公共服務電力與天然氣 (PEG) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Phyllis, and I am your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group Second Quarter 2020 Earnings Conference Call and Webcast. (Operator Instructions)

As a reminder, this conference is being recorded today, July 31, 2020, and will be available for telephone replay beginning at 1:00 p.m. Eastern Time today until 11:30 p.m. Eastern Time on August 11, 2020. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com.

I would now like to turn the conference over to Carlotta Chan. Please go ahead.

Thank you, Phyllis. Good morning, and thank you for participating in our earnings call. PSEG's second quarter 2020 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 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 materials.

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 all for joining us. PSEG reported non-GAAP operating earnings for the second quarter of 2020 of $0.79 per share versus $0.58 per share in last year's second quarter. PSEG's GAAP results for the second quarter were $0.89 per share compared with $0.30 per share in last year's second quarter. Our results for the second quarter bring non-GAAP operating earnings for the first half of 2020 to $1.82 per share. This increase over non-GAAP results of $1.66 per share for the first half of 2019 reflects the growing contribution from our regulated operations, effective cost controls at both the utility and PSEG Power, the absence of 2 extended plant outages that took place in last year's second quarter, and the favorable settlement of audits covering the 2011 through 2016 tax years which, in combination, have mitigated much of the weather-related headwinds experienced in the first quarter of 2020.

Slides 11 and 13 summarize the results for the quarter and the first half of the year. We're especially pleased to report solid operating and financial results at both businesses. Our employees continue to effectively respond to the challenges and requirements of providing essential energy services under extraordinary conditions. The statewide mandated closure of most businesses, schools and government buildings in New Jersey, contributed to a decline of approximately 7% in weather-normalized electric sales for the second quarter. As the state continues the gradual reopening of businesses and activities, effective containment of COVID-19 should expand commercial activity and energy usage in the months ahead. New Jersey has done a very good job of flattening the curve of new COVID-19 cases over the last few months. But we must all remain vigilant as we see signs of potential increase.

Earlier this month, the New Jersey Board of Public Utilities -- I'll just say BPU, authorized utilities in the state to defer prudently incurred incremental costs related to COVID-19 from March 9 of this year through at least September 30, 2021. PSE&G will file its first quarterly report to the BPU on August 3 outlining its COVID-related costs and offsets for the period ended June 30. And we expect to report our deferral in the third quarter.

Our utility field crews are at full force and construction work continues on our infrastructure programs. In May, PSE&G also resumed on-premises customer work using personal protection equipment, PPE, as you -- as we often referred to it, customer contact screening and physical distancing to ensure customer and employee safety. Our associates who are able to work remotely continue to do so, and we are continuing to assess when we will begin a phased return for those employees.

In early June, Southern New Jersey experienced a series of severe straight-line storm systems known as a derecho, with high wind speeds that topped 93 miles per hour and resulted in 127,000 customer outages. The extent of the damage to poles and trees plus the ongoing high winds and required physical distancing restrictions made the storm particularly challenging. PSE&G crews work day and night on outage restoration and were ably assisted by mutual aid from PSEG Long Island to help restore power in New Jersey, and we can't thank them enough.

This ability to draw on local mutual aid from New York is especially critical now given the impact on our work crews of New Jersey's required 14-day COVID-19-related quarantine periods for visitors coming from states with increasing or still high infection rates.

PSE&G continues progress on its portfolio of capital improvements, including several key transmission projects. This quarter, we energized the second phase of our $739 million Metuchen-Trenton-Burlington project and upgraded the transmission circuits between Brunswick Station and Trenton Station. The utility also expects to complete work on a 6-mile upgrade of 230 kV overhead transmission circuits running between Aldene Station and the Linden variable frequency transformer station by year-end 2020, having already completed approximately half of this important project.

On the regulatory front, we're in active discussions with the New Jersey BPU and other parties to settle several items, including the return on equity related to PSE&G'S Federal Energy Regulatory Commission, FERC, formula rate for transmission as well as the pending $2.5 billion 6-year Clean Energy Future energy efficiency filing, which restarted in June following the BPU's adoption of a framework to implement energy efficiency throughout the state. Our proposed program is expected to create 3,700 jobs over 6 years.

The final energy efficiency framework adopted by the BPU in June was an improvement over earlier versions and supports expanded utility investment in energy efficiency by broadening utility participation and program offerings by eliminating the ROE reduction applied to energy efficiency investment, by extending the amortization period to 10 years and delaying any penalties until the fifth year of implementation, while increasing state's energy savings targets to 2.15% and 1.1% for electric and gas, respectively.

In addition, the BPU directed utilities to work with BPU staff and rate counsel to establish a conservation incentive program, or CIP as I'll refer to it, to recover lost revenues or use the lost revenue adjustment mechanism, also known as LRAM, has the default alternative.

As I said a moment ago, PSE&G energy fines have declined due to the COVID-19 restrictions, but peak load for the second quarter remained in a normal seasonal range, averaging 5,100 megawatts versus last year's second quarter average of 5,330 megawatts. PSE&G summer load peaked at 9,753 megawatts in 2019. So far this summer, we experienced a peak load of 9,521 megawatts on July 22, about 2.5% below last year due to COVID-19, but helped by warmer weather. That said, PJM day-ahead round-the-clock power prices have remained in the mid-teens to low $20 per megawatt hour most days during the second quarter.

More recently, New Jersey has experienced several weeks in a row, with temperatures hovering in the mid-80s to mid-90s. Even with this recent heat wave, average day-ahead prices have only crossed the $30 per megawatt hour price point in the PSEG zone twice in the last 30 days. This is a reflection of current market conditions, characterized by reduced loads, sub-$2 per MMBtu natural gas and ample generation.

This market environment is the reality we face at our nuclear stations and as the market is the driver behind zero-emission certificates, or ZECs. Our Salem and Hope Creek nuclear plants produce over 90% of New Jersey zero-carbon electricity. These nuclear units are a cost-efficient and necessary component of the state's transition to 100% clean energy by 2050 as outlined in New Jersey's Energy Master Plan finalized this past January.

As we begin the second round of the ZEC program by filing our applications this fall, it's important to note that the financial need for ZECs is more critical than ever. PJM forward prices have declined from where they were just 2 years ago when forward round-the-clock prices for the PSEG zone were approximately $30 per megawatt hour. Today, they are just over $25 per megawatt hour.

ZEC payments compensate nuclear generation for the zero-carbon attributes that are otherwise unrecognized by the wholesale markets and are an essential component to the economic viability of the New Jersey nuclear fleet. The second ZEC application process is expected to conclude with the BPU decision in mid-April 2021.

On the ESG front, I'm pleased to report that PSEG is gaining broader recognition for our industry-leading position. As many of you know, our carbon intensity is among the lowest of our industry peers, driven by the large percentage of our output from nuclear power plants. And our utility is working hard to reduce emissions through its clean energy filings and infrastructure programs.

In May, our ESG score from MSCI was raised to AA from A, placing us in the top 20% of all companies they evaluate on environmental, social and governance disclosure. And in June, PSE&G was recognized as a trusted brand, ranking first among combined gas and electric utilities by Escalent in the 2020 Cogent Syndicated Utility Trusted Brand & Customer Engagement study.

Turning to earnings guidance. We are reaffirming PSEG's non-GAAP operating earnings guidance for full year 2020 of $3.30 to $3.50 per share. Based on our solid results through the first half of the year and our confidence that we can effectively manage costs across our businesses, continue executing our investment program at PSE&G and provide New Jersey with reliable sources of electricity. We are on track to execute our 5-year $12 billion to $16 billion capital plan without the need to issue new equity and our net liquidity position as of June 30 remains ample at $4 billion.

And finally, as you have all seen by now, this morning, we also announced that PSEG is exploring strategic alternatives for PSEG Power's nonnuclear generating fleet. Our intent is to accelerate the transformation of PSEG into a primarily regulated electric and gas utility, a plan we have been executing successfully for over a decade. PSEG will explore how our potential separation of the nonnuclear assets could reduce overall business risk and earnings volatility, improve our credit profile and enhance an already compelling ESG position driven by pending clean energy investments, methane reduction and zero-carbon generation.

We believe PSE&G is among the best utilities in the country and that our valuation should align with that profile. PSEG intends to retain ownership of PSEG Power's existing nuclear fleet. The nuclear fleet is a necessary component and enabling New Jersey to meet its long-term carbon-reduction goals, and also helps to satisfy the state's capacity obligations for resource adequacy with a cost-effective source of zero-carbon electricity.

Given the relatively small part of PSEG that the nonnuclear business represents, this decision will not have an impact on the company's current shareholder dividend policy, which will continue to be subject to approval by the PSEG Board of Directors. PSEG will manage this process, taking into account the interest of our diverse stakeholders, including our 13,000 valued employees. Any decision regarding the nonnuclear assets will not impact PSE&G or PSEG Long Island customers, their operations or tariffs, but would be subject to customary regulatory approvals. Marketing a potential transaction in one or a series of steps is anticipated to launch in the fourth quarter of this year and is expected to be completed sometime in 2021.

We're excited to explore the opportunities that will shape PSEG's future. It is a future focused on advancing our business as a sustainable, customer-focused provider of essential electricity and natural gas service, delivered by a regulated utility and contracted businesses. I will now turn the call over to Dan for more details on our operating results, and we will both be available for your questions after his remarks.

Terrific. Thank you, Ralph, and good morning, everyone. Ralph said, PSEG reported non-GAAP operating earnings for the second quarter of 2019 of $0.79 per share, and that's versus $0.58 per share in last year's second quarter. We have provided you information on Slide 11 regarding the contribution to non-GAAP operating earnings by business for the quarter.

And on Slide 12, you'll see a waterfall chart that takes you through the net changes quarter-over-quarter in non-GAAP operating earnings by major business. So now I'll go through each company in more detail, starting with PSE&G.

PSE&G reported net income of $0.56 per share for the second quarter of 2020, compared with net income of $0.45 per share for the second quarter of 2019, and that's shown on Slide 16. PSE&G's second quarter results were driven by revenue growth from ongoing capital investment programs. Transmission results contributed an incremental $0.05 per share to second quarter net income, which included approximately $0.02 per share related to 2019 true-ups and lower pension expense.

Gas margin was $0.02 per share favorable, driven by gas system modernization program investments and weather-normalized volumes. Favorable weather comparisons quarter-over-quarter added $0.01 per share. And while electric bad debt expenses recovered through our societal benefits charge, gas-related bad debt expense in excess of the amount included in rates, reduced earnings by $0.01 per share compared to the second quarter of 2019, reflecting higher uncollectibles related to COVID-19.

Distribution-related depreciation and interest expense each lowered net income by $0.01 per share. And nonoperating pension expense was $0.03 per share favorable compared to the second quarter of 2019. And lastly, flow-through taxes and other items were $0.03 favorable compared to the second quarter of 2019. That's driven by the timing of taxes and the settlement of federal tax audits for the 2011 to 2016 years.

Weather in the second quarter of 2020 was favorable compared with the second quarter of 2019, but year-to-date, weather remains a mild headwind. Early summer weather was below normal, but 7% warmer than second quarter 2019 and weather-normalized electric sales in the second quarter, declined by about 7%, with residential loads up 8%, but more than offset by commercial and industrial sales that were approximately 14% lower in the quarter. I note that a majority of residential margin is driven by volume, while commercial and industrial margins are driven by peak demands. So as a result, for the year-to-date period, the net margin impact of higher residential margin has largely offset the lower commercial and industrial demands.

On a trailing 12-month basis, weather-normalized electric sales were down approximately 3% and gas sales were flat, with residential electric and gas usage both up by over 2%. PSE&G's capital program remains on schedule. PSE&G invested approximately $600 million in the second quarter and $1.2 billion through June as part of its 2020 capital investment program. The 2020 capital program reflects $2.7 billion in electric and gas infrastructure upgrades to our transmission and distribution facilities to maintain reliability and increase resiliency. And we continue to forecast over 90% of our planned capital investment will be directed to the utility over the 2020 to 2024 time frame.

PSE&G has continued the temporary suspension of nonsafety-related service shutoffs that began in March. And in July, the BPU authorized regulated utilities in New Jersey, including PSE&G to create COVID-19-related regulatory asset by deferring prudently incurred incremental costs beginning March 9, 2020, through September 30, 2021. PSE&G is evaluating the order and expects to record a deferral in the third quarter of 2020. PSE&G's forecast of net income for 2020 is unchanged and at $1.310 billion to $1.370 billion.

And now moving on to power. PSEG Power reported non-GAAP operating earnings for the second quarter of $0.24 per share and non-GAAP adjusted EBITDA of $258 million. This compares to non-GAAP operating earnings of $0.13 per share and non-GAAP adjusted EBITDA of $211 million for the second quarter of 2019. Our 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. The earnings release and Slide 22 provides you with a detailed analysis for the items having an impact on PSEG Power's non-GAAP operating earnings relative to net income quarter-over-quarter. And we've also provided you with more detail on generation for the quarter and for the first half of 2020 on Slides 23 and 24.

Power second quarter non-GAAP operating earnings were positively affected by several items that, in total, produced results $0.11 per share higher than the year-ago quarter. The June 1 scheduled increase in PJM capacity revenue moderated non-GAAP operating earnings comparisons to a decline of $0.07 per share compared with Q2 of 2019. The addition of ZECs to second quarter results added $0.02 per share. Recontracting and market impacts lifted results by $0.03 per share, reflecting seasonal shape of hedging activity and lower cost to serve versus the year-ago quarter. Gas operations improved by $0.01 per share over the prior year quarter. And lower O&M expense was a favorable $0.06 per share comparison over last year's second quarter, reflecting savings from descoping the plant Salem 2 refueling outage in April, the absence of last year's Salem 1 extended outage, the absence of cost at Keystone and Conemaugh and lower fossil outage and maintenance expenses.

Lower pension expense added $0.01 per share versus the year-ago quarter. And taxes and other items were $0.05 favorable compared to second quarter 2019, driven by the settlement of federal tax audits for the 2011 to 2016 years. Gross margin in the second quarter was $33 a megawatt hour, approximately the same as last year's second quarter. Power prices and natural gas prices stayed low as reduced commercial activity across PJM, New York and Maryland resulted in depressed loads.

Turning to Power's operations, total generation output declined by 3% to total 12.7 terawatt hours in the second quarter of 2020, reflecting the sale of the Keystone and Conemaugh units last fall. Power's combined cycle fleet produced 4.9 terawatt hours of output, up 3%, reflecting the addition of Bridgeport Harbor 5, which was placed into operation in June of 2019. The nuclear fleet operated at a capacity factor of 91.9% for the quarter, producing 7.8 terawatt hours, up 9% over the second quarter of 2019, and that represented 61% of total generation. This quarter's higher nuclear output reflects the absence of the extended Salem 1 outage in the second quarter of last year related to repair of reactor vessel bolts.

Power continues to forecast output for 2020 of 50 to 52 terawatt hours. And for the remainder of 2020, Power has hedged approximately 95% to 100% of production at an average price of $36 a megawatt hour. Lower prices for power and lower spark spreads have resulted in a slight reduction in our total forecasted combined cycle generation volumes in 2021, where we have hedged 65% to 70% of forecast production of 49 to 51 terawatt hours at an average price of $35 a megawatt hour. And for 2022, Power is forecasting output of 50 to 52 terawatt hours with approximately 25% to 30% of total output hedged at an average price of $35 a megawatt hour. Forecast for Power's non-GAAP operating earnings for 2020 remains unchanged at $345 million to $435 million as does our estimate of non-GAAP adjusted EBITDA of $950 million to $1.050 billion.

I'll briefly address the operating results from enterprise and other, where for the second quarter, we reported a net loss of $2 million compared to a net loss of $34 million for the second quarter of 2019. Our non-GAAP operating results for the second quarter of 2020, a loss of $2 million compared to non-GAAP operating earnings that was flat for the second quarter of 2019. And the net loss in the second quarter of 2020 reflects higher interest expense at the parent, partially offset by ongoing contributions from PSEG Long Island. And for 2020, the forecast in this area remains unchanged at a net loss of $5 million.

PSEG's financial position remains strong. At June 30, we had approximately $4 billion of available liquidity, including cash on hand of about $400 million and debt represented 52% of our consolidated capital. During the first half of 2020, PSEG also issued 3 364-day term loans, totaling $800 million for an added liquidity cushion. PSEG has $700 million of floating rate term loans maturing in November of 2020. PSE&G issued $375 million of 30-year, 2.7% secured medium-term loans in May and has $259 million of medium-term notes maturing during the remainder of the year. And Power retired $406 million of senior notes in April and ended June with debt as a percentage of capital of 29%.

Our credit rating agencies published updated research for PSEG during the second quarter, with unchanged ratings and a stable outlook. And we expect to fully fund PSEG's 5-year $12 billion to $16 billion capital investment program over the 2020 to 2024 period without the need to issue new equity. As Ralph mentioned, we continue to forecast non-GAAP operating earnings for the full year of $3.30 to $3.50, and we look forward to moving ahead with the strategic review we reported earlier today.

Phyllis, we are now ready to take questions.

(Operator Instructions) The first question comes from the line of Durgesh Chopra with Evercore ISI.

Maybe if you could help us just size the EBITDA for the nonnuclear generation assets. We're thinking it's roughly 20% of the total Power EBITDA. Does that seem reasonable? Can you comment on that?

Yes. Durgesh, we have not broken that out in the past and are not going to do that at this juncture. I think as we continue to go through the process, more information will come forward. But at this point, we're not going to provide that, and you can pull together your best estimate.

Understood. That's fair. And maybe can we get your thoughts on just in terms of the current market for just your merchant generation and going into the strategic review, how are you thinking about valuation for these assets? Just any high-level color on that front.

I'd say, Durgesh, our expectations is to conduct an extremely robust process without predetermining or self-limiting it in any way, and we'll let the market decide what these assets are worth. All highly efficient and good heat rates, environmentally-compliant in terrific markets. So we're pretty optimistic about it.

Okay. And just one really quick one and then I'll jump back in the queue. Is there a regulated to nonregulated business mix, Ralph, that you are targeting from this transaction?

Yes. So what we're trying to do is become as regulated as is possible and whatever remains being as contracted as is possible to remove that earnings volatility and to have people explicitly recognize the valuation that PSE&G deserves. So the contracted piece would be things like PSEG Long Island, right? That's a multiyear contract to operate that system out there. And then to the extent that the nuclear plants are supported by ZEC. That's not exactly contracted, but quasi supported by public policy and instrumental in terms of New Jersey's carbon aspirations.

Right. So basically we get to regulated -- get to as high regulated plus contracted mix as you can.

Yes, that's exactly right. So to get rid of the merchant piece, yes.

Your next question comes from the line of Jeremy Tonet with JPMorgan.

Just want to follow up with the strategic process as well. And just wondering if you could give a little bit more flavor as far as why now versus any point in the past. And I imagine it's sensitive overall the process, but I didn't know if you could speak at all to what would be the driver for a single-asset versus multi-asset process in the release, You mentioned in the release, just trying to see what details you can share here.

Yes, Jeremy. So we have said for quite some time that we eventually thought these businesses would separate, and we gave certain conditions under which we thought that would happen. And one of those, I won't bore you with all of them, one of those was a sustained discount and evaluation, which to us, will be a demonstration that investors were not satisfied with an integrated model. And we have a couple of things that we're in the process of tackling that seem to us, at least, to be in the market waiting for good news. So the utility is going to grow at 6.5% CAGR. But CEF is going to add to that. So that's the absence of a positive. We've been very public about our discussions on transmission ROE. So that's a bit of an unknown yet, but not a big unknown. And we got good news coming out of the FERC MOPR in terms of our nuclear plants, being able to bid basically at 0 and clear that market. So the remaining piece is the discount associated with having the integrated model. And you can't put our current valuation all on the backs of transmission ROE. You'd just have to make -- forgive me if it's impolite, but some really crazy assumptions to get PSEG valuations that make sense with that being the only case. So we don't -- we just said it right, that predetermined factor that we've always been paying attention to, which is a sustained discount in valuation appears to have manifest itself. So let's pursue acting on that.

Great. That makes sense. That's helpful. And just...

And U.S. also, in terms of pieces or the whole thing, I really -- at the risk of repeating what I said a moment ago, our plan is to make this process as robust as possible to get the cleanest signal from the market about how to optimize the value to our shareholders. And if that means one check for everything or 5,700 -- 6,700 checks for each megawatt, I'm being absurd there, obviously, we'll entertain that whole range.

Got it. That's very helpful. And then do you expect any material change to managing the nuclear portfolio after you divest the other power assets? And how might the sale here impact your financing plans given the importance of power, free cash flow to funding utility growth?

So in terms of the nuclear -- I'll let Dan speak to the financing. But in terms of the nuclear operations, they have largely been separate for their entire existence. Nuclear has its own engineering group, its own maintenance group, its own operations group, its own supply chain, its own HR support, so that should be a nonevent from an operations point of view.

Yes. I think from a financing perspective, I think that one of the key uses of proceeds, I think, would be to pay down debt at Power. Obviously, if you think about the indenture and the structure of that, you've got the asset sitting underneath Power and to the extent that we see some separation there and sell the cash that would come in would be used to pay down that debt. So you would also have less interest expense on a go-forward basis to the extent that, that would end up happening. And also a better business mix and a better credit profile. So the ability to draw some debt capacity from that as well. So that's how we would think about it.

So overall, no real impact to future equity needs at this point?

That's correct.

That's correct.

Your next question comes from the line of Julien Dumoulin-Smith with Bank of America.

So following up on Jeremy's question there, can we talk about how you think about the financing on a go-forward basis? I don't want to get into the proceed expectation, but again, given the backdrop of the Dominion transaction recently and the repositioning, can you just give us a little bit of a sense on how you think about financing the business prospectively? And specifically, how you think about equity needs relative to dividends and specifically emphasis on dividend, if you can?

So I'll start and then Dan, I'll tell you the real story. I mean the utility earnings, far and away, more than cover the dividend. And the utility rate base CAGR growth is in excess of our dividend growth over the past 5 to 10 years. So from the point of view to dividend policy, obviously, reserving the right of the Board to always make decisions each quarter. We are highly confident that, that's a no, never mind. In terms of the financing, the change in the business mix is going to change the potential for the parent to borrow and the delevering that will take place from the proceeds will -- and there'll be a residual power function from a nuclear plant point of view, we'll free up some investment capacity there as well. And don't forget, Julien, our biggest cash generator for the past few years has been the utility. So we've done a bunch of analysis. And obviously, we'll wait and see how the process unfolds. But we feel pretty good about where our financing will come from and how we'll be able to support strong utility growth. That's the goal here, right? Strong, consistent utility growth.

Right. But what -- go for it.

Go ahead, Julien.

I was -- sorry, I was going to say to that point, how do you think about your balance sheet at a consolidated level? You talked about paying down and if I heard you right, that basically the entirety of proceeds would be used to pay down Power debt. But from a consolidated basis, how do you think about pro forma metrics from an FFO to debt perspective, right, given a different risk profile, et cetera? I think that's probably another angle here, right?

Yes. Whether it's the entirety of proceeds is to be determined, right? I think that it's more likely the entirety of the debt, and then we'll see what ultimate aggregate proceeds end up coming in. I think that where you land from the standpoint of overall debt capacity is going to be a function of that business mix, and it's going to be a function of working with the rating agencies to make that determination. And -- but undoubtedly, that is going to be an improvement. And undoubtedly, that's going to be some debt capacity that's going to open up from that perspective. So that's how we're thinking about it. The fine points on that are ahead of us yet. But I think that's how you think about it. And frankly, Julien, we tend to think about our overall financing is coming from the utility is being self-funding, the utility with a very strong cash from operations in its own right. And then ultimately, on the other side, there's a money pool where you'd have access to the Power and the parent as funding vehicles. And I think that what you're going to see is just more of a shift in potential to the parent, although the remaining operations that would sit at Power certainly would have a stream of cash flow and would have the ability to have some financing there as well.

Cool. Just a quick question or clarification on the release. Timing, do you need to wait for FRR in some of these cases get resolved before actually completing this?

No. No. I don't think those are totally independent processes.

Your next question comes from the line of David Arcaro with Morgan Stanley.

Could you give your latest thoughts on the transmission ROE negotiations in terms of what timing you might be aiming for? And then kind as a follow-on, other ways that you have in mind that could potentially mitigate some of the EPS impacts from that, whether it be on the equity ratio or cost allocation side of things?

Yes. So thanks, David. The negotiations are confidential, so I apologize for not being able to give you specifics. But your -- the contents of your question actually gets right to the heart of the matter that this isn't about a single number, what the ROE is. This is about a variety of issues. What is the depreciation rate of the assets, what's the equity layer associated with the business, what are acceptable components of the FERC formula rate filing in terms of cost that maybe had not been captured in the past that could be captured now.

So what I'd say is both sides are eager to provide relief to customers and eliminate an uncertainty in terms of where this could end up. However, what matters to us is the overall economics. And I think what matters to the regulators is the cash impact on customers. So what we're trying to do is balance each of those variables, if you will, to each achieve our stated objective. I'm hopeful we can do it, but I'm not certain we can do it. And we'll just -- unfortunately, I can't say more than that at this point in time. I mean the BPU staff is working hard. The consumer advocate is working hard. We're -- we talked, I think, at least weekly, maybe it's biweekly and they have other things that they need to attend to. But it is an overall economic assessment that we need to make, and we're not going to agree to something voluntarily that we believe is more difficult or less palatable as something that we would be able to achieve at FERC. So to be continued.

Understood. No, that makes sense. And I guess, would there be any change in the timing of the rough time frame that you've communicated in the past for that?

No, I don't think so. I mean, it's a question of patience that the BPU staff and the consumer advocate have, I mean, they could file a complaint tomorrow, and we certainly are not encouraging that, but we're not going to let the potential of filing a complaint make us deviate from what we know as an economically reasonable outcome. And it would be a shame if we couldn't reach that outcome because the fact of the matter is if a complaint was filed, it wouldn't be resolved it for years to come. And New Jersey is struggling with 16% unemployment and all manner of economic challenges that it would be in everybody's interest to try to return some rate relief to customers today. But no, I mean, yes, they could file it tomorrow. I can't constrain that. But we're still trying.

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

Obviously, lots going on and congrats on it. Interesting steps. 2 questions. One on Power. And why sell down given the clean attributes associated with it? I know it's small, but why sell down the solar assets? Or why sell off the solar assets? Why not keep those embedded? And do you see utility-scale solar or not see it is that an attractive business longer term?

Yes. So Michael, on that one, it's 479 megawatts. I think the biggest project is like 40 or 50 megawatts, and most of them are 5 and 6. They're spread around 17 states. So the scale isn't what we'd like it to be. And candidly, we'd like to focus more of our green and carbon-free attributes in the mid-Atlantic region. And as it relates to, particularly nuclear and potentially, offshore wind. Plus, it's really because of its size, what I'm about to say it's hard to prove. We don't think we were getting proper credit for it in our own valuation. It's almost never picked up. You put an EBITDA multiple on something that's largely benefiting from investment tax credits, and that doesn't get reflected in the stock price in a way that it might provide greater value to somebody who has a different calculus around what -- how to measure economic value. Yes, I don't know if you want to -- you said you had a second question, Michael?

Yes. I had a second question. When I go back and look at your investor slide decks, and I'm looking at the capital spending charts in the slide decks from the last few months or so and the CapEx by year for PSE&G. And this has happened for years with your company is that you forecast transmission CapEx to just fall of a cliff, kind of gradually every year, year 2 is lower than year 1, year 3 is lower than year 2. Year 4 is lower than year 3. It actually never happens. Do you have any incremental color about what could make 2021 or 2022 transmission CapEx materially different or significantly different than kind of what you've shown on your latest slide decks for those years?

No. So what you said about transmission is actually true to the capital program overall, and we try to point that out in a good old days when we can actually meet face-to-face at an investor conference that is purely a function of the fact that things are less firm in years 3, 4 and 5 than they are in years 1 and 2. To your specific question about transmission, most of the big projects that came out of the PJM RTEP are pretty much complete or near complete. And a good part of our effort now is in upgrading our 26 kV system to 69. That will result in an overall reduction in the transmission spend. But that's fully baked into that 6.5, the 8% CAGR number that we put out there. The possible -- there is a possibility of increasing transmission investment as New Jersey continues its pursuit of offshore wind. And we go from 1 gigawatt to potentially 7.5 gigawatt future. The current project that Ørsted one had a very miniscule effect on the onshore transmission system. But as you start moving 7.5 gigawatts of power onto to New Jersey, then that could change. So -- and then last but not least, one of the things that the BPU is talking to all utilities, not just us, that is the possibility for accelerating some of the infrastructure programs that we want to do to help create some economic stimulus. And just given the age of our transmission infrastructure, the age of [RDS] infrastructure, that is something that could provide further opportunities for us as well.

Are there any public filings or any dockets or proceedings open, whether at PJM or whether at the BPU regarding incremental transmission spent over the next couple of years?

I don't think -- I'm wondering -- there may be -- we can get back to you, Michael. There may be a BPU docket on how to bid future offshore wind projects, whether they separate the transmission from the actual wind farm because as you probably know, the first solicitation had those 2 bundled together. And I thought the BPU was looking at whether or not to separate them, but that may be over. I'm not sure we can get back to that.

Yes. And the first offshore wind station, Michael, really was it was offshore wind and the line coming into shore all in one solicitation. So to the extent that there is -- and that's been the only solicitation in New Jersey to the extent that there are more solicitations and more of an ability to link up projects that are out in the ocean and then doing it in different ways and maybe carving it up. That's the kind of thing that is being looked at as a policy question. But what I think that wherever that does land, it sounded like your question was really nearer term. So for capital deployment really in the immediate term, I wouldn't expect -- I think your question was '21, '22, that would be on the early end of anything. If anything would happen by that time frame on what we're talking about. So if that's your time frame, I think, less likely. I think, as we go out into the future and try to make some longer-term determinations as how to best target the magnitude of offshore wind that the state is looking for, you may see more into the future.

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

So I wanted to just sort of make sure that I just want to clarify something here. So the divestiture or the strategic review, that's purely being basically driven by, if I understand, the stock valuation? There's no real significant change in market outlook or regulatory stuff that's going on here. This is just basically, hey, is it worth more to -- the valuation equation basically mean it's a good time to look at it. Am I understanding that correctly?

That's exactly right.

And then with respect to the FRR, and -- I guess someone else touched on this. There's no change in that process that you see taking place as a result of this? And do we still -- do you think -- I think you guys were basically under the impression that we -- it was a very good chance you don't need legislation. Is that sort of still the case?

So well lots of questions there. So we're not driving the FRR bus, right? That's being driven by the BPU. So that's a totally independent process. And I think the state is still trying to figure out do they want an FRR that simply secures their carbon-free energy? Do they want to do an FRR that secures all of their energy? And I don't see that being in any way, shape or form, influenced by our decision to divest of our fossil assets.

In terms of legislation, that is purely a function of what kind of FRR they design. So if there's a better than even chance that no legislation is needed, but -- for example, in the creation of an OREC legislation was required. If there's a similar thinking about any other kind of particular technology, then there might be a need for legislation. So it's just too early in the FRR discussions to be definitive. What you're accurately quoting, Paul, is that once upon a time when we thought all that would happen was that our nuclear plants will be supported by BGS that there would not be a need for legislation. But I think the PJM compliance filing that shows that our nuclear plants are free to bid and compete in capacity markets has really diminished the need for anything specific to our nuclear plants at this time.

Your next question comes from the line of Paul Fremont with Mizuho.

I think I just want to follow up a little bit on Julien's line of questions. It looks like your downgrade threshold, according to the Moody's report put out earlier this year, was 17%, and you ended the year, 1% below that. If you were to essentially lose some additional cash flows on the merchant side and use back leverage to fund utility investment going forward, that could put further pressure on your FFO-to-debt ratio. So I guess my question is, would you be willing to accept ultimately a downgrade in the credit rating? Or what would you see as potentially happening on the FFO-to-debt side?

Yes, Paul, obviously, a whole lot of moving parts with respect to what we're talking about and a lot of discussions yet to be had and ability to work through those things. I think what I would say is if you think about the overall business mix of enterprise and you think about that business mix without the nonnuclear generation, I think you have a more stable set of cash flows coming off the business. And I think at the end of the day, you would have a lower threshold from the standpoint of what that newly designed entity look like. So I think that's a part of the calculus that becomes important in all this as we work forward and come to some determinations.

Paul, sorry, I was hoping you'd ask us a question about CEF. By the way, we -- our annual run rate right now in CEF is $200 million a year. It's not $40 million a year because we got $110 million extension for 6 months. And also, as far as we could tell, negotiations are pretty active. We expect either a settlement or a decision by the BPU in September. So we're...

Yes. No, I think we're definitely anticipating a settlement, I think, is what we wrote in the last report that we put out. So we don't know the timing, but we are very optimistic that there will be a settlement in that proceeding.

Okay. Well my timing is September, just so the world knows that. Thanks.

Your next question comes from the line of Steve Fleishman with Wolfe Research.

So just a couple of questions. First of all, you have kind of talked for a little while about kind of willingness to sell the fossil assets. So maybe could you just give a little more color like what is different now versus what you've already been saying for kind of 6 to 12 months? I think you were worried about getting a fair price to some degree. So are you more confident on that? Or some color there?

Yes. I'd say 2 things, Steven. Number one is getting a fair price given the capacity market uncertainty in PJM. And that, I think, yes, we don't -- we haven't run an auction, but the rules are pretty clear in terms of what's going to happen there. But I would say it's just the valuation discount has expanded to the point where just -- it's not fair, right? It just doesn't make any sense for PSEG to be valued where it is. And you can't put it all on the backs of transmission ROE without making truly ludicrous assumptions. So it really was a case of enough is enough. And I do think that unlike the BEC process, where we candidly did a little bit of a test program, we went out to a handful of people who we thought might have interest. We're not going to do that. We're going to conduct a very robust process. And we're going to just run it differently than that probe was run. So I'd say, yes, there's a calming in the power markets and further expansion of the discount and evaluation that conspire to say enough is enough.

Okay. A couple of just technical questions on it. Do you have the tax basis of the assets that you could provide us? And also just how should we think about dealing with like dissynergies? Is that something you can manage?

Yes. Steve, we don't have a tax basis number to provide. It's certainly going to be lower on the federal side, if you think about some of the expensing that's gone on. So I would think about it against the backdrop of some of bonus has gone on. And there's not a dissynergy number. But obviously, to the extent that you've got some of the costs that you see getting spread across the various businesses, there will be some of that, right, that you'll have a smaller entity to be able to spread over. But also as we look at this, we'll be looking at efficiencies across the business as a whole to try to make up some of that.

Great. And then last question. On offshore wind, is there any -- I may be overreading it, but I kind of feel like there's a little bit more of a tone of kind of interest in moving forward with offshore wind growth. Could you maybe just give a little more color on that talking about the future auctions coming up to and -- yes. Yes.

Yes. No. So certainly, we're still where we have been all along, Steve, from the point of view of trying to maximize this opportunity that's available to us to learn. We're in a different place, we have learned more, and we are gaining confidence in the ability to construct and own and operate, probably can't say the same in terms of the regulatory process, particularly at the national level. And you, I'm sure, aware that New Jersey has begun discussions about round 2 solicitation, and that's expected to begin, I think, in a couple of months. So the state is moving, and I do believe all within Governor Murphy's first term, you'll see solicitations and securing a 3,500 megawatts of offshore wind. So this is becoming more and more real with every day. And I have no reason to not believe that the state's full aspirations of 7,500 megawatts as well as New York state's 9,000 megawatts and so on, on the list won't be realized. So you are picking up in my voice that this is going to happen at a scale that I would not have predicted 3 or 4 years ago. But you see it coming along right now.

We have time for one final question. Your next question comes from the line of Sophie Karp with KeyBanc.

Can you hear me?

Yes.

Maybe if I could sneak in a couple of related questions on the power side. So you're keeping nuclear power plants, and we understand they have been substantially derisk [BSX]. And is there, however, a scenario where you can envision that they may find a different home also? And then another question I had is, is there any implication -- are there any implications for how much headroom on your customer build you have on your New Jersey asset divestiture?

Sophie, in the spirit of you never say never, I wouldn't want to say the word never. But we are not marketing those nuclear plants. We have every intention and expectation of holding on to them and marketing the nonnuclear assets to solar source and the fossil fleet. And plus, I just think that the candidate pool for purchasing is vastly, vastly larger for the fossil assets, right? So again, at the risk of repeating myself, you never say never, but I think it's -- you put -- that would be in the conjecture and a mode that is not time well spent. And because I've dabbled on for long, I forgot what your second question was. What was it?

Is there -- are there any implications on the bill headroom in the Jersey?

No, not at all. I would think not. No, I mean, your power prices in the forward market, as we've said, are down from where they were just 2 years ago, and there continues to be pressure on forward power prices, both because of the abundance of natural gas, the reduction in load and the availability of highly efficient generation. So we match -- we try to match all of our utility proposed programs to a bill impact of roughly CPI and we try to do that in a way that includes rolling in of rates every 6 to 12 months. So there is no price and rate shock to the customer. And of course, we are firm believers that energy efficiency can be targeted to those customers who are A, either most vulnerable; or B, most broadly, providers of services to the population at large, and therefore, benefit the population at large by reducing their energy consumption.

I do think that runs us past the appointed hour, so I would be remiss, notwithstanding all the news and hopefully really good and exciting news that we shared with you. If I didn't simply say to everyone on the call that I hope you and your families and friends are experiencing good health and have not been affected by this horrible challenge that we have in the form of COVID-19. And to the extent that any of you have friends or families who have been frontline health workers, we at PSEG truly express our thanks to you and to them indirectly. And please, I mean that, convey that to them.

We had just an amazing, terrific effort by our employees. We've not been untouched by COVID-19. Our infection rates are about half of the general population. Our employees are managing to work safe and just produce some phenomenal cost savings, yielding a very strong quarter. I know we had some onetime stuff, but even if you back that onetime stuff out, I think we had a terrific quarter.

And Dan and I aren't the dancing types, but hopefully, you can hear in our voice the excitement, the genuine excitement we feel about the pursuit of the strategic alternative and what that means for the concentrated, focused growth of the utility, especially a CEF that we expect to be resolved by September. Hi, Paul. And we look forward to seeing you all in person, but until then, we'll see you at some upcoming virtual conferences over the next several weeks. Thanks, everyone.

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