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. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session for members of the financial community. At that time, if you have a question, you will need to press the star and the number one on your telephone keypad. To withdraw your question, press the pound key. As a reminder, this conference is being recorded today, July 31st, 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 two 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. We must all remain vigilant as we see signs of potential increases. 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 9th of this year through at least September 30 of 2021.
PSE&G will file its first quarterly report to the BPU on August 3rd, outlining its COVID-related costs and offsets for the period ended June 30th, and we expect to record a 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 we often refer 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 this storm particularly challenging. Our PSE&G crews worked 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 mi 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 continuing 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 six-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 six 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 in 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 the 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, as the default alternative.
As I said a moment ago, PSE&G energy volumes have declined due to the COVID-19 restrictions, but peak load for the second quarter remained in a normal seasonal range, averaging 5,100 MW versus last year's second quarter average of 5,330 MW. PSE&G summer load peaked at 9,753 MW in 2019. This summer, we experienced a peak load of 9,521 MW on July 22nd, 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 is the driver behind Zero Emission Certificates or ZECs. Our Salem and Hope Creek nuclear plants produce over 90% of New Jersey's 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 two 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 a 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. 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 double A from single A, placing us in the top 20% of all companies they evaluate on environmental, social, and governance disclosure. 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: Residential study. Turning to earnings guidance, we are reaffirming PSEG's non-GAAP operating earnings guidance for full year 2020 of $3.30-$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 five-year, $12 billion-$16 billion capital plan without the need to issue new equity. Our net liquidity position as of June 30th remains ample at $4 billion. Finally, as you have all seen by now, this morning, we also announced that PSEG is exploring strategic alternatives for PSEG Power's non-nuclear 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 a potential separation of the non-nuclear 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 in 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 non-nuclear 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 interests of our diverse stakeholders, including our 13,000 valued employees.
Any decision regarding the non-nuclear 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. 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. Slide 12, you'll see a waterfall chart that takes you through the net changes quarter-over-quarter and non-GAAP operating earnings by major business. 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. While electric bad debt expense is 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 non-operating pension expense was $0.03 per share favorable compared to the second quarter of 2019.
Lastly, flow-through taxes and other items were $0.03 favorable compared to the second quarter of 2019, as driven by the timing of taxes and the settlement of federal tax audits for the 2011-2016 years. Weather in the second quarter of 2020 was favorable compared with the second quarter of 2019, year-to-date weather remains a mild headwind. Early summer weather was below normal, 7% warmer than second quarter 2019. Weather-normalized electric sales in the second quarter declined by about 7%, with residential loads up 8%, more than offset by commercial and industrial sales that were approximately 14% lower in the quarter. I know that a majority of residential margin is driven by volume, while commercial and industrial margins are driven by peak demands.
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 - 2024 timeframe. PSE&G has continued the temporary suspension of non-safety-related service shutoffs that began in March.
In July, the BPU authorized regulated utilities in New Jersey, including PSE&G, to create a COVID-19-related regulatory asset by deferring prudently incurred incremental costs beginning March 9th, 2020 through September 30th, 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 at $1,310,000,000-$1,370,000,000. 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 provide you with a detailed analysis of the items having an impact on PSEG Power's non-GAAP operating earnings relative to net income quarter-over-quarter. We'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 1st 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 OM expense was a favorable $0.06 per share comparison over last year's second quarter, reflecting savings from de-scoping the planned 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. Taxes and other items were $0.05 favorable compared to second quarter 2019, driven by the settlement of federal tax audits for the 2011-2016 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 TWh 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 TWh 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 TWh , 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 - 52 TWh .
For the remainder of 2020, Power has hedged approximately 95%-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%-70% of forecast production of 49-51 TWh at an average price of $35 a megawatt-hour. For 2022, PSEG Power is forecasting output of 50-52 TWh with approximately 25%-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-$435 million, as does our estimate of non-GAAP adjusted EBITDA of $950 million-$1,050 ,000,000.
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 was a loss of $2 million compared to non-GAAP operating earnings that was flat for the second quarter of 2019. 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. For 2020, the forecast in this area remains unchanged at a net loss of $5 million. PSEG's financial position remains strong. At June 30th, 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 three 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. Its 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. Power retired $406 million of senior notes in April and ended June with debt as a percentage of capital at 29%. Our credit rating agencies published updated research for PSEG during the second quarter with unchanged ratings and a stable outlook. We expect to fully fund PSEG's five-year $12 billion-$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.
Ladies and gentlemen, we will now begin the question and answer session. For members of the financial community, if you have a question, please press the star and the number one on your telephone keypad. If your question has been answered and you wish to withdraw your polling request, you may do so by pressing the pound key. If you are on a speakerphone, please pick up your handset before entering your request. One moment, please, for the first question. The first question comes from the line of Durgesh Chopra with Evercore ISI. Please proceed with your question.
Hey, good morning, team. Thank you for taking my question.
Morning, Durgesh.
Maybe if you could help us just size the EBITDA for the non-nuclear generation assets. We're thinking it's roughly 20% of the total power EBITDA. Does that seem reasonable? Can you comment on that?
Yeah, 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. At this point, we're not going to provide that, and you can pull together your best estimate.
Understood. That's fair. Maybe can we get your thoughts on just in terms of the current market for merchant generation and going into the strategic review, how you're thinking about valuation for these assets? Just any high-level color on that front?
Yeah, I'd say, Durgesh, that our expectations is to conduct an extremely robust process without predetermining or self-limiting it in any way. We'll let the market decide what these assets are worth. They're all highly efficient, good heat rates, environmentally compliant, and in terrific markets, so we're pretty optimistic about it.
Okay. Thanks for that, Ralph. Just one really quick one, and then I'll jump back in the queue. Is there a regulated to non-regulated business mix, Ralph, that you're targeting from this transaction?
Yeah. 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. The contracted piece would be things like PSEG Long Island, right? That's a multi-year contract to operate that system out there. To the extent that the nuclear plants are supported by ZEC, that's not exactly contracted, but Plaza, supported by public policy and instrumental in terms of New Jersey's carbon aspirations.
Right. Basically get to as high regulated plus contracted mix as you can.
That's exactly right. Yeah.
Okay. All right.
To get rid of the merchant piece. Yeah.
Understood. Thanks, guys. Appreciate the time.
Your next question comes from the line of Jeremy Tonet with JP Morgan.
Hi, good morning.
Good morning.
Just wanted to follow up with the strategic process as well, just wondering if you'd give a little bit more flavor as far as why now versus any point in the past. I imagine it's sensitive overall, the process, but 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 the release, just trying to see what details you can share here.
Hey, Jeremy. 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. One of those, I won't bore you with all of them, one of those was a sustained discount in the valuation, which to us would be a demonstration that investors were not satisfied with an integrated model. We have a couple of things that we're in the process of tackling that seem, to us at least, to be the market waiting for good news. The utility's going to grow at 6.5% CAGR. CEF is going to add to that. That's the absence of a positive. We've been very public about our discussions on transmission ROE. That's a bit of an unknown yet, but not a big unknown.
We got good news coming out of the FERC MOPR in terms of our nuclear plants being able to bid basically at zero and clear that market. 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 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. We just said, all right, that predetermined factor that we've always been paying attention to, which is a sustained discount in our valuation, appears to have manifested itself. Let's pursue acting on that.
Great. That makes sense. That's helpful.
You asked 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. If that means one check for everything or 6,700 checks for each megawatt, I'm being absurd there obviously. We'll entertain that whole range.
Got it. That's very helpful. Thank you. Do you expect any material change to managing the nuclear portfolio after you divest the other power assets? How might the sale here impact your financing plans given the importance of power free cash flow to funding utility growth?
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. That should be a non-event from an operations point of view.
Yeah, 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 sale, the cash that would come in would be used to pay down that debt. You would also have less interest expense on a go-forward basis to the extent that that would end up happening. Also a better business mix and a better credit profile. The ability to draw some debt capacity from that as well. That's how we would think about it.
Overall, no real impact to future equity needs at this point?
That's correct.
That's correct.
Great. Thank you so much for taking my question.
Thanks, Jeremy.
Your next question comes from the line of Julien Dumoulin-Smith with Bank of America.
Hey, good morning, team. Thanks for the time.
Good morning, Julien.
Pleasure. 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, 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? Specifically, how you think about equity needs relative to dividends, and specifically emphasis on dividend, if you can?
I'll start and then Dan will tell you the real story. 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 - 10 years. From the point of view of the dividend policy, obviously reserving the right of the board to always make decisions each quarter, we are highly confident that that's a no nevermind. In terms of the financing, the change in the business mix is going to change the potential for the parent to borrow, and the de-levering that'll take place from the proceeds will, and there'll be a residual power function from the nuclear plant point of view, will free up some investment capacity there as well. Don't forget, Julien, our biggest cash generator for the past few years has been the utility.
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. Oh, go for it.
No, go ahead, Julien.
I'm 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, if I heard you right, that basically the entirety of proceeds would be used to pay down power debt. From a consolidated basis, how do you think about pro forma metrics from a FFO- to- debt perspective, right? Given a different risk profile, et cetera. I think that's probably another angle here, right?
Yeah. 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. 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. That's how we're thinking about it. The fine points on that are ahead of us yet. I think that's how you think about it. Frankly, Julien, we tend to think about our overall financing is coming from the utility as being self-funding.
The utility with a very strong cash from operations in its own right. 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. 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 quick question or clarification on the release timing. Do you need to wait for FRR and some of these key issues get resolved before actually completing this?
No.
Okay.
Those are totally independent processes.
Fair. Excellent. Thanks for clarifying that, especially the dividend.
Thanks, Julien.
Your next question comes from the line of David Arcaro with Morgan Stanley.
Hi, good morning. Thanks for taking my question.
Hi, David.
Hey, David.
Could you give your latest thoughts on the transmission ROE negotiations in terms of what timing you might be aiming for? Then, kind of 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?
Yeah. Thanks, David. The negotiations are confidential, I apologize for not being able to give you specifics, 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 costs that maybe had not been captured in the past that could be captured now? 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, I think what matters to the regulators is the cash impact on customers.
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. Unfortunately, I can't say more than that at this point in time. I mean, the BPU staff is working hard, the consumer advocate's working hard. We talk, I think, at least weekly, maybe it's biweekly. They have other things that they need to tend to. 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. I guess, would there be any change in the timing of the rough timeframe that you've communicated in the past for that?
No, I don't think so. It's a question of the patience that the BPU staff and the consumer advocate have. They could file a complaint tomorrow. 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 is an economically reasonable outcome. 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 at FERC for years to come. 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. No, they could file it tomorrow. I can't constrain that. We're still trying.
Okay, great. No, thank you very much.
Your next question comes from the line of Michael Lapides with Goldman Sachs.
Hey guys, thank you for taking my question. Obviously, lots going on. Congrats on it. Interesting steps. Two questions, one on power. Why sell down given the clean attributes associated with it? I know it's small, why sell off those solar assets? Why sell off those solar assets? Why not keep those embedded? Do you see utility-scale solar or not see it as an attractive business longer term?
Yeah. Michael, on that one, it's 479 MW. I think the biggest project is like 40 or 50 MW, and most of them are 5 MW and 6 MW. They're spread around 17 states. 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. Because of its size, what I'm about to say is 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 how to measure economic value.
Dan, I don't know if you want to.
And if-
You said you had a second question, Michael?
Yeah, 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 and the slide decks from the last few months or so, and the CapEx by year for PSE&G. This has happened for years with your company, is that you forecast transmission CapEx to just fall off a cliff, kind of gradually every year. Year two is lower than year one, year three is lower than year two, year four is lower than year three. 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?
What you said about transmission is actually true of the capital program overall, and we try to point that out in the 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 three, four, and five than they are in years one and two. 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 kV. That will result in an overall reduction in the transmission spend. That's fully baked into that 6.5%-8% CAGR number that we put out there.
There is a possibility of increasing transmission investment as New Jersey continues its pursuit of offshore wind, and we go from a 1 GW to a potentially 7.5 GW future. The current project, that Ørsted one, had a very minuscule effect on the onshore transmission system. As you start moving 7.5 GW of power onto New Jersey, then that could change. Last but not least, one of the things that the BPU is talking to all utilities, not just us, about is the possibility for accelerating some of the infrastructure programs that we want to do to help create some economic stimulus. Just given the age of our transmission infrastructure and the age of our gas 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 spends over the next couple of years?
I don't think so. I'm wondering though, we could get back to you, Michael. There may be a BPU docket on how to bid future offshore wind projects, whether to separate the transmission from the actual wind farm. As you probably know, the first solicitation had those two bundled together. I thought the BPU was looking in whether or not to separate them, but that may be over. I'm not sure. We can get back to you on that.
Yeah. The first offshore wind solicitation, Michael, really it was offshore wind and the line coming into shore all in one solicitation. 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. I think that wherever that does land, it sounded like your question was really nearer term. For capital deployment really in the immediate term, I wouldn't expect, I think your question was 2021, 2022. That would be on the early end of anything, if anything would happen by that timeframe on what we're talking about.
If that's your timeframe, 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.
Got it. Thank you, Ralph. Thank you, Dan.
Yeah.
Your next question comes from the line of Paul Patterson with Glenrock Associates.
Hey, how you guys doing?
Hey, Paul.
Good. How are you?
Great. I wanted to just sort of make sure that I just want to clarify something here. The divestiture or the strategic review, that's purely being basically driven by, if I understand, 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? Does the valuation equation basically mean it's a good time to look at it?" Am I understanding that correctly?
That's exactly right. [crosstalk]
Okay. With respect to the FRR. I guess someone else touched on this. There's no change in that process that you see taking place as a result of this. Do you think, I think you guys were basically under the impression that there was a very good chance you don't need legislation. Is that sort of still the case?
Wow, lots of questions there. We're not driving the FRR bus, right? That's being driven by the BPU. That's a totally independent process. 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? 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. There's a better than even chance that no legislation is needed. For example, in the creation of an OREC, legislation was required. If there's a similar thinking about any other kind of particular technology, there might be a need for legislation.
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 would be supported by BGS, that there would not be a need for legislation. 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.
Okay, great. The rest of my questions have been asked and answered, and thanks so much. Have a great one.
Your next question comes from the line of Paul Fremont with Mizuho.
Thanks. 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. 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?
Yeah, 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 non-nuclear generation, I think you have a more stable set of cash flows coming off the business. 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. I think that's a part of the calculus that becomes important in all this as we work forward and come to some determinations.
Great. Thank you.
Paul, sorry, I was hoping you'd ask us the question about CEF. Our annual run rate right now at CEF is $200 million a year. It's not $40 million a year because we got a $110 million extension for six months. As far as we could tell, negotiations are pretty active. We expect either a settlement or a decision by the BPU in September.
Yeah. No, I think we're definitely anticipating a settlement, I think is what we wrote in the last report that we put out. 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.
Hey, good morning. Thought I was going to miss you. Hey, Ralph.
How are you?
I'm doing great, thanks. Just couple of questions. First of all, you have kind of talked for a little while about kind of willingness to sell the fossil assets. Maybe could you just give a little more color, like what is different now versus what you've already been saying for kind of 6-12 months? I think you were worried about getting a fair price to some degree. Are you more confident on that or some color there?
Yeah. I'd say two things, Steve. Number one is getting a fair price given the capacity market uncertainty.
PJM and that I think, yeah, we haven't run an auction, but the rules are pretty clear in terms of what's going to happen there. I would say it's just the valuation discount has expanded to the point where it's not fair. It just doesn't make any sense for PSEG to be valued where it is.
Right
you can't put it all on the backs of transmission ROE without making truly ludicrous assumptions. It really was a case of enough is enough. I do think that unlike the BEC process, where we candidly did a little bit of a test probe, and 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. I'd say, yeah, there's a calming in the power markets and a further expansion of the discount and valuation that conspired to say enough is enough.
Okay. Couple of just technical questions on it. Do you have the tax basis of the assets that you could provide us? Also just how should we think about dealing with synergies? Is that something you can manage?
Yeah, 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. I would think about it against a backdrop of some of bonuses gone on. There's not a dis-synergy 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. You'll have a smaller entity to be able to spread over. 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. Last question, on offshore wind, I may be overreading it, but I kind of feel like there's a little bit more of a tone 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, too? Yeah.
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 as 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. You, I'm sure, are aware that New Jersey has begun discussions about round two solicitation, and that's expected to begin, I think, in a couple of months. The state is moving, and I do believe all within Governor Murphy's first term, you'll see solicitations and securing of 3,500 MW of offshore wind.
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 MW, as well as New York State's 9,000 MW and so on down the list, won't be realized. You are picking up in my voice that this is going to happen at a scale that I would not have predicted three or four years ago. You see it coming along right now.
Great. Thank you.
We have time for one final question. Your next question comes from the line of Sophie Karp with KeyBanc.
Hi, can you hear me?
Yes, sure.
Hi, sure.
Hi. Thanks for taking my question. Maybe if I could sneak in a couple of related questions on the power side. You're keeping nuclear power plants, and we understand they have been substantially de-risked via ZECs. Is there, however, a scenario where you can envision that they may find a different home also? Another question I had is are there any implications for how much headroom on your customer bill you have in New Jersey after this divestiture? Thank you.
If 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 onto them and marketing the non-nuclear assets, the Solar Source, and the fossil fleet. Plus, I just think that the candidate pool for purchasing is vastly larger for the fossil assets. Again, at the risk of repeating myself, you never say never, but I think that would be in the conjecture and a mode that is not time well spent. Because I babbled on so long, I forgot what your second question was. What was the end?
Are there any implications on the bill headroom in New Jersey?
No, not at all. I would think not, no. The power prices in the forward market, as we've said, are down from where they were just two 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. 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- 12 months, so there is no price and rate shock to the customer.
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. I would be remiss, notwithstanding all the news and hopefully really good and exciting news that we share 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.
To the extent that any of you have friends or family who have been frontline health workers, we at PSEG truly express our thanks to you and to them indirectly, 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 produced some phenomenal cost savings, yielding a very strong quarter. I know we had some one-time stuff, even if you back that one-time stuff out, I think we had a terrific quarter.
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. 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.