, when Salem Unit 1 experienced a month-long unplanned outage. PSEG Power's combined cycle fleet produced 4.7 TWh, down 8%, reflecting lower market demand in the quarter. The nuclear fleet produced 8.2 TWh, up 3%, and operated at a capacity factor of 98.8% for the first quarter, representing 62% of total generation. As Ralph mentioned, Hope Creek posted an uninterrupted run between refueling outages and just began its 23rd refueling outage in April. PSEG Power is forecasting generation output of 36-38 TWh for the remaining three quarters of 2021, and it hedged approximately 95%-100% of this production at an average price of $30 per megawatt-hour. Gross margin for the first quarter rose to approximately $34 per megawatt-hour, compared to $30 per megawatt-hour in the first quarter of 2020, which contained one of the mildest winters in recent history. Power prices in the first quarter of 2021 were stronger across PJM, New York, and New England compared to the year earlier period, and this winter's temperatures were 12% cooler on average and resulted in better market conditions compared to the first quarter of 2020. Power's average capacity prices in PJM were higher in the first quarter of 2021 versus the first quarter of 2020, and will remain stable at $168 per megawatt day through May of 2022. In New England, our average realized capacity price will decline slightly to $192 per megawatt day beginning June 1st. However, Power's cleared capacity will decline by 383 MW with the scheduled retirement of the Bridgeport Harbor Unit 3, achieving our goal of making Power's fleet completely coal-free. Over 75% of PSEG Power's expected gross margin in 2021 is secured by our fully hedged position of energy output, capacity revenue set in previous auctions, and the opportunity to earn a full year of ZEC revenues, and certain ancillary service payments such as reactive power. The forecast of PSEG Power's non-GAAP operating earnings and non-GAAP adjusted EBITDA for 2021 remain unchanged at $280 million-$370 million and $850 million-$950 million respectively. Now let me briefly address results from PSEG Enterprise and Other. For the first quarter of 2021, Enterprise and Other reported net income of $10 million, or $0.02 per share, for the first quarter of 2021, compared to a net loss of $5 million or $0.01 per share for the first quarter of 2020. The improvement in the quarter reflects higher tax benefits recorded in the first quarter of 2021 due to the use of an annual effective tax rate that will reverse over the remainder of the year, as well as interest income associated with a prior IRS audit settlement. For 2021, the forecast for PSEG Enterprise and Other remains unchanged at a net loss of $15 million. With respect to financial position, PSEG ended the quarter with $803 million of cash on the balance sheet. During the first quarter, PSEG issued $450 million of five-year secured medium-term notes at 95 basis points and $450 million of 30-year secured medium-term notes at 3%. In addition, we retired a $300 million, 1.9% medium-term note at PSE&G that matured in March. In March of 2021, PSEG closed on a $500 million, 364-day variable rate term loan agreement following the January prepayment of a $300 million term loan initiated in March of 2020. For the balance of the year, we have approximately $950 million of debt at PSEG Power scheduled to mature in June and September, $300 million of debt scheduled to mature at the parent in November, and $134 million of debt at PSE&G scheduled to mature in June. Our solid balance sheet and credit metrics keep us in a position to fund our 2021-2025 capital investment program without the need to issue new equity. As Ralph mentioned earlier, we are affirming our forecast of non-GAAP operating earnings for the full year of 2021 of $3.35 to $3.55 per share. That concludes my comments. Christy, we are now ready to take questions. One moment, please, for the first question. The first question is from the line of Julien Dumoulin-Smith with Bank of America. Good morning. Thanks for having me. Hey, good morning. Thanks, team. First off, if you don't mind, there was an article this morning here in Reuters, I believe, around federal support for production tax credits. Obviously, you all just received your own state-level support here on ZECs. Can you talk about how those two might mesh together, understanding that obviously, it's very early days on any federal effort here? Related to that, on the nuclear front, as you think about your cost reduction efforts and offsetting the dyssynergies, how should we think about the cost structure sitting above the nuclear plants, sort of once everything's said and done after this year if you think about that too? Hi, Julien. Thanks for your question. In the New Jersey statute, the 2018 statute, there's an explicit offset that would reduce the ZEC payment if there's a federal payment for the carbon-free attributes of the plants. We have always maintained that whether it's nuclear or wind or solar, that reducing the nation's carbon emissions should be governed by a nationwide program. We are actively pursuing these federal remedies. Yes, they would be, as I just said a moment ago, offset the ZEC. I don't know that I fully understand your question about the cost structure that's on top of the plants. Dan, did you- Let me rephrase that, if you don't mind, team. Thank you, Ralph. Just as you think about the legacy SG&A, sort of the corporate costs, as you think about divesting these other packages here, can you just elaborate as to how you think about sort of what the run rate is of that business without asking what the actual profitability of the nuclear plants are? How do you think about the cost structure there then, just as we look to refine ourselves in kind of a 2022 going forward basis? Yeah. No, we have set a goal for ourselves that there would be no stranded costs that would remain upon a divestiture of assets. The philosophy we've adopted is that we want to be extremely ambitious in eliminating positions, but extremely accommodating in helping people get reassigned, to the extent that their skills match needs in the company, right? I mean, we turn over 7% of our employee population every year. We're always looking for talent. The one exception to that, of course, is that to the extent that we have people like myself whose compensation was spread over a bigger asset base, that's going to be something that we will have to make up in a different way. We obviously have certain positions like that will be the case. No, we are quite focused and intent upon not having any residual stranded support or overhead costs remaining after the SAM. Yeah. Be them direct or indirect, as Ralph pointed out. Right. Excellent, team. Just clarifying, there's no further clues you can offer us on the sale price for the portfolio today outside of not taking a write-down, I presume. Yeah. It's a bracket for you. It's a big bracket. It was between $500 million and $600 million. The value accretion is based upon an average of the next three years of what we thought the EBITDA would be. The earnings accretion is if we use the proceeds simply to retire debt. We're not making any heroic assumptions. As I said in my remarks, it was a robust process. We had credible participants. The prices we received were quite credible, and we think it worked quite well. You're tired of hearing me say this, so far, the only surprise I've had since July is that there have been no surprises. I hope I can continue to say that, I'm sure I will. Indeed. Well, congratulations again on the progress. Speak to you soon. Thank you. Our next question comes on the line of Jeremy Tonet with J.P. Morgan. Hi, good morning. Morning, Jeremy. Just wanted to take a step a bit higher level here with Biden plan. Granted, it's very early here, things can change, but just wondering what you're looking for here, and how could it impact PEG, as far as what it could mean for offshore wind, transmission development, or even kind of different things such as nuclear with green hydrogen in the future. Just any type of thoughts that you could share as far as what possibilities or what you're looking for here? Sure, Jeremy. We were one of a very small group of companies, candidly, in our industry, who wrote to the President in support of his 80% reduction by 2030 for the electric sector. We're working with members of Congress on making sure that nuclear is included in any clean energy standard in a technology-neutral way. Candidly, we have been talking to folks about the possibility that if tax credits are extended for carbon-free energy, that nuclear would be eligible for that as well. That to the extent an incentive system is set up to achieve these targets, that they not be technology-specific, but that they'd be, I'll repeat myself here, technology indifferent as long as you're achieving the desired outcome, which is carbon reductions. We know that there's a lot of wisdom to the all-of-the-above approach, including nuclear, solar, wind, carbon capture, and storage. We're pleased to see what the President has said about prospects for offshore wind. New Jersey's in the middle of a second-round solicitation looking for another 2.4 GW. Maryland is seeking an additional few hundred megawatts. I do think the momentum is real, and the combination of enthusiasm coming out of Washington and enthusiasm on the part of governors in the region in which we operate leads me to believe that there is going to be a lot of opportunity to invest both in the transmission infrastructure needed to access carbon-free resources and the continued development of carbon-free resources, as well as the preservation of existing carbon-free resources. Don't forget, I know you know this, but nationwide, the existing nuclear fleet is responsible for just over 50% of the carbon-free energy in the nation, even though it only supplies 20% of the total electricity. In New Jersey, those numbers are even more pronounced. Our nuclear plants are over 90% of the carbon-free energy in the state. You've got this really nice confluence of political leadership in the capital and in the states all rowing the boat in the same direction. Got it. That's very helpful. Thanks. Granted, as you said, federal support could supersede what happens at the state level. It's great to see you just got the three-year extensions there. Just wondering, as you look down the road here, do you see the potential for changes to the ZEC program in New Jersey, be it higher levels, longer duration, or just trying to get a feeling for what you think might be possible there? We've been quite consistent saying that we see a multi-phase process to secure the long-term viability of our nuclear plants, and getting round two of ZECs was the successful culmination of phase one. In phase two, there are three pathways we're going to explore. One is a federal pathway, be that a clean energy standard or a production tax credit. We talked about that just a moment ago. We're going to work hard to pursue that because it is global climate change, not New Jersey climate change. Second path is to be an honest broker and advisor to the state in its pursuit of an FRR. That, as I said in my remarks, is in process, and we're expecting to see a summary, a report from the state's consultant sometime this month. That's just a little bit behind schedule, but not by much, and the state has some time to do that thoughtfully and well. In the unlikely event that all of that doesn't achieve the long-term economic viability of the nuclear plants, then we would talk to state policymakers about modifying the ZEC program to do that. It is pretty clear that a three-year process is untenable in such a capital-intensive asset. As we said throughout the ZEC proceeding, the $10 per megawatt hour was not commensurate with the cost of capital associated on a risk-adjusted basis for not bringing those plants. Given the opportunity to pursue these three other remedy paths, that we would accept the $10 per megawatt hour. I do think that there's a fair amount of opportunity to change the economic support for the nuclear plants. Great. That's helpful. I'll leave it there. Thanks. Next question comes on the line of Shar Pourreza with Guggenheim Partners. Hey, guys. Good morning. Hey, Shar. Couple questions here. First, just curious how you're thinking about maybe capital allocation from the fossil sale, pending sale, and especially as you guys are getting over the finish line. I mean, kind of with the de-risking nature of the transaction, do you sort of need the cash proceeds for further de-levering, or do you anticipate the transaction to be credit accretive? Then maybe as a sub-point, how efficiently do you think you could redeploy proceeds on the organic side? We've seen some pretty healthy transactions on the asset side with PE. Curious there. Yeah, it's a great question, Shar. We've said throughout the year and even before, if you take a look at the capital program that we have in front of us for 2021 to 2025, that we could fund that without the need for incremental equity. Take that as it is and start to think about the sale of the business and proceeds coming in. There's going to be excess proceeds. Your question is the right one: what do you think about for use of proceeds? There's debt at the power level. If you think about working your way through kind of some of the terms of that debt, you'll see that some of the conditions therein are reliant upon some of the assets that are being sold. I think pay down of debt at the Power level is an obvious first use of proceeds. We would anticipate excess proceeds beyond that, at which point you start to take a look at how we have described the business. How we've described the business is continuing to grow the utility. It has a fairly voracious appetite. The existing capital plan can be done without additional equity. As we step through time, as we've always said, if you take a look at the five-year capital plan, there are additional things that end up coming to bear during those four- or five-year periods and then towards the back end of that plan that are not known at the beginning. There certainly ends up being opportunity at the utility. We've had a lot of discussion about offshore wind. We've talked about investing in Ocean Wind. We do not intend to do Ocean Wind as a one-off project. We would either be in the business or not. Opportunities will come there, and they tend to be lumpy when they come based upon the various solicitations. I think there's another opportunity to deploy capital there. There is always the opportunity to return some capital to shareholders. To your point, we have said very often that to the extent that we look at some of the transactions that are going on and people are paying more than one times rate base to get the ability to earn on a $1 of rate base, that's a challenging economic situation for us. We have looked and will continue to look at those opportunities, but to date, they have kind of fallen below the optimal things that we can do with our capital. Got it. Then just a transmission ROE question. How active, Ralph and Dan, are your discussions on returns now that some of the other agenda items have been taken off the BPU plate? This is in light of the headlines from the FERC ALJs on pretty draconian views for ROEs and cap structures, which obviously sends a message to investors. How qualitative do you think the BPU is in regard to target ROEs, both on the transmission and state-level side in light of what we're seeing at the federal side? I think the conversations remain very constructive. The issue, as you correctly pointed out, Shar, has been a combination of how busy the board was given what we wanted to do. That's only part of it. I mean, the board is in the middle of a second-round solicitation on offshore wind for 2.4 GW. They're in the middle of an FRR proceeding, they regulate water companies, other electric and gas companies. COVID does introduce an element of inefficiency in terms of how and when one can meet. There's been no indication in the conversations that anyone is any less motivated to find a common ground than when we started. I realize it's over a year ago that we started. I find it hard to believe it's taken that amount of time, but that's just a function of what I said a moment ago. Again, the motivation for us is to get a fair outcome that removes any uncertainty on the part of our investors, and as well as to provide some level of rate relief for our customers. The motivation for the board staff is to achieve that same rate relief, but to do it now instead of getting immersed into a FERC proceeding that might resolve itself in many years from now. Got it. Terrific. Thank you, Ralph and Dan. Thanks. Appreciate it. Very comprehensive. Thanks, Ralph. The next question comes from the line of Durgesh Chopra with Evercore ISI. Hey, good morning. Thanks for taking my question. Maybe just this clarification on the FERC discussion you were just having. Have you quantified what the 50 basis points elimination does in terms of an earnings impact to you guys? Yeah, I think we did, Durgesh. It's said to be about $0.06 a share on an annual basis. Perfect. Thank you. Just maybe get your thoughts directionally, how you're thinking about the PJM here, the capacity auction here next month. Maybe you can just talk about it directionally. Where do you see prices going? How does that impact your process of selling the fossil assets? Yeah, Durgesh. We have had a long and storied history of not trying to predict in public where things are going. I think we've done a decent job internally of having our own views, but ultimately, as a participant there, don't tend to share too many. The only thing I would say is that if you take a look overall at the parameters that have been put forth for this auction, there is more of a bearish tilt than a bullish tilt if I think back compared to some prior auctions. We'll get the results June 2nd and see where things go. On balance, just as a comparison to prior auctions, we see a little bit more bearish than bullish signals coming out of this one, just from the inputs that we've gotten so far. No, that's super helpful. Is that just any color on sort of your discussions with active parties interested in those assets? What are you seeing there? I think it'll play a little bit of a role. If I tend to think about the assets that we're selling to guests, they're very efficient, great capacity factors, they're getting significant spark spreads that ultimately drive their value. Capacity has some of the value, obviously, but given how much they run, I think the energy margins are going to be critical to that determination. This auction is going to be one year. What folks will see after that, they can draw some conclusions from a year, but as I just talked about, you think about historical auctions compared to the current auction, you're going to have differences in the parameters as you step through time. I think that the capacity auctions of the past have not been a wonderful forebearer of what could happen in future auctions. Obviously, each participant's going to take a look at that and see what they're going to do with it from a bid perspective. It's not as big of an impact to look at at a historical capacity auction as some other things. Understood. Appreciate the color. Thank you. Next question comes on the line of Steve Fleishman with Wolfe Research. Hey, good morning. Thanks. Hi, Steve. I think most of my questions were answered. Just on the fossil sale just discussed. Based on the initial bids you've had and different scenarios for the auction, how confident are you that you will complete a sale out of this and get somewhere in the range you were expecting? Steve, I think we have had a robust process. I think that we've had a lot of interest. I think the assets themselves deserve and have drawn a lot of interest. I guess I'd echo what Ralph said a couple of minutes ago. If we think about that things have gone as expected, I think that's a relative positive for continued progress here, and we would anticipate coming to a good conclusion. Okay. Then on the offshore wind, both the commitment you've made so far and potential future ones. When will we get a little more kind of insight into the investment you're going to make and timing of that? Yeah. That happens in increments, Steve. Good news out of BOEM that the environmental impact statement will be done, and I think that's a 2022 event. We've talked about making some capital decisions in the second half of this year, what's called our pre-FID decision. As I say to the national government, FID stands for financial investment decision, right? Then I think there's another major decision one year later than that. It's multiple steps in the process. We're pleased with how things are going right now. There's some tax law changes that are being bandied about that need to be sorted through in terms of our original premise of being a tax equity partner. I think right now, to be honest with you, that team is more focused on execution and there's a little bit more attention being paid to the ongoing solicitations to create even further opportunities. Yeah. See, the dynamic environment that we've had from a credit perspective in Washington does tend to shift things around and, as Ralph said, with the tax equity and the Ocean Wind project. It remains a little bit in flux exactly what it will look like because the tax equity is going to be influenced by the ultimate tax rules where they sit. We've had some changes over time with respect to, I guess, last December, you saw a shift between the equalization, if you will, between PTC and ITC. With all of the, I guess I'd say proposals as opposed to proposed legislation, because it's not at that stage yet with respect to where some of these credits may go. It's got to turn into actual legislation before we know a final answer there. Those will tend to influence, ultimately, some of the cash flows in the initial years too. Okay. This question kind of got asked, but I'll just ask it a little differently. Given the FERC NOPR that came out, just how is that, if at all, impacting your ability to settle the New Jersey transmission ROE? Is that tying into it at all or are you feeling okay? It's, of course, part of the background environment in which we're talking. Okay. It's sort of ironic. Six months ago, when we were having this conversation, I think you would've phrased that. The other way. Framing the conversation. Of course, our colleagues at the regulatory team were saying, "All right, we need another 50 basis points. We need to have it lower." Our response was, "Well, that's not guaranteed." It turned out we were right. Now we're tempted to say, well, with the RTO being taken away, then our settlement number needs to be higher. I guess what they're saying, well, there's no guarantee that's going to happen. It's part of the background. The negotiation has always been around the base ROE, and both sides realize that any RTO incentive adder was separate and apart from that conversation. Okay. Thank you. Next question comes from the line of Paul Patterson with Glenrock Associates. Hey, good morning. Morning, Paul. Just quickly on the market seller offer cap. As you're aware, there was a filing by P3 sort of seeming somewhat concerned about whether or not there was going to be a safe harbor that they perceive to be, whether that was going to be continuing for this upcoming auction. I was wondering, I didn't see really anybody other than them raise this issue, and obviously counter filings and what have you. Any sense as to whether or not that's a significant issue or could impact you guys in any significant way? Not to my knowledge, Paul. Dan and I are looking at each other right now saying we haven't rang any alarm bells over that at all. Okay, great. Then just with the MOPR and the FRR, given where the MOPR is and these things that are happening at PJM plus what we're having at FERC, what are the chances that there will be any significant action until the MOPR issue is resolved with respect to the FRR? I think what the state will do is continue to make progress on what an FRR should look like. If the MOPR doesn't resolve the duplicative payment, I don't want to conjecture whether the state would proceed with the FRR if the duplication in the capacity payment were eliminated. The state might choose to continue anyway just to assert its independence and to not have to worry about a future FERC going back in the other direction, right? Because New Jersey's clearly in this for the long haul in terms of securing carbon-free energy. We've had some sizable changes in direction at FERC, whether it's the MOPR, whether it's the RTO adder. I could see the state just saying, "Okay, I can't wait that way. Let me chart my own course." Having said that, they might equally say, "Well, I don't need to chart that course for a little while because the offshore wind that's coming into play in the 2024 energy year will no longer have this penalty imposed upon it. Okay. It does give the state some optionality if the MOPR is fixed. Okay, great. Thank you. If resolved quick enough, perhaps gets done before anything gets finalized on the FRR. That would, I think, be the ideal situation that the State would have all the information to be able to finalize against. That makes sense. Thank you. Your next question comes to the line of David Arcaro with Morgan Stanley. Oh, hi. Thanks so much for taking my question. How do you think about your chances in the offshore transmission solicitation and the eventual scale of that opportunity? Yeah. One of the landing points is a switching station of ours, and that doesn't give us a hard and fast advantage except we know the area, we know the right of ways, we know the transmission flows. We understand how to engineer multiple solutions to bring that power on land without creating any other reliability issues. Have we given a scale of the magnitude of the opportunity? I don't think we have, right? Because it's an RFP, so if we start throwing numbers out there, then we give our competitors a fair amount of information about what we think we'll be bidding. It is a consequential number. It's something that would be a sizable project and a good use of capital. Okay, great. Yeah, thanks. That's helpful. I guess I was just curious with Ørsted's recent cable issues that they ran into, just wondering if that's something that needs reevaluation or changes economics in any way for the Ocean Wind project. I don't want to pretend to be an expert on that. I think the economic impact is more on having to go back and fix as opposed to designing in advance to avoid. That would be a better question to ask of the folks at Ørsted. We will, of course, see all of that included in the project financial analysis during the pre-FID stage. I don't have a more specific answer for you than that. I know what's been in the public domain has been existing projects that need some mitigation. Okay, got it. Thanks so much. Our next question comes from the line of Michael Lapides with Goldman Sachs. Hey, guys. Thanks for taking my question. Real quick, first of all, offshore wind, are you thinking that your interest is primarily owning or co-owning or owning stakes in projects that primarily serve New Jersey? Or are you looking to be more broad, more diverse across the Eastern Seaboard and with more venture partners besides just the one you're doing on Ocean Wind? Yeah. We would accept broader opportunities. As you probably know, Michael, our Garden State Offshore Energy site that we co-own with Ørsted has ready access to Maryland, and it's actually being used for something called the Skipjack Project, which serves Maryland. It could also reach into Delaware, should Delaware choose to pursue offshore wind, and it can reach New Jersey. It's at the southern tip of New Jersey. That has a three-state reach. Our arrangement with Ørsted is in a certain part of the Mid-Atlantic region, so we're free to work with others outside this region. As you're well aware, most of the participants in offshore wind are seeking partnerships, if at all, with local utilities for a variety of regulatory and transmission planning reasons. While we would be open to it, I think that it's safe to conclude that our primary focus and emphasis is with this partner in this Mid-Atlantic region. Got it. Michael, it's a pretty opportunity-rich area as well. We have said that we wouldn't expect to be going to the Philippines to be doing any projects there. If you think about what is closer to home, it is a pretty opportunity-rich area. Got it. Just one last one. On Ocean Wind or on other New Jersey ones, can you remind me, once the PPA is signed, who warehouses construction cost risk? Is that the project developers? Is it the customer? How does that work? No, that's the project developer, right? The PPA or the board order has an energy price and then an escalator for 20-25 years, I forget. Anything that's increased, any costs or issues that were not anticipated or planned for, are at the risk of the developer. Got it. Thank you, Ralph. Much appreciated. Your final question comes on the line of Jonathan Arnold for Vertical Research Partners. Yeah. Good morning, guys. Just a quick one. On the offshore again, can you remind us, Ralph, if you have any involvement with Ocean Wind 2 at this stage or if there's an opportunity to have one? Jonathan, you broke up. There's a chance that Dan heard you better than I did, or maybe you just need to repeat that. Here, repeat the question, Jonathan. No, my question was whether you have, just if you could remind us what your involvement or potential involvement with Ocean Wind 2 might be, the project that was bid in to the current solicitation. Yeah. Basically, that's Ørsted's project, and if they want to partner with someone, we have the right of first refusal in doing that. Great. Thank you for that. Just one cleanup issue on the Power and the balance sheet. Dan, I heard you mention your comments about use of proceeds. Is there an amount of debt that you've indicated you would continue to carry on Power? Just trying to sort of gauge how we should think about some of these items that are coming up and what the go-forward balance sheet might look like. Yeah. There's not a number that we put out, Jonathan. I think the way to think about it is that there's cash flows that come off of power, and certainly those cash flows are financeable to the extent that there's, for instance, a longer-term solution for nuclear, then you've got a longer-term understanding as to what that could be, and it could carry an incremental amount of debt for a longer period of time, depending upon where all that lands. Separate and apart, necessarily of power, but the offshore wind proposal, as Ralph talked about, it escalates for 20 years, and that price is fixed. Yes, the construction risk is on the developer, but what you see from a revenue stream standpoint is not market-oriented. You get paid the OREC, and then you provide back the market revenues that would come from that. There's some stability there as well. Haven't put a number on that, but there is a financeable cash flow stream in both of those instances. Your comments before were not sort of pointing to a kind of a debt-free power then? Right. Not necessarily. Certainly, it would probably not be the same issuances that would be there, but it could carry some debt on the other side of that. Okay. Just maybe similar vein, any plans to term out the power maturity that's coming up in November, or is that one you're just going to retire? It'll be based upon everything else that happens between now and then, which includes the status of what's going on from a sales perspective. Okay, great. Thank you, guys. Thanks, John. I think we're going to wrap up at this point. Thank you all for joining us. I know we've been on the phone for about an hour, but the message I hope you heard is a fairly simple one, and that is that we're executing on our plan and doing the things that we said we would do to reinforce and create a primarily ESG-leading utility. Thank you again for spending time with us, and I hope to see you all soon in person. Have a great day, folks. Thank you. Ladies and gentlemen, that does conclude your conference call for today. You may disconnect, and thank you for participating.