Public Service Enterprise Group Inc Q2 FY2021 Earnings Call

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.

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 de-risking 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 non-nuclear 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, 2013, eight 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 two 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, averaged well above $200 per megawatt hour over the past decade. Combined with net metering subsidies and federal tax credits provided, later incentives topped $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 BPU 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, one that will 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 meet New Jersey's 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 for an offshore transmission system. Proposals may address any or all of these four 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 BPU will be the ultimate decision-maker. We support the state's efforts to procure transmission in a manner that is most reliable, constructible, and cost-effective for our customers. All of this is excellent 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 being economically at risk but vitally important to New Jersey's ability to reach its clean energy and carbon goals gained 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 referred to 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 three 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 the premature closing of merchant plants whose market revenues are not currently covering costs and risks. 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. 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 LGBTQ+ 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 six 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 five-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 force behind the transmission buildout over the past 10 years, and I hope all of you will have the opportunity to meet her 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. Whether in person or virtually, we are looking forward to hosting 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.

Thank you, Ralph, and good morning, everyone. As Ralph mentioned, PSEG reported non-GAAP operating earnings for the second quarter of 2021 at $0.70 per share, compared to $0.79 per share for the same quarter last year. We have provided information on the contributions to non-GAAP operating earnings by business in the quarter and year-to-date periods on Slides 13 and 15. Slides 14 and 16 contain waterfall charts illustrating the net changes in non-GAAP operating earnings by major business. I will 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, up from a net income of $283 million, or $0.56 per share, for the same quarter in 2020. The results for PSE&G's second quarter reflect revenue growth due to ongoing capital investment programs. Growth in transmission contributed $0.01 per share to second-quarter net income, fueled by ongoing infrastructure investment and the timing of transmission operating and maintenance expenses, along with corrections from previous year filings. Electric margin added $0.02 per share to net income compared to the same quarter last year, driven by increased demand from commercial and industrial sectors, alongside higher margins in April and May as opposed to the COVID-19 restrictions that impacted the previous year's results; along with the implementation of the Conservation Incentive Program in June. Gas margin also added $0.01 per share due to the Gas System Modernization Program's rate rollings. Gas-related bad debt and operating maintenance expenses were both favorable by $0.01 per share compared to the same period last year, following the timing of COVID-related deferrals since the New Jersey Board of Public Utilities' order issued in the third quarter of last year. An increase in distribution-related depreciation from a higher rate base reduced net income by $0.01 per share. Non-operating pension expense was favorable by $0.02 per share compared to the second quarter of 2020, reflecting strong asset returns from last year. Tax expense was unfavorable by $0.02 per share from the prior year, attributed to the timing of adjustments to align with PSE&G's estimated annual effective tax rate. The transmission agreement involving PSE&G, the BPU, and Rate Counsel, mentioned earlier by Ralph, has been submitted to FERC for approval, with an effective date requested for August 1. While we do not have a timeline for FERC's response, we will start recognizing the effects of the settlement on our financials starting August 1. This agreement would adjust the base return on equity for PSE&G's formula rate from 11.18% to 9.9%, which will lower the annual transmission revenue requirement by around $100 million on a pretax basis. Additionally, key components of the settlement will reduce annual depreciation expense by about $42 million, resulting in a corresponding reduction in revenue with no net impact on earnings, and improve cost recovery methods for administrative and general expenses and investments in materials and supplies. The agreement also proposes to increase PSE&G's equity ratio from 54% to 55% of total capitalization. The financial implications of the settlement are projected to reduce PSE&G's net income by about $50 million to $60 million, or $0.10 to $0.12 per share annually in the first 12 months following implementation. Weather conditions during the second quarter were substantially warmer than in the same quarter of 2020, with the temperature humidity index 34% higher than average and an unusually high number of hours above 90 degrees. The New Jersey economy continued to recover in the second quarter, boosting weather-normalized electric sales by roughly 4% compared to the same period in 2020, which was marked by COVID-19 economic restrictions. For the trailing 12 months, weather-normalized electric and gas sales rose by about 1%, with residential electric consumption increasing by 4% and gas usage by 2%. The Conservation Incentive Program, which commenced on June 1 for electric sales, eliminates the inconsistencies in weather, economic activity, efficiency, and customer use affecting our financial results, establishing a margin baseline. This new mechanism enables PSE&G to enhance customer engagement in energy efficiency programs without the risk of losing margins due to lower sales. A similar initiative for gas sales will initiate on October 1, replacing the weather normalization clause. PSE&G’s capital program is on track, with investments of approximately $700 million in the second quarter and $1.3 billion year-to-date through June. This capital is part of PSEG's $2.7 billion Electric and Gas Infrastructure Program for 2021, aimed at improving transmission and distribution facilities to enhance reliability and resilience. We anticipate over 90% of PSEG's planned capital investment will go to the utility within the 2021 to 2025 timeframe. PSE&G's updated forecast for net income in 2021 is $1.42 billion to $1.47 billion, revised from the prior estimate of $1.41 billion to $1.47 billion. Now turning 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. In comparison, the second quarter of 2020 saw non-GAAP operating earnings of $0.24 per share and non-GAAP adjusted EBITDA of $258 million. The non-GAAP adjusted EBITDA excludes specific items similar to those in our non-GAAP operating earnings measure, in addition to income tax expense, interest expense, and depreciation and amortization. The earnings release and Slide 23 present a detailed breakdown of how various factors impacted PSEG Power's non-GAAP operating earnings versus net income quarter-over-quarter. We also offered additional insights into generation for the quarter and first half of 2021 on Slide 24. PSEG Power's second-quarter non-GAAP operating earnings were impacted by several factors that collectively resulted in a decline of $0.14 per share compared to the previous year. Recontracting and market effects lowered results by $0.09 per share due to the seasonal hedging activity and higher service costs relative to last year's second quarter. Generating volume and zero-emission certificates each decreased by $0.01 per share, linked to reduced nuclear output resulting from the planned spring refueling outage at the Hope Creek Nuclear Plant. PJM capacity revenue improved results by $0.02 per share in a year-over-year comparison. For the year-to-date ending June 30, capacity was favorable by $0.05 per share compared to the first half of 2020, reflecting a higher scheduled price of around $167 per megawatt day for most of the first half of 2021 relative to $116 per megawatt day for the same period in 2020. Increased operating and maintenance expenses reduced earnings by $0.04 per share in comparison to last year’s second quarter, mainly due to the planned refueling outage at Hope Creek and higher fossil operating costs. Conversely, lower depreciation expense stemming from the sale of the solar source portfolio and the early retirement of the Bridgeport Harbor coal plant, combined with reduced interest expense, contributed an additional $0.02 per share compared to last year's second quarter. Taxes and various other factors were unfavorable by $0.03 per share due to the absence of a multiyear tax audit settlement included in last year's results for the same quarter. Gross margin in the second quarter of 2020 was $28 per megawatt hour compared to $33 per megawatt hour in last year's second quarter. This decrease reflects the seasonal price impact of recontracting, which is anticipated to result in a negative $2 per megawatt hour price decline in the hedge portfolio for the full year. We expect the recontracting results in the third quarter of 2021 to be similarly negative, and as noted in the last quarter, it will more than offset the $0.03 per share benefit realized in the first quarter of this year. Now let’s discuss Power's operations. Total generation output declined by 1% to 12.6 terawatt hours in the second quarter due to the refueling outage at Hope Creek and subsequent forced outage, which lowered nuclear output compared to the second quarter of 2020. The nuclear fleet achieved an average capacity factor of 86% during the quarter, generating 7.2 terawatt hours, a 7% decrease from last year, representing 57% of total generation. Power's combined cycle fleet produced 5.3 terawatt hours, an increase of 8% due to heightened market demand fueled by warmer weather. Power is anticipating generation output of 25 to 27 terawatt hours for the remaining two quarters of 2021 and has hedged 95% to 100% of its production at an average price of $30 per megawatt hour. Additionally, we are pleased to note that PSEG Power has completely eliminated coal from its generation mix following the early retirement of Bridgeport Harbor Station 3. Power's quarterly impairment assessments, including a strategic review of the non-nuclear fleet, indicated that the ISO New England asset grouping experienced impairment as of June 30, 2021. Consequently, Power logged a pretax charge of $519 million for this asset group. The asset groupings within PJM and New York ISO did not exhibit impairment as of June 30, 2021. However, moving these assets to held-for-sale status, anticipated upon reaching a sale agreement, is expected to lead to additional significant impairment of the fossil portfolio. Transitioning to held-for-sale status would also suspend depreciation and amortization expense for those units, yielding a favorable effect on GAAP and non-GAAP operating earnings until the transaction concludes. In June 2021, PSEG completed the sale of PSEG's Solar Source, resulting in a pretax gain of approximately $62 million and an income tax expense close to $63 million, mainly due to the recapture of investment tax credits tied to units in operation for less than five years. For the rest of the year, depreciation expense is predicted to decline by about $0.03 per share due to the Solar Source sale. The forecast for PSEG Power's non-GAAP operating earnings for 2021 has been revised to a range of $295 million to $370 million, updating from a prior estimate of $280 million to $370 million, while our projected non-GAAP adjusted EBITDA remains unchanged at $850 million to $950 million. Now, let me briefly summarize the operating results from Enterprise and Other, and provide an update on PSEG Long Island. In the second quarter of 2021, PSEG Enterprise and Other reported a net loss of $3 million, or $0.01 per share, consistent with a net loss of $2 million, or $0.01 per share, in the second quarter of 2020. This net loss reflects higher interest expenses at the parent company, partially offset by ongoing contributions from PSEG Long Island. In June, PSEG Long Island entered into a non-binding term sheet with the Long Island Power Authority to address all of the authority's claims related to Tropical Storm Isaias. The terms will be integrated into amendments to our operation service agreement and submitted for approval to New York state authorities later this year. The operation service agreement will continue through 2025, with an option for mutual extension. For 2021, the forecast for PSEG Enterprise and Other remains unchanged at a net loss of $15 million. PSEG's financial situation continues to be strong. By June 30, we had approximately $4 billion of available liquidity, including around $107 million in cash, with debt constituting 52% of our total capital. In the first half of 2021, PSEG entered into two 364-day variable rate term loan agreements totaling $1.25 billion. During the second quarter, PSEG Power repaid $950 million in senior notes due in June and September 2021, and ended June with debt as a percentage of capital at 20%. In May, Moody's revised PSE&G's credit rating outlook to negative from stable, while the first mortgage bond rating remains at Aa3. We still anticipate funding PSEG's $14 billion to $16 billion capital investment program from 2021 to 2025 without the necessity of issuing new equity, while also continuing to provide consistent and sustainable growth in our dividend payments. As Ralph noted, we've raised the lower end of our forecast for non-GAAP operating earnings for the entire year to $3.40 to $3.55 per share, an increase of $0.05 per share based on the robust results from the first half of the year, instilling confidence that we can achieve results at the upper end of our initial guidance. That concludes my remarks. Carol, we're now ready to take 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. 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-à-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 inform how the state goes about the review. Just wondering if you could update us there on that.

Yes. So Jeremy, it's Ralph. We're excited about playing in all four parts of the offshore transmission opportunity. 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 at 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 hand their results over to the BPU for an early decision probably end of the 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. 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 three units economically viable. But I don't see that connected to Offshore Wind in any way.

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 of drag to be perpetual? Or are there offsets like CapEx going 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 can you just give us some thoughts on how you see sort of the business trajectory post the power sale? Just thinking about 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 joint ventures? 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. We hope to meet towards the end of September, which is our current plan. At that time, we expect to provide multiyear earnings guidance and revisit our dividend policy. Currently, we offer 10 months of earnings guidance, and the multiyear guidance may initially span 3 to 5 years, but it will not extend beyond that due to the challenges of making long-term predictions. As we mentioned previously, we believe that post-sale, we will be nearly 90% regulated, although this could decrease somewhat as we add Offshore Wind projects; however, they should be fully contracted. This aligns with our earlier estimates of being in the 80% to 90% range. We are committed to ensuring a longer-term plan for our nuclear plants, as the current 3-year outlook is not feasible. We appreciate that New Jersey is allowing us to enter into more in-depth discussions about extending this timeline at the federal or state level. Our utility growth trajectory has improved, supported by the fact that our aging infrastructure cannot meet the growing needs of our customer base and is increasingly challenged by severe weather conditions and storms. The push to replace this aging infrastructure, particularly with more people working from home, has become more crucial. Additionally, we are now able to align our efforts with New Jersey's carbon-free and green initiatives, enhancing opportunities to grow our customer-side rate base. While replacing transmission towers in terms of earnings power takes a significant number of smaller projects, they remain vital to our customers for energy efficiency and reliability. Overall, the utility growth prospects are still strong, if not better, as we continue to address the challenges posed by climate change and the resulting infrastructure demands while also leveraging new opportunities on the customer side.

Should we consider the 3- to 5-year growth rate in relation to the current utility rate base, and as Offshore Wind becomes more significant, adjust that base upward before calculating growth? Alternatively, will you return to your usual method of guiding based on CapEx and probabilistic scenarios when thinking about that growth rate? The underlying growth rate, relative to the rate base, seems to depend heavily on the visibility of CapEx, correct? Is that the correct way to approach it?

I don't want to provide a long-term growth estimate today. However, we have shared a five-year compound annual growth rate on our rate base growth, which will guide our thinking on long-term earnings growth. This perspective will evolve from the end of last year into the new year. Offshore Wind presents some challenges right now since we only have one confirmed project, Ocean Wind 1. Nevertheless, we have numerous opportunities in discussions. As you mentioned, we will experience some uncertainty regarding the capital program in years four and five, which may introduce some conservatism into the rate base growth. We've managed to compensate for this in the past, and we will take this into consideration. We will provide clearer details regarding our assumptions about ongoing programs during our meeting in September, ensuring that it is evident what has been factored into our earnings growth projections.

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.

I believe there are a couple of factors at play. Firstly, we have solar that has already been sold, which was anticipated in our projections. Currently, we still expect fossil fuels to remain, so that reflects more of a continuation of the current situation. Additionally, it's worth noting that regarding utilities, the SIP program for electricity starts in June and for gas in October. During the summer, gas usage tends to be low, which should reduce some volatility for the remainder of the year. Given the current circumstances and the stabilizing effects of the SIP program, we felt it was appropriate to take the actions we did, and we will monitor developments going forward.

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, it's 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.

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.

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 will more than likely 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 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.

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?

I don't think we should go into details on that, Jonathan. We have various discussions ongoing with Ørsted regarding several projects in the Mid-Atlantic region, and that’s probably as much as I want to share. I want to make sure that Dan's earlier comment is properly addressed. When we say it's not regular, we mean it won't be included in the transmission, and it won't be part of PSE&G, but all transmission is regulated by FERC, so we would still treat it that way. Regarding Ocean Wind 2, it is reasonable to conclude that we will engage in discussions with Ørsted about that, along with other opportunities in the area.

All right. You mentioned that you're hoping to make an announcement regarding fossil at the Analyst Day, which is still targeted for September. However, it seems you suggested that the first quarter of '22 is now mentioned in your official statement regarding when the closing might occur. Can you clarify if there has been any shift in the timeline?

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. 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 the 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 them, 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.

As Ralph mentioned, the initial announcement was made about a year ago. When he refers to 12 months, we are essentially at the event, if not exactly on the day. The FERC process does not have a definite timeline, making the timing a bit uncertain. This gives us an approximate timeframe, I believe.

I was just wondering about the change in language, which seems slight, but that's great. Dan, I have one more quick question about the CIP and its implementation. Does this influence your guidance in any way regarding performance related to weather for the rest of the year? I understand it makes things less volatile going forward, but I'm curious how it affects 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.

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?

The total revenue reduction is $142 million, with a $42 million reduction in depreciation and amortization. Therefore, the adjustment to the EBIT line or operating income line is $100 million. If tax affects that, it suggests a larger impact than the cents per share you initially announced. Can you help me understand the difference?

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 imperfect 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 in 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. The risk component is a function of what are the skill sets that you have or that your partner has.

Got it. Can you remind me that we are currently in an environment where inflation is a hot topic, particularly regarding commodity costs. If the cost to build the Offshore Wind plant exceeds the original expectations, how is that cost distributed 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.

Regarding the asset sale, could you clarify what the book value or asset value of the fossil portfolio is at this time, considering the write-down and other factors?

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

Okay, regarding the transmission build-out, which has been discussed and presents a promising opportunity with Offshore Wind, how would it be structured? It seems competitive. If you were to secure a significant portion of that, would there be an Allowance for Funds Used During Construction associated with it? Or would the earnings impact only be recognized once the project is completed?

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

There is an opportunity to bid on any component, but I wonder how that would operate if someone pursued a comprehensive bid. For instance, would it allow someone to say, 'I want to build a substation'? How could that be modularized? Is it feasible to have a project out there that could be divided into parts? Or would it mostly remain intact? Do you see what I'm getting at?

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 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 four 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 such a low-cost solution on land or out in the ocean that PJM figures out a way to ensure the technical requirements of the project are achieved and then leaves it to the BPU 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. 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.