公共服務電力與天然氣 (PEG) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Sylvia, and I will be your event operator today. I would like to welcome everyone to the Public Service Enterprise Group Third Quarter 2019 Earnings Conference Call and Webcast. (Operator Instructions) As a reminder this conference is being recorded today, October 31, 2019, and will be available for telephone replay beginning at 1:00 p.m. Eastern Standard Time today until 11:30 p.m. Eastern Standard Time on Friday, November 8, 2019. 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, Sylvia. Good morning, and thank you for participating in our Earnings Call.

PSEG's third quarter 2019 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 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 these financial measures and a disclaimer regarding forward-looking statements on our IR website and in today's earnings.

I'll now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of PSEG. Joining Ralph on today's call is Dan Cregg, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Thank you, Carlotta, and thank you all for joining us this morning.

PSEG reported non-GAAP operating earnings for the third quarter of 2019 of $0.98 per share versus $0.95 per share on last year's third quarter.

Our GAAP results for the third quarter were $0.79 per share compared with $0.81 per share in last year's third quarter.

Our results for the third quarter bring non-GAAP operating earnings for the year-to-date to $2.64 per share compared with $2.56 per share for the first 9 months of 2018; that is up 3%.

Regulated operations are on track to contribute approximately 75% of total op earnings for the year and reflect PSE&G's ongoing investment in New Jersey's energy infrastructure.

Slide 6 and 7 summarize the results for 2019 third quarter and year-to-date.

In September, the New Jersey Board of Public Utilities, and I'll refer to them as the BPU, approved PSE&G's Energy Strong II settlement authorizing continued investment in electric and gas system reliability and resiliency improvements over the next 4 years.

We expect to begin the first of these projects in the current quarter, which will continue the important economic engine associated with PSE&G's investments in New Jersey's energy infrastructure.

We continue to eagerly pursue PSE&G's Clean Energy Future filings to bring the benefits of energy efficiency, electric vehicles, energy storage and advanced metering infrastructure, or AMI, at scale to our entire customer base, which is consistent with Governor Murphy's clean energy goals.

Our filing is designed to achieve the 2% electric and 0.75% gas savings contained in the 2018 New Jersey Clean Energy Act. And this represents an order of magnitude increase from the level of spending in our existing energy efficiency program.

In September, the BPU approved the extension of the procedural schedule in the case to March 2020 to provide the opportunity for additional discussions.

We expect that the BPU's review of our energy efficiency proposal and clean energy filing, will be informed by their Energy Master Plan proceedings, which are targeted for conclusion at year-end, and an ongoing energy efficiency stakeholder process, which will continue into 2020.

In parallel, we continue to engage with key stakeholders to develop the supporting policy framework on the role of the utilities, decoupling or loss revenue recovery and key metrics to measure energy efficiency program effectiveness.

Because our energy efficiency proceeding is ongoing, the BPU's review of it will occur prior to those of New Jersey distribution companies that have yet to file their energy efficiency proposals to satisfy the Clean Energy Act requirements.

The PSE&G remains on track to invest $2.7 billion in infrastructure upgrades to its transmission and distribution system this year. The forecast to direct over 90% of PSEG's $13 billion to $15.5 billion of planned capital investment to the regulated business over the next 5 years remains intact, as does PSE&G's compound annual growth and rate base of 7.5% to 8.5% starting from the $19 billion level at year-end 2018.

And now over to PSEG Power. Power closed on the sale of its 776-megawatt interest in the Keystone and Conemaugh generating units during the quarter. The sale continues the elimination of coal from PSEG Power's fuel mix by mid- 2021, when we will retire our only remaining coal unit located at Bridgeport Harbor.

In the last 5 years, PSEG Power has retired early, or sold about 2,400 megawatts of coal-fired generation, which has reduced the carbon intensity of what was already a low-carbon fleet.

In addition, earlier this week, PSEG exercised an option on Ørsted's Ocean Wind project, resulting in a period of exclusive negotiation for PSEG to potentially acquire a 25% equity interest in the project, subject to negotiations toward a joint venture agreement, advanced due diligence and any required regulatory approvals. The Ocean Wind project was the winner of New Jersey's recent offshore wind solicitation and is an important part of Governor Murphy's clean energy agenda.

The project, scheduled to come online in 2024, will be located off the coast of Atlantic City, and will benefit from Ørsted's experience in developing offshore wind projects in the U.S. and internationally.

I'm pleased with the opportunity to apply PSEG's expertise in developing energy infrastructure in New Jersey to expanding the State's resources of 0 carbon generation toward our goal of reducing carbon emissions. And speaking of carbon emissions, PSEG continues to advocate for a national price on carbon. While we understand the significant challenges to advancing climate legislation in the current congress, we recognize the increasing focus on this topic.

So I hope that remarks I made yesterday before the Energy Subcommittee of the House Energy and Commerce Committee will only add to the growing call for meaning action and thoughtful discussion on how to best address climate change. On a related note, I'm pleased to report that PSEG was, again, named to the Dow Jones Sustainability Index North America for the 12th consecutive year.

And one last item, we continue to await a final order from the Federal Energy Regulatory Commission, to shorten that to the FERC, in their effort to reform the PJM capacity auction with the approval of replacement rules. We are optimistic that this will occur once the FERC achieves a quorum of 3 voting commissioners on this particular docket, which could happen after November 29, when Commissioner Glick will be eligible to vote on this matter or when the Senate confirms a new FERC commissioner.

Given our results of the first nine months of the year, we are narrowing the full year forecast of PSEG's non-GAAP operating earnings to $3.20 to $3.30 per share from our original guidance of $3.15 to $3.35 per share. The midpoint of the guidance is unchanged and represents over 4% growth in earnings from the $3.12 per share posted in 2018.

Utility earnings continue to benefit from rate relief and immediate remeasurement of the pension plan has raised PSE&G's expected full year results to a range of $1.225 billion to $1.250 billion, up from the utility's original guidance range of $1.2 billion to $1.230 billion.

Weak power prices have affected PSEG Power's results to a range of $395 million to $420 million, where we've lowered the upper end of its original guidance, which had originally been proposed at $395 million to $460 million.

Guidance for Enterprise and Other is $5 million for the full year.

Thank you to our employees for delivering another solid quarter on the operations front and to recognize the tremendous work that goes into maintaining system reliability and generation availability during this summer.

I'll now turn the call over to Dan for more details on our operating results, and make sure that I'm available for your questions after his remarks.

Excellent. Thank you, Ralph, and good morning, everyone.

As Ralph mentioned, PSEG reported non-GAAP operating earnings for the third quarter of 2019 of $0.98 per share versus $0.95 per share in last year's third quarter. We've provided you with the information on Slide 11 regarding the contribution to non-GAAP operating earnings by business for the quarter; and Slides 12 and 14 contain waterfall charts that will take you through the net changes in non-GAAP operating earnings by major business for the comparable quarter and year-to-date periods versus the prior year.

And now I'll review each company in more detail, starting with PSE&G. PSE&G, as shown on Slide 11, reported net income for the third quarter of 2019 of $0.68 per share compared with $0.54 per share for the third quarter of 2018. For the first 9 months of the year, net income was $1.92 per share, up 18% from the $1.63 per share earned in 2018.

PSE&G's third quarter results were driven by expanded investments in transmission, the settlement of the 2018 distribution rate review and changes to our pension plan that took effect on July 1, that lowers pension expense during the second half of 2019.

PSE&G's growth in transmission investment added $0.06 per share to quarter-over-quarter net income comparisons, including a $0.01 per share positive adjustment for an estimate of the 2019 year-end true up.

Electric margin was $0.03 higher than the year ago quarter, driven by rate relief and higher weather normalized volume. And gas margin was $0.03 higher than the prior year quarter driven by rate relief. Weather was lower by $0.01 per share compared to significantly warmer summer experienced in 2018.

An increase in depreciation and interest expense of $0.01 per share each related to PSE&G's expanded capital base, reduced net income comparisons versus the prior year's third quarter. Lower O&M expense was a $0.01 per share favorable comparison. And changes to post retirement benefit or OPEB expenses as well as the split of the pension plan associated with remeasurement of pension expense effective July 1 had a combined $0.03 per share positive impact on net income compared to the year ago quarter.

The effective tax rate for the quarter, recorded based upon the average annual effective tax rate, resulted in a positive $0.01 per share impact, and this effect was just timing between quarters, it's related to the flowback of excess deferred taxes and it will reverse in the fourth quarter.

The New Jersey economy continues to experience positive growth, evidenced by the low state unemployment rate in the last 20 years. PSE&G reached the 2019 system peak of 9,753 megawatts this past July compared to 2018 system peak of 9,978 megawatts.

The temperature-humidity index, or THI, which is used to measure the impact of summer weather on sales, was 10% lower in the 2019 third quarter than 1 year ago, or nearly 12% higher than a normal summer. Weather-normalized sales for the trailing 12 months, which provides a longer-term trending data, remain relatively flat for electric and was 1% higher for gas. Residential electric and gas customer growth continues to trend higher at approximately 1% per year.

Earlier this month, PSE&G filed with FERC an update to its formula rate for transmission. The annual update is expected to go into effect January 1, 2020, and our transition investment includes projects that will replace aging infrastructure with modern equipment, including replacing many of our 26 KV lines to extend 69 KV power throughout the State. These projects will improve reliability, resiliency, address voltage issues and increase capacity on the system.

After incorporating these investment plans, and reflecting the completion of returning certain excess deferred taxes during 2019, costs for residential customers will increase by approximately 2%. And I should highlight that PSE&G has been proactive in returning tax reform benefits to transmission and distribution customers, which, in total, have lowered rates by over $300 million in 2019.

PSE&G invested approximately $2 billion for the 9 months ended September 30 in electric and gas transmission and distribution capital projects. For the year, PSE&G expects to invest $2.7 billion to enhance reliability and increase resiliency.

PSE&G's projected capital spending range remains at $12 billion to $14.5 billion over the 2019 to 2023 period, which translates into expected rate base growth at a compounded annual rate of 7.5% to 8.5% applied to a $19 billion year-end 2018 rate base.

PSE&G's forecast of net income for 2019 has been updated, the range of $1.225 billion to $1.250 billion from the original range of $1.2 billion to $1.230 billion.

Now moving to power. Power reported non-GAAP operating earnings for the third quarter of $0.29 per share and non-GAAP adjusted EBITDA of $322 million. This compared to non-GAAP operating earnings of $0.39 per share and non-GAAP adjusted EBITDA of $360 million for the third quarter of 2018.

PSEG Power's net income in the third quarter was impacted by a decline in realized energy prices and lower capacity revenues that were partially offset by Zero Emissions Certificate revenue earned in the quarter.

PSEG Power closed the sale of its interest in the Keystone and Conemaugh coal-fired generating stations during the third quarter, which resulted in a pretax loss of $402 million on the 9 months ended September 30.

Non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense, depreciation and amortization expense.

The earnings release and Slide 20 provides you with detailed analysis of the items having impact on PSEG Power's non-GAAP operating earnings relative to net income quarter-over-quarter. And we have also provided you with more details on generation for the quarter and for the year-to-date period on Slides 21 and 22.

PSEG Power's results for the third quarter reflect a full quarter's impact of the expected reduction in capacity revenues in PJM that offset higher capacity revenues in New England from the addition of Bridgeport Harbor 5.

On a net basis, capacity revenues lower results by $0.10 per share compared with the third quarter of 2018. A full quarter of ZEC revenues contributed $0.07 per share. Recontracting and the impact of lower spark spreads, which reduced results by $0.05 per share, were offset by lower cost to serve load resulting in no net impact. This reflects an approximate $3 per megawatt hour decline in the average hedge price compared with the year ago quarter.

Gross margin in the third quarter declined to $31 per megawatt hour from $33 per megawatt hour in the year ago quarter. Power prices and natural gas prices were lower across PJM New York and Maryland despite summer weather that was warmer than normal.

Turning to PSEG Power's operations. Total generation output declined by 2% to total 16.3 terawatt hours in the third quarter, reflecting lower market demand and reduced output at Hope Creek, which included a coast down of that unit into its scheduled fall refueling outage.

We continue to see weaker wholesale energy prices resulting from declines in the price of gas and lower loads, which also limits the dispatch of older, less efficient CCGTs in an increasingly efficient PJM market.

For the third quarter, PSEG Power's gas-fired CCGT fleet operated at a capacity factor of 63% and produced 7.2 terawatts hours of output during the third quarter, up by 3% over the year ago quarter, primarily reflecting production from the 3 new combined cycled gas turbines at Keys, Sewaren and Bridgeport Harbor.

For the quarter and year-to-date periods, PSEG Power's nuclear fleet operated at a capacity factor of 91%, producing 7.8 terawatts hours and 23.1 terawatts hours, respectively, representing 53% of total fleet generation for the year-to-date period.

For the year-to-date period, generation production volumes increased by 1.9 terawatt hours to 43.5 terawatts hours, driven by higher combined cycle output of 3.2 terawatts hours, largely due to the 3 new units, partially offset by lower nuclear and coal output. This difference in generation reflects the 1-month outage extension at Salem 1 in the second quarter for reactor vessel bulk replacements as well as the decline in Hope Creek's output that I referenced earlier.

Lower prices for power and natural gas continues to dampen generation volumes. In addition, the completed sale of PSEG Power's interest in the Keystone and Conemaugh units will lower forecasted generation volumes by 1.2 terawatts hours in 2019, and by 5 terawatts hours in each of 2020 and 2021, and were reflected in our second quarter 2019 volume updates.

PSEG Power continues to forecast full year output for 2019 of 57 to 59 terawatt hours. The remainder of expected production for the year of 13 to 14 terawatts hours is hedged at an average price of $37 per megawatt hour.

2020's forecast to output of 52 to 54 terawatt hours is hedged approximately 85% to 90% at an average price of $37 per megawatt hour. For 2021, PSEG Power has hedged 40% to 45% of forecasted output of 52 to 54 terawatt hours at an average price of $35 per megawatt hour.

The forecast for 2019 to 2021 volumes includes production consistent with current market conditions and reflects the sale of Keystone and Conemaugh during the third quarter of 2019.

Spark spreads in the third quarter were lower than a year ago, reflecting lower power and gas prices across the region. And while our generation volumes approximated last year's levels, the increment we saw in our new combined-cycle unit in Bridgeport was more than offset by reductions across the balance of the portfolio, driven by declines in load across the region.

The impact of these lower prices and volumes as well as locational power price differences between where we generate power and where the load resides, resulted in margin declines at Power versus expectations. And as a result, we've updated our forecast of Power's 2019 non-GAAP operating earnings to $395 million to $420 million versus the original range of $395 million to $460 million, and have lowered the guidance for PSEG Power's non-GAAP adjusted EBITDA to $1 billion to $1.050 billion from our original guidance of $1.030 billion to $1.130 billion.

Now I'll briefly address operating results for Enterprise and Other. And for the third quarter, we reported income of $6 million or $0.01 per share compared to net income of $9 million or $0.02 per share in the third quarter of 2018. And the decrease in net income year-over-year reflects higher interest expense at the parent, continues to benefit from ongoing contributions from PSEG Long Island.

For 2019, the forecast of PSEG Enterprise and Other net income has been narrowed from a range of $5 million to $10 million to simply $5 million.

Our financial position remains strong. PSEG closed the quarter with $120 million of cash on the balance sheet, with debt at the end of September, representing 52% of our consolidated capital. Debt at PSEG Power represented 33% of its capital at the end of the quarter.

During the quarter, PSE&G issued $400 million of 30-year secured medium-term notes at an interest rate of 3.2%, and retired $250 million of maturing 2% medium-term notes.

We continue to expect to fully fund PSEG's existing 5-year $13 billion to $15.5 billion capital investment program over the 2019 to 2023 period without the need to issue equity.

As Ralph mentioned, we've narrowed our forecast of PSEG's non-GAAP operating earnings for the full year to $3.20 to $3.30 per share, keeping the midpoint unchanged.

That concludes my comments. Sylvia, we are now ready to answer questions.

(Operator Instructions) Your first question comes from Julien Dumoulin-Smith from Bank of America.

So couple of questions. First off, just strategically, if you could address some of the media articles out there. We'd be curious on how you think about the state of the power business? And I now, you will -- typical practice isn't to talk about media articles per se, but I'm curious how you think about it strategically, some of the assets there in the future. And to any extent that you do evaluate assets, how do you think about paying down debt versus reinvesting back in the business as evidenced by potentially some of this offshore wind investment, or at least some of the inaugural investment?

Well, on the state of the power business, Julien, I think it's going to be around a while. People -- I'm sorry, I don't mean to be flip, but it seems like electricity is still highly regarded and valued and used by people. And we have a really strong fleet from the point of view of proximity to load and environmental signature. So I think we're quite happy with its cash flow generation and its overall operational performance.

We're always open to the suggestion that others may be able to extract greater value from our assets than we can. And when that's the case, they come talk to us and they suggest commercial terms that we find interesting and that's kind of what's happened with Keystone and Conemaugh as you're well aware. But I'm not quite sure how else to respond to your question.

I mean, we've got a good fleet, they run well, they're financially sound, they're operationally sound and we're always open to commercial discussions with others about whether we can maximize the value or they can maximize the value. Dan, help me out here with?

Yes. I mean, if there's a specific article that you're referencing, Julien, we're not recognizing exactly what it is. But I think Ralph has kind of laid it out.

Or perhaps, if I can frame it this way, should we be thinking about more asset sales following on your first asset sale this quarter with respect to the interest in Key/Con.

As we've said in the past, Julien, we always are active in the market. We both look to purchase and we look to engage with others. Although, candidly, we have made a net 0 pledge that said we will not be building or expanding our fossil fleet in any way that we can envision at this point in time. But yes, we're always engaged in commercial discussions with interested parties, I mean that doesn't change.

Okay. All right. Well, let's move on then. Just quickly if I can pivot to the other side, on offshore wind, if you will. How do you think about the stake versus being involved more narrowly in the transmission side of this business? It seems like potentially a little bit of a pivot in terms of where you all want to be involved. But without the details on our side, how do you think about the risk profile of the decision to be involved sort of outright in the ownership interest?

Yes, sure. So I mean, we've looked at this industry as best as we can and estimates are that there's the potential for up to 80 gigawatts of offshore wind developable along the Eastern United States. Now that's a number that comes out of, I believe, EIA or NOVA report, I forget exactly which, and there's been an announced desire to develop about 35 gigawatts. So there's a potential for growth in this industry.

We are -- we're not experienced in building offshore wind and we have a full year ahead of us in terms of due diligence and further analysis to do. It does appear, Julien, that you're right; that one cannot completely extricate themselves from the risk associated with the timing of the construction. But it's conceivable still that one could protect oneself from the cost associated with the construction. So we're learning as we go along how to balance that risk of the total project versus the components.

But yes, you're not going to be able to build a wire to nowhere and get paid for it. That is an option that isn't available to us. Maybe it's available to others, but I don't think that's the case.

So we're trying to learn in a measured way in an industry that we think is going to continue to grow, and we're pretty proud of the person that is willing to help us learn and do some of the teaching. I mean they're a world leader in offshore wind projects, and we think we know this part of the country fairly well from a permitting point of view, from a market point of view, from a workforce point of view and various other characteristics that matter a lot to a project like this.

Yes. And I think, Julien, Ralph referenced in his prepared remarks that there are skills that we can bring to this kind of a project, but obviously, they are not all of the skills that are needed for this project. So that I think that, for that reason, you see an interest in potentially partnering.

I think, certainly that's the case if you think about the existing solicitation that Ørsted won on -- from a New Jersey standpoint that all of that is linked. And as we step forward, to the extent that the things are done on a more differentiated basis, there may be more transmission specific oriented work that could come from.

Your next question comes from Praful Mehta from Citi.

So maybe just a little bit more on the offshore wind side. Just want to understand the nature of the agreement. So is the 25% ownership reflective of your investment into the transmission? Or is that a upfront payment of 25% to get the 25% and then subsequently, there will be cash outflow to invest in the transmission side? Just if you could give us any color you can on how that option that you have right now, how will that actually play out?

Yes. I think the way to think about it, Praful, is that the solicitation that New Jersey did represented the project as a whole. What I mean by that, it would represent the turbines at sea, it would represent the substation at sea, the line in between and the substation on land. So all of those are an indistinguishable project; that is, it was put forth to New Jersey and was awarded to Ørsted. So the interest would be an interest in that project. What we still have in front of us is the advanced due diligence and the partnership structuring with respect to that type of an investment.

Got you. So you'll pay an upfront 25-something to get the 25% and then, as a partner, you would put in money to kind of build out that project as approved?

Yes. What we have is an opportunity over the ensuing number of months, and Ralph referenced roughly a year's period to make a determination whether or not an interest in 25% of the project is something that we would want to do. So that's currently what we are exploring, but it would be a -- the 25% is not anything immediate, it is more about what the ultimate interest in the project could become.

Fair enough. That's very helpful. And then just on the generation side, I know, Ralph, you mentioned everything is going great, but if you just look at from a -- like, for example, 2021 curve perspective, your hedging for the base load generation is down about $4 a megawatt hour versus last quarter's disclosure. Capacity factors are down and clearly markets are challenging. So just wanted to understand given you've been in this business for so long and kept these assets for so long, is there anything different that needs to be done to kind of better kind of deal with the current market situation, like more retail or anything else that you think would help? Or is the current plan and this current quarter is more of a blip than anything else?

No. That's fair, Praful. I didn't mean to suggest it's going great. I meant to -- what I meant to say is that we're still in a business that is essential and has natural customer segment, namely the whole population. And the particular assets that we're putting to that business are quite strong in terms of where I think our future is headed as a collective society.

Let me be more specific. We tried retail. We couldn't get the scale and the profitability that we wanted. We gave it a good effort for 1.5 years to 2 years and stepped away from that. Clearly, something we need is resolution of the PJM capacity market. If reliability is going to continue to be served from the point of view of supply, then FERC has to do something other than say that the current PJM RPM is not just unreasonable. They have to replace that with rules and hopefully, they will replace with the rules that meet the 2 objectives they've set forth, namely to eliminate price suppression and number two, to allow states to access the resources that they want to.

Another thing that needs to happen is that we need to get a recognition for the attributes of different power plants the society appears to value, but the market doesn't price in. The one that's more glaring is carbon. I think if we can do one or both of those things, then our fleet is extremely well positioned. In the meantime, it continues to generate some healthy positive cash flows for the utility to make use of, but if somebody else can make better use of them, we're willing to listen. Until that time, we're quite happy to run these good assets and await further progress in price formation, further progress on capacity markets and further progress on the pricing of carbon, but your observations are spot on. I did not mean to suggest that sparks had expanded and that everything was fixed in wholesale power market design.

Your next question comes from Greg Gordon from Evercore.

Two questions, not to beat a dead horse on the power side of the house. The willingness to enter into negotiation with Ørsted, to take a position in the project itself, feels like a bit of an evolution of your thinking in that, correct me if I'm wrong, and I may be wrong, the last time we talked about this publicly, you had said that your interests would lie primarily and mainly in building the infrastructure to support that kind of investment, and that you weren't primarily interested in taking direct equity interest in offshore wind. So can you talk about the evolution of your thinking there? And do you think that, that could be, given the quantum of the size of the potential market that you just quoted, a bigger part of your strategic vision going forward? And then I'll switch to -- over to the utility side.

Yes. So Greg, I think it is fair to say that there's been some evolution. I don't know that I would characterize it the way you did, but it definitely is fair to say there's been some evolution. The evolution really is the recognition that whatever one's -- whatever skills one brings to the table and there, there's been no evolution about what our skills are in terms of this particular project, it is an integrated whole. And the project doesn't stand -- it doesn't need its own financial expectations if one side successfully brings their skills to the table and the other side doesn't. And what's most challenging, of course, is how do you extricate yourself from the schedule risk, for example. I mean, there may be ways and we'll explore them every year to protect oneself from the cost risk, but at the end of the day, if Ørsted builds transmission -- if we build transmission online, but turbines aren't there on time, then how on earth does the project succeed and vice versa. If they put wind turbines out there on time and we don't build the transmission line on time, how do they get paid? So these relative risks and returns are all part of the calculation going forward a year from now. But yes, it is fair to say that as we've had further discussions and grown in confidence in the skills and ability of our partner to do this and do this well that we've been a little more open-minded about overall project risk and what that means for us.

My second question is can you just take us into a little more detail on the adjustment you have made on pension and why now? And how that flows to the bottom line to the accretion level that you've articulated?

Yes. Kind of simple in concept, I think, Greg. We've -- what we did without changing any of the benefits within the pension, a split of the pension among the different participants enabled a little bit of volatility to come off of the overall expense. And that all being what it is, one outcropping of that was that, that process during the year, and it was at midyear this year, prompted a remeasurement. And so if you think about what year-end looked like from the standpoint of overall returns and what it looked like from a market recovery, more generally, that remeasurement ended up in kind of a recognition within the overall components of the pension of the fact that markets had come back a little bit, and so that prompted an uptick from the standpoint of overall P&L impact or reduction of expense, increase of income in total from the pension standpoint. So it's really nothing more than the overall management of the pension, in general, but the outcropping of that was a remeasurement, which prompted a lift because market prices had come back from where they were at the turn of the year.

Your next question comes from Christopher Turnure from JP Morgan.

I was wondering if you can give us an update on the Energy Master Plan finalization coming up pretty soon here. Just where are maybe stakeholder discussions around this? And kind of what the impact might be on the CEF and energy efficiency finalization next year?

So Chris, as far as we know, we're still expecting a year-end conclusion to the Master Plan. I'm going to stick with what's been publicly reported because I think that's: a, all we're allowed to say; and b, probably all we know. Namely, there's been some debate over the future of continued use of fossil fuels. There is a desire to decrease that as soon as greatly as possible. There's a recognition that fossil fuels, in particular natural gas, play a very important role in heating and in various other uses in the state, and therefore, given the housing infrastructure and the building infrastructure, that would not immediately lend itself to moving away from natural gas, one has to be reasonable about its continued use.

So it was, I think, just last week that the BPU announced the details for a public review of the plan. And there, they did repeat that it would be available by the end of the year. There's been a little bit of discussion around how aggressive the state should in encouraging electric vehicles and there seems to be some enthusiasm for that. But every draft we're seeing continues to espouse the importance of nuclear, which is important to us. I think those are the issues at a high level that matter and that we've been paying careful attention to.

Okay. I mean, clearly, the governor's stated his position on the PennEast Pipeline, which you're no longer a part of. But is, I guess more broadly, the debate in New York State on gas availability having an impact on the discussion, sort of the Energy Master Plan so far?

Yes, I think that, that conversation, in general, is not quite as specific in New Jersey's as is in New York when it comes to permitting of specific projects and the ability to hookup customers. But that general topic of continued reliance on fossil fuels has made its way into the New Jersey Energy Master Plan. Not in as immediate time frame is my interpretation, given what we're witnessing in New York versus what we're witnessing in New Jersey.

Okay. And then my second question is just a follow-up on the offshore wind announcement from the other day. It looks like you had an option to have exclusive negotiations. Why did you kind of have to do this now if you have a year to make a final decision? Or just what was the impetus behind coming out now as opposed to kind of keeping things going on in the background?

Yes, so the option to have exclusive negotiations required that we decide whether or not we wanted to preserve that option for exclusive negotiations for this next phase. So we chose -- I know it's a little strange. Yes, indeed, it does sound like an option for an option, but that's what we had and we exercised that option. At this point, we have an option to participate where there's no third option to options to option. I'm not just stuttering there, I'm actually articulating something accurately, believe it or not, it's a little frightening.

And with that, you had to specify the 25%.

No, no. That was -- we had an option as to what to specify. We could have gone higher than that, but we chose to focus on entering this space in a more measured way at this point.

And Chris, that, obviously, I mean, as we learn more about the space, that number can be different, right? I mean, we'll keep getting educated.

Your next question comes from Shar Pourreza from Guggenheim Partners.

So just a couple of follow-ups on the prior questions. Just first on the 21 on the power hedges. It looked like it was a bit more of a pronounced downward move in the hedges versus what you guys disclosed in the second quarter. And you only kind of modestly increased your hedges. [Course] and sparks had some strength this quarter for Cal '21. So I'm kind of curious, what drove the downward move, which looks to be a little bit more pronounced than what the dictate markets as you think about second and third quarter? Is there any other regional dynamics that we should be thinking about?

No. I mean, I think, one thing to think about, Shar, is to the extent that low deals are a bigger part of what's included there, you're going to see some of those costs end up coming through because they're offset within the revenue mix. So we tend to see a little bit of an uptick as we go through BGS, which is one of the biggest load contracts that we have. And then as we go through the year, you see a little bit more of a decline. So is it a little bit of saw tooth from that perspective. And that maybe what you're seeing there.

Okay. Got it. And then just on asset sales, Dan, specifically, there's been reports around Bethlehem Energy Center and sort of you marketing the assets. So I'm kind of curious is there updates there? Can you confirm that? And then it's your only asset left in New York, so sort of how you're thinking about that exposure?

Well -- and I think -- so you're right, and I think that what your follow on to the question, actually, encaptures some of that concept as well. It's just a single asset in that area. I would say years ago, there was thought processes around maybe expanding a little further; that did not happen. So we are out and really checking value with respect to that. It is a situation where we will go through the process and make a determination as to whether or not we want to do something based upon what we see coming out of that process.

Got it. Got it. Got it.

Shar, that what I was referring to earlier, about we're always engaged in commercial conversations, but that doesn't necessarily mean that there's any sort of requirement or commitment or decision that's been made on these assets.

Right. No, that's helpful. Just wanted to get a little bit more specific. And then just lastly around sort of the offshore wind ventures. And I know you're taking sort of a proof of concept, kind of dipping your toes in the water, no pun intended. But there's been some sort of negative dialogue from rating agencies. We've seen some downward movement in ratings with some of your peers in certainly around the New England region who have taken a much bigger role in this process. So I'm kind of curious how the conversations are going with the rating agencies, especially as you start to take the step a little bit more forward as proof of concept starts to kick in there and eventually you potentially could take a bigger piece, whether it's transmission or what have you. I'm curious if there's any dialogue right now you've had with the rating agencies. And if there is any concerns coming from their end?

Yes, I mean, Shar, what I would say about that is that, obviously, clearly, we understand that aspect of what you're talking about from the standpoint of current exposure as described by Ralph. Where we are right now is in a situation where we will continue the dialogue into the next number of months into next year to make a determination as to what the ultimate path is going to be. So there is awareness that this is a possibility for us to make that investment. There's an understanding as to the nature of the magnitude -- relative nature, relative magnitude of the investment and it falls into the broader camp of where we are in total and where we come from, from the standpoint of financial strength as well. So it's not something that we're blind to, we're aware of, and as are the rating agencies, but that's part of our overall diligence as we go through the next year or so.

Your next question comes from Travis Miller from Morningstar.

I like your options on options on options, I have a follow-on, on follow-on, on follow-on, on the offshore wind here. The 25%, wondering how you are thinking about that: as a percentage of the project or as a dollar amount? What are your thoughts there? Why not leave it more open to a 10% or 50%? And what's that capital at risk that you think about?

Yes. So that percentage is based upon an agreement we have with Ørsted. And suffice to say, Travis, that we've done some financial analysis that has a total project cost expectation built in, and therefore, a related return. And if during the course of the next year, we find out that the project -- that the 25% dollar value that we expected isn't what the project is promising, then we have the option to not participate at all. So those terms are still being negotiated with Ørsted.

But yes, so we do have some expectations of what that 25% amounts to in dollars and cents and we'll spend a year making sure that those expectations are as solid as they could possibly be and that there isn't some other reality that would cause us to basically walk away. We don't anticipate that. We're in this in good faith and with a fair amount of work done already, but a lot more to be done.

Okay. But then when you think about that amount of capital that you would put into offshore wind, how do you think that -- about that in terms of bucketing, kind of, return on capital across the 2 business here, the utility, just in terms of return versus putting more capital into the utility versus returns relative to, say, buying back stock or other kind of corporate level or even power?

Our philosophy on that hasn't changed. We view share repurchase as value-neutral, that unless there's a dislocation in the market, that the market is accurate, and therefore, one is not creating or destroying value. Now, if the market is out of whack, then you might be able to create value if you purchase at the right time. And then we apply cost of capital to the regulated operations, which is lower than the cost of capital to the unregulated operations. This would be an unregulated operation. So therefore, we have a higher hurdle rate that we subject ourselves to because of the greater risk.

When we compare it to the Power business writ large, I would say that we are trading off merchant risk for some operational risk. We just don't know the offshore wind business as well as we know the nuclear business and the combined cycle business, but we like the contract that Ørsted has received from the State of New Jersey. It's actually a regulatory order and we like their experience base. So we are comfortable enough at this point to enter into this option agreement that says that trade-off of commercial risk versus operational risk with this partner is worth taking. And over the course of the next year, we have to turn that into even greater comfort as a result of the diligence that needs to be done. But yes, that was a lengthy speech, but the answer is, it is -- the return expectations on offshore wind would exceed the return on expectations off of the utility. Having said that, we are still very much committed to the utility representing over 90% of our capital deployment over the next 5 years. And Dan and the finance team have done a great job of making sure that all of these things are possible within the investment potential of the enterprise.

Got it. Yes, that's helpful then. And just real quick on the utility side. I know you guys just got through, obviously, a big rate case. But given the spending plan and what's on the table in terms of Energy Master Plan and other possible separate outside of general rate case, what is your thinking on timing of a general rate case?

So we have a requirement to go and buy in 5 years from our GSMP, which is 2023, is what we would have thought, December of 2023, I think. So we've got 4 more years before we need to worry about that.

And nothing before that?

Correct.

Your next question comes from Paul Patterson from Glenrock Associates.

I have a question about transmission. In the last couple of months, we've been seeing FERC put out a few orders, trying to expand, I guess, competition or voice concern about competition not being in the specific areas of transmission development. And also PJM, I think, put out a cost containment filing not that long ago and I think you guys have actually filed some stuff. And I'm just thinking when you look at these actions, how do you think about the potential impact on you guys if it's possible? I know that there are a variety of orders and it's -- I mean, I'm not asking for any granularity here, I guess, but what the potential impact might be in terms of transmission development from your perspective if these things come to pass as I guess initially filed?

So I think what you're referring to, Paul, is an attempt by others, and maybe even FERC, to breathe some life into FERC Order No. 1000, which I have been an outspoken critic of in terms of the tremendous cost and administrative burden it has imposed upon customers in exchange for very, very little benefit in terms of creative and valuable solutions to transmission reliability issues.

What I'd -- what I'll say today is what we said when FERC Order No. 1000 first came out, which is to the extent it potentially introduces competition to our own service territory and projects that we would embark upon, then we would make ourselves available to other territories where we would be allowed to compete.

Now as long as that is, indeed, a level playing field across RTOs, I kind of like our skill sets and our ability to compete. To the extent that other RTOs don't make it as open a playing field as perhaps PJM might, then that would be an issue we'd have to raise at FERC and get fixed.

Having said all of that, I still believe that FERC Order No. 1000 was a solution in search of a problem and has created more problems than it has done anything else. So we will continue to try to point that out to FERC through actual cases where administrative costs and burdens have exceeded overall project costs in certain jurisdictions. And this notion is just -- FERC would be far better off spending its time figuring out how to fix wholesale power markets than try to fix something that isn't broken, namely transmission construction.

Okay. I hear you there. Any sense as to how some of these might -- or is it just, I guess, too early to say maybe how some of these things might fall out, do you think?

I think it's too early to say, Paul.

Your next question comes from Michael Lapides from Goldman Sachs.

Ralph, very basic question. First of all, how are you thinking about -- now that you're a few quarters behind the rate case or after the rate case, how are you thinking about the impact of regulatory lag in the coming years and whether you think rate base growth and earnings growth at PSE&G will move in lockstep?

Yes. So remember, Michael, I think it's about 90%. I forget the exact number, and I will know by the time we get to EEI, I'll do some more studying of our -- CapEx does get contemporaneous return. At the risk of some immodesty -- actually, there's no modesty, I'm going to boast about our employees. They do a great job of controlling O&M. So the anemic loan growth we have is enough to help us combat the regulatory lag associated with the 10% that doesn't get contemporaneous return. It isn't enough to make up for all of it. And our clauses do have some back-end CapEx that does not get closed recovery, but candidly, it is back-end and closer to the rate case test here. So we always have the ability to file for rate sooner if we needed to if the lag became too much. But believe me, all hands on deck are focused on earning our allowed return and quite candidly, Dave Daly and the team at the utilities are doing a darn good job of making that happen, so.

And Michael, the other thing to remember as well is that the transmission side of the business has a formula rate filing, which is through contemporaneous as well.

Right. And can you remind us what is the formula rate increase in transmission for 2020 for -- starting in January 2020? What's the dollar amount for that?

Aggregate amount, I think was in at approximately the $300 million number. It's a year-over-year jump, so it's a little bit bigger than the norm, though, because if you think about last year, there were some particular tax flowbacks, which are not there. So from a year-over-year standpoint, it's a little bit higher than the norm because of the absence of that giveback, which would have all concluded at the end of this year.

Got it. So roughly $300 million step up from 2019 to 2020?

Yes. Yes.

Your next question comes from Paul Fremont from Mizuho.

If you were not to take an equity interest in the offshore wind project, can you give us an idea of how much capital spending would be involved to connect up the project on your side?

So Paul, I don't think any analysis has been done yet on what the land impacts are of the project. It's suffice to say the generator lead, which is a transmission like, it's not FERC regulated, it doesn't get a rate base treatment, would be much bigger than any kind of on-land adjustments that need to be made. And it's probably not unreasonable to assume that given that this lead would connect into someone else's service territory, that the ARTEP-type of impact in our area would not be something that would materially change our capital budget.

Okay. And then, I guess, I just wanted to follow-up on something that you guys - that you mentioned earlier, the net 0 pledge. We shouldn't assume, for instance, for Keystone and Conemaugh that you're looking to replace that capacity? And if you were to dispose of, let's say, Bethlehem, you wouldn't be looking to sort of replace that? Or would you?

No, I don't -- I'm not 100% sure I understand your question, but I think the answer to that is no. But…

And in fact, almost the opposite, what we've said is that we would not be acquiring fossil-driven generation. So that would imply that replacing those would not have.

Your final question comes from Sophie Karp from KeyBanc.

I just wanted to go real quick back to the offshore wind and if you were to take a 25% stake in that project. I'm presuming that would be a sizable chunk of cash involved eventually in it and as an investment. So how should we think about your kind of CapEx plan evolving? And when would we get updates on that as well as how you plan to fund it as far as debt and equity mix, et cetera?

Yes. So I think the way to think about that is we've been talking about a time frame over the next number of months and do a year to make an ultimate determination as to the investment that we may make, and I think that's the right time frame to think about some of those incremental details.

Right. And so you took down -- at some point on the Energy Strong II decision, you took down a little bit your CapEx plan. And so is it fair to say that you have some headroom there versus your original planning that you contemplated at the Analyst Day?

Yes. I think that's a fair way to think about it.

Mr. Izzo and Mr. Craig, there are no further questions at this time. Please continue with your presentation or closing remarks.

Thanks, everyone, for joining us today. Lots of questions about offshore wind; I guess that wasn't a big surprise. But the real message we want to make sure we leave you with is that we continue with just extremely steady performance. We're on track to deliver on everything we've told you about earlier in the year and have been telling you about for many years. Customer sat as solid. We're preserving our financial strength. This is giving us the opportunity to pursue some expanded Clean Energy Future opportunities, and those are everything from the Clean Energy Future filing, that is still very much alive and being discussed with the BPU and offshore wind, which we've now exercised the option to pursue an option. So that's really where we want to leave you.

I wish you all a happy Halloween. Have a safe and enjoyable holiday. And we look forward to seeing you in about 10 days in Florida. Thanks, everyone, for joining us on the call.

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