Ladies and gentlemen, thank you for standing by. My name is Carol, and I'm your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's Second Quarter 2021 Earnings Conference Call and Webcast. . As a reminder, this conference is being recorded today, August 3, 2021, and will be available beginning at 2:00 p.m. Eastern Standard Time today 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, Carol. Good morning, and thank you for participating in our earnings call. PSEG's second quarter 2021 earnings release, attachments and slides detailing operating results by company are posted on our website at investor.pseg.com, and our 10-Q 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 and non-GAAP adjusted EBITDA, which differ from net income or 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 earnings material. I'll now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of PSEG. 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, everyone, for joining us this morning. PSEG reported non-GAAP operating earnings of $0.70 per share for the second quarter of 2021 versus $0.79 per share in last year's second quarter. GAAP results for the second quarter were $0.35 per share net loss related to transition charges at PSEG Power, and that compares with $0.89 per share of net income for the second quarter of 2020. Also in the quarter, PSEG Power recorded a pretax impairment of $519 million at its New England Asset Group, partly offset by a pretax gain of $62 million from the sale of the Solar Source portfolio. We continue to make great progress on a number of fronts to position ourselves for the future. We had a strong operating quarter that, once again, produced non-GAAP operating earnings in line with our expectations for the year. Our results for the second quarter bring non-GAAP operating earnings for the first half of 2021 to $1.98 per share. This 9% increase over non-GAAP results of $1.82 per share for the first half of 2020 reflects the growing contribution from our regulated operations and continued derisking at PSEG Power. Slides 13 and 15 summarize the results for the quarter and the first half of the year. It's been a year since we announced our intentions to explore strategic alternatives for our nonnuclear generation assets, and I'm pleased with the progress to date in what I believe is a compelling platform for future regulated growth at PSE&G. Our utility, a clean energy infrastructure-focused business, will be complemented by a significantly contracted, carbon-free generating portfolio, consisting of our nuclear fleet and investments and opportunities in regional Offshore Wind. The marketing of the fossil assets has garnered a significant level of interest from numerous qualified buyers in a competitive process, which is advancing as expected. And we expect to provide you with more information on this process in the very near future. I'm pleased that we've reached a balanced agreement with the New Jersey Board of Public Utilities and the Division of Rate Counsel on PSE&G's transmission rate, which, if approved by FERC, will resolve a significant regulatory uncertainty for us and provide a timely rate reduction for customers. PSE&G has agreed to voluntarily reduce its annual transmission revenue requirement, which includes a reduction in its base return on equity to 9.9% from 11.18%. If approved by the FERC, a typical electric residential customer will save 3% on their monthly bills. New Jersey continues to experience positive economic activity since Governor Murphy lifted the Public Health Emergency Order in June. Our largest customer class in terms of sales, the commercial segment, has shown a rebound in electricity demand. Electric sales overall adjusted for weather were up nearly 4% over the second quarter of 2020, led by an 11% increase in commercial sales, which was partly offset by a 5% decline in residential sales as people gradually returned to work outside the home. The warmer-than-normal summer has also increased PSE&G's average daily peak load for the quarter to 5,480 megawatts compared to last year's second quarter average of 5,100 megawatts and the 5,330 megawatts experienced in the pre-COVID second quarter of 2019. And so far this summer, PSE&G's load has peaked at 10,064 megawatts on June 30, exceeding the 10,000-megawatt mark for the first time since July 19 of the year 2013, 8 years ago. Turning to clean energy developments in New Jersey, the BPU in June awarded a second round of Offshore Wind projects totaling 2,658 megawatts and is now halfway towards the state's goal of procuring 7,500 megawatts of Offshore Wind generation by 2035. The award was split between the 1,510 megawatt Atlantic Shores project and Ørsted's 1,148 megawatt Ocean Wind 2. The OREC price is set in the second round range from about $86 to $84 for the Atlantic Shores and Ocean Wind projects, respectively. And last week, the BPU approved a new solar successor incentive framework that consists of 2 programs: an administratively determined incentive; and a competitive solicitation incentive, which would apply to larger projects defined as 5 megawatts and above. Incentive levels for the administratively determined segment range from $90 per megawatt hour for net metered residential projects to $70 to $100 per megawatt hour for the commercial and community solar segments and up to $120 per megawatt hour for certain public entity projects. You will recall that the prior program consisting of solar renewable energy credits or as we frequently refer to them as SRECs, average well above $200 per megawatt hour over the past decade. And combined with net metering subsidies and federal tax credits provided later incentives topping $300 per megawatt hour. So this successor program is a positive step towards balancing the need for clean energy while recognizing the importance of affordability for our customers. PSEG's existing solar programs are essentially fully subscribed. We'll continue to work with the state MBP on programs that can help meet the solar goals in the Energy Master Plan. PSEG continues to make tangible progress on our own decarbonization and ESG goals. In the second quarter alone, we closed on our 25% equity stake in the 1,100-megawatt Ocean Wind project in New Jersey, that's the Ocean Wind 1 project, obviously. We retired our last coal unit at Bridgeport Harbor in Connecticut, making our generating fleet coal-free and moved up our net-zero vision by 20 years to 2030. But not only do we accelerate the net-zero vision, we also expanded it to include Scope 1 direct greenhouse gas emissions, and Scope 2 indirect greenhouse gas emissions from operations at both PSEG Power and PSE&G. Expanding the net-zero vision to include both the utility and power operations is a significant move forward in our decarbonization efforts, and one that will both inspire and challenge us to do more and do it better. Coming up, PSEG is preparing to bid into a competitive process to build Offshore Wind transmission infrastructure. This solicitation is intended to procure transmission solutions to this important New Jersey 7,500-megawatt Offshore Wind target by 2035. The potential projects can cover onshore upgrades, new onshore transmission connection facilities, new offshore transmission connection facilities and a network to offshore transmission system. Proposals may address any or all of these 4 components. The decision-making criteria is expected to include, among other things: an evaluation of reliability and economic benefits; cost; constructability; environmental benefits; permitting risks; and other "New Jersey benefits". This competitive transmission open window will be jointly conducted by PJM and the New Jersey Board of Public Utilities. PJM will lead the technical analysis of the proposed transmission solutions, and the BP will be the ultimate decision-maker. We support the state's efforts to procure transmission in a manner that is most reliable, constructable and cost effective for our customers. All of this is great progress on our decarbonization efforts and continues to demonstrate our alignment with the state's Clean Energy agenda and our industry leadership on environmental stewardship. New Jersey's recent endorsement of the environmental benefits provided by our New Jersey nuclear plants through the second zero-emission certificates, I'll refer to that as ZEC for the rest of this conversation, extends the $10 per megawatt hour carbon-free attribute recognition through May of 2025. This extension will allow us, along with stakeholders in New Jersey and at the federal level, the time we need to work on a long-term economic solution to keep our merchant nuclear fleet economically viable and preserve its currently unmatched contribution of reliable, carbon-free baseload generation, the most cost-effective clean generation source available. During the ZEC deliberations, a growing recognition of these nuclear units were economically at risk, but vitally important to New Jersey's ability to reach its clean energy and carbon goals gain further traction. The importance of the New Jersey nuclear units to the state's climate goals was also recognized in the BPU Staff's recent resource adequacy report. The report recommends that New Jersey should continue exploring a region-wide or New Jersey-only integrated clean capacity market, with the fixed resource requirement, often, we refer to that as an FRR. We expect that the BPU will be closely watching to see whether FERC accepts PJM's just filed modifications to the minimum offer price rule which appears to better align the PJM capacity market with New Jersey's clean energy goals. The results of the first PJM capacity auction in 3 years, influenced by a COVID-19 pandemic stifled demand curve, served as further evidence of the market risks faced by our nuclear units. This sentiment is shared by Biden administration officials, including DOE Secretary Granholm and White House Domestic Climate Advisor Gina McCarthy, who have both spoken publicly on the importance of nuclear energy as a clean energy resource. We continue to work on promoting a federal nuclear production tax credit proposal where the value of the credit declines as market revenue increases. This is the primary federal policy that would help prevent premature closing of merchant plants whose market revenues are not currently covering cost and risk. Other options, such as the federal nuclear grant program administered by the Department of Energy are also being discussed. However, we and others in the industry share the view that a competitive grant program will not provide timely relief nor the certainty these plants need to remain operational. Nonetheless, we're encouraged by the attention that at-risk nuclear plants are getting in Washington. And we especially appreciate the efforts of New Jersey Congressman Bill Pascrell, who's leading this effort in the House of Representatives, and Senators Cardin, Manchin and Booker in the Senate. That said, we do expect the federal infrastructure effort to take the better part of the rest of the year to unfold. On the social side of ESG during the second quarter, we recognized the Juneteenth holiday by giving employees paid time off to commemorate and celebrate this important day in our nation's history and supported our LBGTQ+ community with numerous events for Pride Month. Also in June, PSEG was named to JUST Capital's Top 100 companies supporting healthy families and communities. Overall, we had a solid quarter and results for the first half of the year have positioned us to update our full year guidance somewhat earlier than has been our practice. We are raising by $0.05 per share at the bottom end of PSEG's non-GAAP operating earnings guidance for full year 2021 to a range of $3.40 to $3.55 per share, based on favorable results of PSE&G and Power through the first 6 months of the year. This update also incorporates an August 1 effective date to implement the transmission rate settlement and the expectation that the fossil assets will contribute to consolidated results through the end of the year. We're on track to achieve the Utilities 2021 planned capital spending of $2.7 billion on schedule and on budget. This spend is part of PSEG's consolidated 5-year, $14 billion to $16 billion capital plan, which we still intend to execute without the need to issue new equity, while also continuing to offer the opportunity for consistent and sustainable growth in our dividend. Before closing, I do want to recognize the contributions of Dave Daly, who will be retiring on January 4, 2022, after 35 years of dedicated service to the company. Kim Hanemann, who had been named PSE&G's Senior Vice President and Chief Operating Officer, was promoted to succeed Dave as President and COO of PSE&G effective June 30. In support of a seamless transition of leadership at PSE&G, Dave is serving as an executive adviser through the end of the year. With her promotion, Kim is the first woman to lead New Jersey's largest electric and gas utility in our 118-year history. Many of you know Kim is the power behind the transmission buildout over the past 10 years, and I hope all of you will have the opportunity to meet here in the near future. Speaking of meeting, New Jersey has among the highest rates of fully vaccinated people in the country, but vaccination rates in the state have recently plateaued. So we're carefully monitoring the impact that highly contagious variants are having on updated health and safety protocols. So whether in person or virtually, we are looking forward to hosting an investor owned -- an investor event in the fall when we expect to share with you the many good things that are happening at PSEG regarding our improved business mix, increased financial flexibility and solid growth opportunities. So now I'll turn the call over to Dan for more details on our operating results and we'll rejoin you at the end of this for your questions.

Great. Thank you, Ralph, and good morning, everybody. As Ralph said, PSEG reported non-GAAP operating earnings for the second quarter of 2021 at $0.70 per share versus $0.79 per share in last year's second quarter. We've provided you with an information on Slides 13 and 15 regarding the contribution to non-GAAP operating earnings by business for the quarter and the year-to-date periods, and Slides 14 and 16 contain corresponding waterfall charts that take you through the net changes in non-GAAP operating earnings by major business. I'll now review each company in more detail starting with PSE&G. PSE&G reported net income of $309 million or $0.61 per share for the second quarter of 2021 compared with net income of $283 million or $0.56 per share for the second quarter of 2020. PSE&G's second quarter results reflect revenue growth from ongoing capital investment programs. Growth in transmission added $0.01 per share to second quarter net income, reflecting continued infrastructure investment as well as the timing of transmission O&M in the quarter and true ups from prior year filings. Electric margin added $0.02 per share to net income compared to the year earlier quarter. driven by commercial and industrial demand, reflecting higher margins in April and May compared to the COVID-19 restrictions that affected prior year results; and the implementation of the Conservation Incentive Program or CIP mechanism in June. Gas margin added $0.01 per share, driven by the Gas System Modernization Program rate rollings. Gas related bad debt expense and O&M expense were both $0.01 per share favorable compared to the year earlier quarter, driven by the timing of COVID-related deferrals since the issuance of the BPU's order in the third quarter of last year. An increase in distribution-related depreciation due to higher rate base lowered net income by $0.01 per share. Nonoperating pension expense was $0.02 per share favorable compared to the second quarter of 2020, reflecting the continued recognition of strong asset returns experienced last year. Tax expense was $0.02 unfavorable compared to the second quarter of 2020, driven by the timing of adjustments to reflect PSE&G's estimated annual effective tax rate. The transmission agreement between PSE&G, the BPU and Rate Counsel that Ralph mentioned earlier has been filed with FERC for approval with an August 1 requested effective date. There's no timetable from when FERC must respond, however, we will begin recording the impacts of the settlement on our financials starting with the August 1 requested effective date. The agreement would reset the base ROE for PSE&G's formula rate to 9.9% from 11.18%, which lowers the annual transmission revenue requirement by about $100 million per year on a pretax basis. Other key elements of the settlement lower annual depreciation expense by approximately $42 million, which has a corresponding reduction in revenue that results in no net impact on earnings and an improved cost recovery methodology for our administrative and general costs and investments in materials and supplies. The agreement also includes an increase of PSE&G's equity ratio from 54% to 55% of total capitalization. The financial impact of the settlement agreement is expected to lower PSE&G's net income by approximately $50 million to $60 million or $0.10 to $0.12 per share on an annual basis in the first 12 months once implemented. Weather for the second quarter was significantly warmer than the second quarter of 2020, with the temperature humidity index that was 34% higher than normal and a significantly higher than normal number of hours at 90 degrees or greater. The New Jersey economy continued to recover in the second quarter, increased by total weather-normalized electric sales by approximately 4% compared to the second quarter of 2020, which was at the height of the COVID-19 economic restrictions. On a trailing 12-month basis, weather-normalized electric and gas sales were each higher by approximately 1%, with residential electric and gas usage up by 4% and 2%, respectively. The Conservation Incentive Program, which started June 1 for electric sales, removes the variations of weather, economic activity, efficiency and customer usage from our financial results, resetting margins to a baseline level. This new mechanism supports PSE&G's ability to maximize customer participation in energy efficiency programs without losing margins from lower sales. A similar program covering gas sales will commence October 1 and replace the weather normalization clause. PSE&G's capital program remains on schedule. PSE&G invested approximately $700 million in the second quarter and $1.3 billion year-to-date through June. This capital was part of 2021's $2.7 billion Electric and Gas Infrastructure Program to upgrade transmission and distribution facilities and enhance reliability and increase resiliency. We continue to forecast over 90% of PSEG's planned capital investment will be directed to the utility over the 2021 to 2025 time frame. PSE&G's forecast of net income in 2021 has been updated to $1.42 billion to $1.47 billion from $1.41 billion to $1.47 billion. Now moving on to Power. PSEG Power reported non-GAAP operating earnings for the second quarter of $0.10 per share and non-GAAP adjusted EBITDA of $159 million. This compares to non-GAAP operating earnings of $0.24 per share and non-GAAP adjusted EBITDA of $258 million for the second quarter of 2020. 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 Slide 23 provide 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. We also provided you with more detail on generation for the quarter and for the first half of 2021 on Slide 24. PSEG Power's second quarter non-GAAP operating earnings were affected by several items that combined lowered results by $0.14 per share below the quarter from a year ago. Recontracting and market impacts reduced results by $0.09 per share, reflecting seasonal shape of hedging activity and higher cost to serve load versus the year ago quarter. Generating volume and zero emission certificates were each down by $0.01 per share, affected by lower nuclear output related to the spring refueling outage at the 100% owned Hope Creek Nuclear Plant. PJM capacity revenue added $0.02 per share to the year ago quarterly comparison. For the year ended June 30 -- for the year-to-date ended June 30, capacity is $0.05 per share favorable compared to the first half of 2020, reflecting the scheduled higher price of approximately $167 per megawatt day for the majority of the first half of 2021 versus the $116 per megawatt day for the same period in 2020. Higher O&M expense reduced results by $0.04 per share compared to last year's second quarter, primarily reflecting the planned Hope Creek refueling outage and higher fossil operating expenses. Lower depreciation expense, reflecting the sale of the solar source portfolio and the early retirement of the Bridgeport Harbor coal-fired generating station, combined with lower interest expense, to add $0.02 per share versus the year ago quarter. Taxes and other items were $0.03 per share unfavorable, reflecting the absence of a multiyear tax audit settlement included in the second quarter 2020 results. Gross margin in the second quarter of 2020 was $28 per megawatt hour compared with $33 per megawatt hour for last year's second quarter. The decline quarter-over-quarter reflects the seasonal price impact of recontracting, that is anticipated to result in a negative $2 per megawatt hour price decline in the hedge portfolio for the full year. We expect recontracting results in the third quarter of 2021 to be similarly negative, as we mentioned last quarter, will more than offset the $0.03 per share benefit seen in the first quarter of this year. Now let's turn to Power's operations. Total generation output declined by 1% to 12.6 terawatt hours in the second quarter as the refueling outage at Hope Creek and subsequent forced out its lower nuclear output versus the second quarter of 2020. The nuclear fleet operated at an average capacity factor of 86% for the quarter, producing 7.2 terawatt hours, down by 7% versus last year, which represented 57% of total generation. Power's combined cycle fleet produced 5.3 terawatt hours of output, up 8% in response to higher market demand helped by warm weather. Power is forecasting generation output of 25 to 27 terawatt hours for the remaining 2 quarters of 2021, and has hedged 95% to 100% of its production at an average price of $30 per megawatt hour. Also during the quarter, we're pleased to remind you that PSEG Power eliminated all coal from its generating mix with the early retirement of Bridgeport Harbor Station 3. Power's quarterly impairment assessments, including consideration of its strategic review of the nonnuclear fleet, determined that the ISO New England asset grouping showed an impairment as of June 30, 2021. As a result, Power recorded a pretax charge of $519 million for this asset group. PJM and New York ISO asset groupings did not show an impairment as of June 30, 2021. However, a move of these assets to held for sale, which would be effective upon an anticipated sale agreement, would be expected to prompt an additional material impairment to the fossil portfolio. Such a move to held for sale would also prop the cessation of depreciation and amortization expense for the held-for-sale units, resulting in a favorable impact to GAAP and non-GAAP operating earnings through the close of the transaction. In June of 2021, PSEG completed the sale of PSEG's Solar Source, which resulted in a pretax gain of approximately $62 million and income tax expense of approximately $63 million, primarily due to the recapture of investment tax credits on units that operated for less than 5 years. For the remainder of the year, depreciation expense will also decline by approximately $0.03 per share as a result of the Solar Source sale. Forecast of PSEG Power's non-GAAP operating earnings for 2021 has been updated to $295 million to $370 million, from $280 million to $370 million, while our estimated non-GAAP adjusted EBITDA remains unchanged at $850 million to $950 million. Now let me briefly address operating results from Enterprise and Other and provide an update on PSEG Long Island. For the second quarter of 2021, PSEG Enterprise and Other reported a net loss of $3 million or $0.01 per share for the second quarter of 2021, which was flat compared to a net loss of $2 million or $0.01 per share for the second quarter of 2020. The net loss for the second quarter of 2021 reflects higher interest expense at the parent initially offset -- partially offset, I should say, by the ongoing contributions from PSEG Long Island. In June, PSEG Long Island entered into a nonbinding term sheet with the Long Island Power Authority, that would resolve all the authorities claims related to Tropical Storm Isaias. The terms will be adopted into amendments to our operation service agreement, or OSA, and submitted to New York state authorities for approval later this year. The OSA contract term will continue through 2025, with a mutual option to extend. For 2021, the forecast for PSEG Enterprise and Other remains unchanged at a net loss of $15 million. PSEG's financial position remains strong. At June 30, we had approximately $4 billion of available liquidity, including cash on hand of about $107 million and debt represented 52% of our consolidated capital. During the first half of 2021, PSEG entered into 2, 364-day variable rate term loan agreements totaling $1.25 billion. During the second quarter, PSEG Power retired $950 million of senior notes maturing in June and September 2021 and ended June with debt as a percentage of capital of 20%. In May, Moody's changed PSE&G's credit rating outlook to negative from stable. Their first mortgage bond rating remains Aa3. We still expect to fund PSEG's $14 billion to $16 billion capital investment program over the 2021 to 2025 period without the need to issue new equity, while also continuing to offer consistent and sustainable growth in our dividend payment. As Ralph mentioned, we've raised the bottom end of our forecast of non-GAAP operating earnings for the full year to $3.40 to $3.55 per share, up by $0.05 per share based on the solid results we have seen in the first half of the year that give us confidence that we can deliver results at the upper end of our original guidance. That concludes my comments. And Carol, we are now ready to answer questions.

. The first question comes from the line of Jeremy Tonet with JPMorgan.

Just wanted to dig into the fossil sales process a little bit more, if I could. And given the impairment here, I just want to make sure I'm clear, the one taken in New England, it would seem that, that process might wrap up more near term than the others. And then at the same time, for the other pieces of the sale, it seems like the process might slip into '22 a little bit, if I saw that right. Just wondering if you could walk through some of the drivers on that.

Sure, Jeremy. With respect to your question on the different asset groupings, when we think about and when we do our impairment tests, we use those asset groupings. And so there's an asset grouping for New England, one for New York and one for PJM. And so I would not look at the timing of the impairment in the second quarter in New England as being different timing for different components. I think what you would look at is the way that the test is done by looking at both the traditional view of an undiscounted set of future cash flows, as well as the potential for a sale that go into that calculation. And basically, that calculation was such that we did as of the end of the second quarter, see an impairment in New England, but did not see one in New York and PJM. As I noted in my remarks that as we continue forward and upon a movement to held for sale, you could see a material impairment incremental to what's there. But it does not have to do with timing per se of the sale. And -- what we have said all along was somewhere around midyear, we would be moving to agreement. We're still in that ballpark, I believe. But I still think year-end is about what you would anticipate the path that we're on. But it does not imply separate sales by virtue of what's happened. It's more just based upon the overall accounting and how that test works vis-a-vis, let's say, the balance on the books.

Got it. That's helpful. And maybe just kind of pivoting towards Offshore Wind here in investment timing in transmission. Just wondering how you think about the opportunity post the settlement here? And then I guess as well, with nuclear, if there's potential federal outcomes here, if that might kind of play into the process in any way at all, and informs how the state goes about the review. Just wondering if you could update us there on that.

Yes. So Jeremy, it's Ralph. So we're excited about playing in all 4 parts of the offshore transmission opportunity. And we do see that as a quite sizable opportunity. This is due, if I'm not mistaken, at the end of this month, but they've been delayed. They were originally due the end of this month, but they were delayed. Now it's sometime in September, probably the end of September. We're expecting PJM to review that through the balance of the year and then handing their results over to the BPU for an early decision probably end of first quarter next year, it could slip a little further than that. But there's a sizable opportunity in Offshore Wind. And it's quite real, just given the fact that we now have over 3,700 megawatts of wind farms that are due to become operational depending upon the project anywhere from 2024 to 2028. Nuclear is wholly separate from that, and we are greatly encouraged by the amount of attention being given to merchant plants, in particular by President Biden and his administration, by bipartisan members of the House and the Senate. There is a component of the infrastructure build that right now allows for a grant program for nuclear. And while that is by no means the preferred path for us, just a mere fact that Congress is recognizing the challenge of nuclear plants, I think, is important for the nation and could relieve some of the cost pressure on New Jersey customers who are currently bearing the full burden of keeping our 3 units economically viable. But I don't see that connected to Offshore Wind in any way.

Your next question comes from the line of Shar Pourreza with Guggenheim Partners.

Can you just elaborate, Ralph, on the impact of the FERC ROE settlement with the BPU? I mean do you anticipate that $0.12 to -- $0.10 to $0.12 of drag to be perpetual? Or are there offsets like CapEx go forwards? Or maybe the ability to raise the equity ratio at the distribution business, O&M levers? How do we think about that?

Yes. So the $0.10 to $0.12 is the all-in effect of some of the improvements in the formula rate treatment. Some of the benefits realized from an earnings point of view of reducing the depreciation rate, but it also includes the most obvious drag of lowering the allowed ROE. Now a couple of things will happen by parts of changing the depreciation rate. The rate base will decline more slowly. So that's an improvement to earnings in the out years. But having said that, however, though, as you grow the rate base from new CapEx, the lower ROE is going to be a drag on earnings. So we won't break it out in the future, Shar, because there's no sense talking about what is no longer our ROE, but it will all be factored into any earnings guidance we give for 2022 and beyond.

Got it. Got it. Got you. Okay. Great. And then just can you just give us some thoughts on how you see sort of the business trajectory post like the power sale? Just thinking of like how do you bridge the 6.5% to 8% utility rate base growth with the remaining moving pieces, like nuclear and the holdings business, Offshore Wind JV. And do you sort of plan to provide longer-term EPS guidance post the sale at the Analyst Day? So how do we sort of think about that?

Yes. So we're hoping to get together late in September. That's still our current thinking. And we do anticipate being able to give multiyear earnings guidance and revisit our dividend policy at that point in time. I think -- right now, we give you 10 months of earnings guidance. So multiyear may start out being 3 to 5 years. I don't think it's going to -- it's certainly not going to be beyond that. It's just so tough to predict, longer term than that, Shar. But really, what we highlighted not that long ago is still in place, we think after the sale, we'll be close to 90% regulated. Now that could drop a little bit as we start adding Offshore Wind, but that we expect to be fully contracted. And so that was the 80% to 90% range that we had given in prior earnings calls, and that's still in place. We are determined to get a longer-term treatment of our nuclear plants. We've said in a matter of fact that the 3 years that is untenable. And we're delighted that New Jersey gave us that to be able to enter into this more thoughtful discussion either at the federal level or if it has to be at the state level to expand that time frame. But the utility growth trajectory has only been enhanced, right? Its growth trajectory has always been supported by the fact that we have an aging infrastructure that can: A, not meet the needs of a customer base that is increasingly dependent on that infrastructure; and B, that infrastructure in addition to its age is confronting more intense weather patterns and storms. So the need to replace that aging infrastructure, inclusive of greater emphasis on the last mile as more and more people work from home, is just equally, if not growing in prominence. And then we have the ability to add to that the carbon-free agenda and the green agenda of New Jersey, which allows this whole opportunity of adding to the rate base on the customer side of the meter. And as I said in the past, it takes a lot of light bulbs to replace the transmission tower in terms of earnings power, but they're equally important to the customer, both from an energy efficiency point of view and a reliability point of view. So I'd say that the utility growth prospects remain intact, if not, are enhanced. But what we continue to see in terms of climate change and the stress it puts on the infrastructure and the desire to battle that and the opportunity it creates on the customer side of the meter.

So should we -- as we're thinking about the 3- to 5-year growth rate, should we think about it as the rate base that you guide currently at the utility level, and when Offshore Wind starts to become more material, you kind of rebase that year higher and then grow off of that? Or as you're thinking about that 3- to 5-year growth rate, are you going to revert back to your traditional, to what you guide, which is looking at your CapEx and probabilistic scenarios, right? And I guess the bookends of that growth rate off of the rate base growth would really be based on, I guess, the CapEx visibility you have, right, that would dictate a lot of on top of that. Is that the way to think about it?

So I don't want to give that long-term growth today. But I think -- when you have to think about, Shar, I mean, we have given a 5-year CAGR on rate base growth. So that will form the template of how we think about our long-term earnings growth so -- the end of last year until we get to the new year. And then it will build off of that. Now Offshore Wind is a little bit more difficult at this point in time, obviously, because we only have one project that's in the bank, so to speak, that's Ocean Wind 1. But we have lots of opportunities that are in the discussion phase. And to your point, yes, we will still suffer from the fact that the capital program is not as well known in years 4 and 5, and that they embed a little bit of potential conservatism in the rate base growth, which we've tended to be able to make up for in the past. And we'll think that through and give you further clarity about what we're assuming in terms of on file programs or continuation of programs when we meet with you in September. But we'll make that abundantly clear in how the earnings growth has been -- what's being assumed in it.

Your next question comes from the line of Julien Dumoulin-Smith with Bank of America. Julien Dumoulin-Smith: So I want to come back to the guidance increase just on '21 here. I just wanted to understand a little bit more of the confidence, and the confidence in raising now with second quarter. I mean, obviously, the ROE impact is known, but you also have a solar and fossil headwind, obviously not fully reflected in expectations here. Just what gave you the confidence to raise it at this point? It's notable.

Julien, I think it's a couple of things. First off, we have solar that has been sold and that was in what we had going forward. And as we sit here today, what we have still assumes that fossil continues on. So that's more status quo than anything else. The other thing that I would -- that I think is probably worth mentioning though, is just the -- if you think about the utility, if you think about on the electric side, that SIP program, which has a leveling effect -- is in effect for electric in June, it's in effect in October for gas. And if you think about going through the summer period, gas usage is low during that period. So that will take some volatility out of the balance of the year from those perspectives. And so just seeing where we are with the events that we know and with the effect of some volatility-reducing aspects of the SIP, I think that it made sense right now to do what we did do and we'll see what happens from here. Julien Dumoulin-Smith: Excellent. And perhaps I can preference that I know the rating agencies are already acting in some respects. But can you elaborate on the increased flexibility, right? I know you used that word very specifically here, as you mentioned the topic at the Analyst Day. What kind of financial metrics are you thinking about with respect to your balance sheet on a prospective basis, perhaps pro forma for your strategic repositioning?

Yes. Look, I think embedded within your question is an acknowledgment that as we step forward, the company will have a more stable business mix on top of the aspect that I just talked about with respect to the SIP having a stabilizing effect. I think Analyst Day is the right time to put that out. But if you think about just that change in business mix is going to put us in a position where we have some more flexibility. So I think for more details on that, stay tuned. But I think the direction of it is obviously favorable given the business mix. Julien Dumoulin-Smith: But just to clarify this, should we still broadly be thinking about use of proceeds? Is it entirely towards debt paydown?

No. I mean what we said is that use of proceeds certainly would go towards Power's debt paydown. You've seen some of that happen already, but also the continued ability to invest in the business, if you think about investment opportunities that Ralph just talked about with respect to PSE&G and certainly within some of the out years as well as Offshore Wind, and the potential for a return of capital to shareholders. So those are the buckets that we've talked about. And probably with respect to the first use, I would think about the Power debt being taken out. Julien Dumoulin-Smith: Got it. Understood. I appreciate it. But so buyback, dividend and CapEx all there?

Yes. You were nodding your head Dan, but they couldn't see that.

Your next question comes from the line of Durgesh Chopra with Evercore ISI.

Dan, just quickly on 2021, can you quantify how much benefit was weather in the second quarter? I'm just trying to reconcile your move up in guidance given, sort of, the ROE headwinds and the combination of other things, including sort of demand recovery, load recovery year-over-year.

Yes. We didn't have a $0.01 provided on weather, but modest. It's kind of in a $0.01 or $0.02 down across the businesses.

Got it. Okay. So small. And then just maybe all my questions have been answered. But Ralph, is there a way to size the transmission investment, like what could be the upside? I mean you have a, what, $16 billion 5-year CapEx plan towards the high end of your range. But what could be a potential upside from all the transmission investment in New Jersey?

Yes. No, I'm glad you asked that question, right? Because what we have been telling folks is that we expect it to be a 9-figure investment opportunity. But I think we've understated it. Looking at the breadth of what New Jersey wants to see happen, we may need to add a 0 to that. That does look like a more of a 10-figure investment opportunity at this point.

Got it. So very large and presumably sort of worth structure.

Yes. It's a lot of infrastructure.

Right. And over sort of a 5, 10 year time line. Is that the right way to think about it? I appreciate all leanings, but...

Yes. No. I think that that's right, because it's supposed to be if New Jersey goes ahead with it, the intent is to be able to manage the 2035 target of 7.5 gigawatts. But it's not necessarily all going to be regulated, right? Some of the on-land stuff probably will be. But the components that are landing sites onshore and the backbone out in the ocean and the pieces that are connected to the ocean more than likely would be unregulated, but supported by a contract or a board order.

And Durgesh, the nature of it, we talked a little bit about it in the prepared remarks. There's a lot of options as to what actually can end up coming forward. And so I think what you're likely to see is a submission that would include multiple alternatives that some may or may not be mutually exclusive depending upon the way that the decision is ultimately made. So you may see kind of a bigger number going forward from the standpoint of all alternatives, which may distill down to a smaller number that we end up getting. Now it all obviously would end up being FERC regulated, but you may not see that embedded within our PSE&G regulated entity.

Your next question comes from the line of Jonathan Arnold with Vertical Research.

Just quickly on Ocean Wind to your potential interest in becoming involved there. Any sense of how soon we might learn about that? Are you already talking about it? Or anything you can share there?

Yes, I don't think we want to get into details on that, Jonathan. I mean we have a range of conversations across several projects that are in the Mid-Atlantic region underway with Ørsted. And I think that's probably as far as I want to go. I do want to make sure that we -- that Dan's comment a second ago is best addressed, right? So when we say it's not regularly what we mean is it's not going to be part of the transmission, it's not going to part of PSE&G, but all transmission is FERC regulated. So we'd still give that kind of treatment. But in terms of Ocean Wind 2, it is obviously safe to conclude that we will have some conversations with Ørsted about that as well as some other opportunities in the region.

All right. And just on -- you said that you're hoping to announce the -- have things to tell us in, I think, the very near future on fossil in the Analyst Day still targeting September. But you did -- it does look like you put first quarter of '22 sort of in the official statement on when we might when closing might happen. So -- can you just close the loop for us there a little bit? Did things shift back a bit, or...

Happy to. Look, so from my perspective, we've been running a 12-month process that's been phenomenally successful. It's been extremely robust. And I just don't want to sacrifice value for an arbitrary deadline. So we think in the near future, we'll be able to give you more detail, and we're still holding out for end of September Analyst Day. But I'm not going to sacrifice value for, as I said, an arbitrary deadline. The Q1 of '22 is just if you look at FERC approval time frames for similar-sized deals, in terms of when things were filed and when FERC finally blessed and you tack it on to where we are at the moment, that it could bleed into next year is what we're saying. It could still happen by the end of this year, but it could also just look at the range of dates leading to next year. Again, I think the process has been incredibly robust, and I don't want to diminish how well it's gone by just forcing an expedited closing of the final stages.

And just as Ralph mentioned, Jonathan, so I mean the initial announcement was this time last year. So when he talks about 12 months, we literally are to the event at least, if not for the exact day at 12 months. And that FERC process does not have a firm time line on it. And so that's -- as we think about timing, it's a little bit of an uncertain target. That's an approximate time frame I believe.

I was just curious because it looks like a slight change in language, but that's great. Dan, I'll just ask one other quick thing on the CIP and implementing that. Does that have -- because I guess that sort of would pull out any over or under performance on weather through the balance of the year. Does it help or hurt you relative to guidance, having the CIP sort of come into effect? I realize it makes it less volatile going forward. But I'm just curious as you sort of pull out the, what you had in the base.

Yes. Honestly, Jonathan, it will depend a little bit upon what the weather and the economic activity is, right? We will be back to a more neutralized outcome. And as you mentioned, embedded within your question, there's more stability to that. But I think it's probably a question better answered as we get to our year-end call than where it is now.

I thought it might be a question of what weather was because that was -- which you'll then as we think about sort of year-to-year comps that will fall away and then it becomes normal, right?

Yes. I mean we would be thinking about it prospectively as being normal. So I don't think there'd be a strong bias one way or the other.

Your next question comes from the line of Michael Lapides with Goldman Sachs.

A couple of questions. First one, just need a little help here. The net revenue change tied to the FERC ROE adjustment is $100 million, if I back out the $42 million. I'm just struggling to get to how it's only $0.10 to $0.12 of an impact. Would think just that $100 million tax effect is a bigger impact than $0.10 to $0.12.

I'm sorry, Michael. Say again?

Well, I'm just -- the total revenue reduction is $142 million, but there's a $42 million reduction in D&A. So kind of down to the EBIT line or operating income line, it's a $100 million adjustment that just -- if that tax affected that, that would imply a bigger impact than the cents per share you've disclosed when you first announced it. Can you just help me bridge the gap there?

Yes. Yes, Michael, if you think about the other things that we kind of talked about within the overall settlement. So the way we've described it to some folks, the probably the easiest thing to think about is just if we spend $1 on G&A, the imperfected timing groove of state and federal regulation might have us receiving $0.49 back from state and $0.49 back from federal. And so there's not full recovery. And so it seemed like the right time, as we were talking through all this, to be able to just make sure that we were able to recover all costs. And so something like that, that would get us back and my example, that $0.02 of that dollar is additive as well. And so it's that kind of thing that went into the overall settlement, which helped a little bit beyond just the headline math of ROE delta times rate base amount. So those kind of things around the edges that were a little bit helpful, that we cleaned up as we went through as well.

Got it. And then, Ralph, just a question for you, and this is thinking multiyears out and really long term. What is a better business from a risk profile and return standpoint? Owning minority stakes in Offshore Winds, the generating facility itself? Or owning and developing and building either contracted or FERC-regulated transmission to serve that wind?

Well, it depends on the skill sets that you contain, right? So for us, it's clearly the transmission component. But we're fortunate to have a partner that's the world leader in operating those Offshore Wind farms. So by virtue of that skill set that we can candidly lean on, we're economically indifferent in that regard. But it's pretty clear we've not been shy about it. In the case of building the wind farms, we're the passenger on the bus, but we have a very good bus driver that we trust. And in the case of the transmission, we're more than happy to be the best driver. But in both cases, we look at risk-adjusted returns. And the risk component is a function of what are the skill sets that you have or that your partner has.

Got it. And can you remind me just the -- we're in an environment right now where a hot topic for conversation is inflation, especially on commodity cost inputs. If the price, or the cost to build the Offshore Wind plant rises above kind of the original expectation, how does that get shared between you and Ørsted?

Well, so the projects are shared according to our equity percentages, right? So you're 25% owner of the project, they're 75% owner of the project. And that's what the benefits or burdens would be going forward.

Your next question comes from the line of Paul Patterson with Glenrock Associates.

So just on the asset sale, could you -- with the write-down and everything, where is the book value or the asset value on the books of the fossil portfolio at this point?

Yes. So we've laid out within our SEC docs, Paul, that fossil asset value is about $4.5 billion.

Okay. And then just on the transmission build-out, which you guys went over and it sounds like a great opportunity with Offshore Wind and everything. But how would it work? I mean, it sounds like it's competitive. Would there be AFUDC if you guys were to win a substantial portion of that? Would that be -- would there be AFUDC that would be associated with the construction of that? Or would it basically be the situation where you get the earnings impact when the project is complete?

No, there is the ability for an AFUDC recovery loan.

There is. Okay. And then -- just finally to sort of -- you mentioned that any component can be bid on. But it would seem to me that -- how would that work, I guess, if there was sort of a comprehensive bid, somebody dig into this scale like you can do a comprehensive bid? Is it really the ability of somebody to say, "Hey, there's a substation or something I want to -- I want to build." How could somebody sort of modularize it, if you follow what I'm saying? Is that really a possibility that you would have a project that would be put out there, but they would say, well, we'll take part of your project and split it up or really would it be pretty much -- do you follow what I'm saying?

I do. I do. And actually, that's been done successfully in the past, Paul. If you think about third quarter 1,000 solicitations replaced called the Artificial Island project. We're basically -- we were given part of the project and someone else was given another part of the project that were considered complementary to each other and mutually reinforcing of the voltage and stability issue that was trying to be resolved. I do think your question points in a direction that I would agree with, that it is probably easier to optimize the whole by putting in all 4 components and a specialist that just wants to do one component may or may not fit as naturally into the other components. But they could have just such a low-cost solution on land or out in the ocean that, that PJM figures out a way to ensure the technical requirements of the project are achieved and then leaves it to the BP units whether or not they want to have bifurcated ownership of what will become an Offshore Wind grid.

Ladies and gentlemen, that is all the time we have for questions. And now I will turn the call back over to management for closing remarks.

Great, thank you. So look, I hope you agree. We've made tremendous progress on multiple fronts, operational, regulatory and legislative. I'm particularly optimistic and encouraged by the amount of federal attention being given to a nuclear production tax credit, and the clearing of the deck, so to speak, of some of our own state issues that are now behind us, both in terms of the ROE settlement and the second round of ZECs. We're going to continue to make progress, I'm sure, on the fossil asset sale, to get us to that fully-regulated or contracted position that we have targeted for the better part of the year. And we're looking forward to speaking with many of you at some of the upcoming virtual conferences over the next several weeks and our Investor Day in the fall. So with that, stay safe, stay healthy, and thank you for joining us, everyone.

Ladies and gentlemen, that does conclude your conference call for today. You may disconnect, and thank you for participating.