Public Service Enterprise Group Incorporated

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. 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 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, October 31, 2019, and will be available for telephone replay beginning at 1 p.m. Eastern Standard Time today until 1130 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 .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 .pseg.com and our 10-queue 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 discussed non-GAAP operating earnings and -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 material. I'll now turn the call over to Ralph Izzo, Chairman President and Chief Executive Officer of PSEG. Joining Ralph on today's call is Dan Craig, 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 98 cents per share versus 95 cents per share in last year's third quarter. Our GAAP results for the third quarter were 79 cents per share compared with 81 cents 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 nine months of 2018. That is up 3 percent. Regulated operations are on track to contribute approximately 75 percent of total OP earnings for the year and reflect PSEG's ongoing investment in New Jersey's energy infrastructure. Blides six and seven summarize the results for 2019's 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 PSEG's Energy Strong 2 settlement authorizing continued investment in electric and gas system reliability and resiliency improvements over the next four years. We expect to begin the first of these projects in the current quarter, which will continue the important economic engine associated with PSEG's investments in New Jersey's energy infrastructure. We continue to eagerly pursue PSEG's clean energy future filing 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 percent electric and 0.75 percent 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 for utilities, decoupling or lost 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 percent of PSE&G's 13 to 15.5 billion of planned capital investment to the regulated business over the next five years remains intact, as does PSE&G's compound annual growth and rate base of 7.5 to 8.5 percent, starting from the $19 billion level at year end 2018. And now over to PSE&G Power. Power closed on the sale of its 776 megawatt interest in the Keystone and Kahnema generating units during the quarter. The sale continues the elimination of coal from PSE&G Power's fuel mix by mid-2021, when we will retire our only remaining coal unit located at Bridgeport Harbor. In the last five years, PSE&G Power has retired early or sold about 2,400 megawatts of coal fire generation, which has reduced the carbon intensity of what was already a low carbon fleet. In addition, earlier this week, PSE&G exercised an option on Orsted's Ocean Wind Project, resulting in a period of exclusive negotiation for PSE&G to potentially acquire a 25 percent 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 Orsted's experience in developing offshore wind projects in the U.S. and internationally. I'm pleased for the opportunity to apply PSE&G's expertise in developing energy infrastructure in New Jersey to expanding the state's resources of zero carbon generation toward our goal of reducing carbon emissions. And speaking of carbon emissions, PSE&G 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 meaningful action and thoughtful discussion on how to best address climate change. On a related note, I'm pleased to report that PSE&G 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, I'll just shorten that to 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 three voting commissioners on this particular docket, which could happen after November 29th when Commissioner Mike Lick will be eligible to vote on this matter or when the Senate confirms a new commissioner. Given our results through the first nine months of the year, we're narrowing the full year forecast of PSE&G'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 a mid-year re-measurement of the pension plan has raised PSE&G's expected full year results to a range of ,000,000 to ,000,000, up from the utility's original guidance range of $1.2 billion to ,000,000. Weak power prices have affected PSE&G Power's results to a range of ,000,000 to ,000,000, where we've lowered the upper end of its original guidance, which had originally been proposed at ,000,000 to ,000,000. Guidance for enterprise and others is ,000,000 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 the 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, PSE&G 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 -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 nine months of the year, net income was $1.92 per share, up 18 percent 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 1st that lowers pension expense during the second half of 2019. PSE&G's growth and transmission investment added $0.06 per share to -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. Gas margin was $0.03 higher than the prior year quarter, driven by rate relief. Weather was lower by a penny per share compared to the significantly warmer summer experience in 2018. An increase in depreciation and interest expense of a penny 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 penny per share favorable comparison. And changes to post-retirement benefit or OPEB expenses, as well as a split of the pension plan associated with remeasurement of pension expense affected July 1st, 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 penny per share impact. And this effect is 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 lowest 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 one year ago, but nearly 12% higher than a normal summer. Weather normalized sales for the trailing 12 months, which provides a longer-term trending data, remained 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. Our transmission investment includes projects that will replace aging infrastructure with modern equipment, including replacing many of our 26 kV lines to extend 29 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 to 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 nine 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 2019-2023 period, which translates into expected rate-based 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 to a range of ,000,000 to ,000,000, from the original range of $1.2 billion to ,000,000. 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. PSE&G 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-emission certificate revenue earned in the quarter. PSE&G Power closed the sale of its interests in the Keystone Economo coal-fired generating stations during the third quarter, which resulted in a pretax loss of $402 million on the nine months ended September 30th. 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 an impact on PSE&G 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 -to-date period on slides 21 and 22. PSE&G 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 lowered results by 10 cents per share compared with the third quarter of 2018. A full quarter of ZEC revenues contributed 7 cents per share. Recontracting and the impact of lower spark spreads, which reduced results by 5 cents 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 PSE&G Power's operations, total generation output declined by 2 percent to total 16.3 terawatt-hours in the third quarter, reflecting lower market demand and reduced output at Hope Creek, which included a coastdown 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, PCG Power's gas-fired CCGT fleet operated at a capacity factor of 63 percent and produced 7.2 terawatt-hours of output during the third quarter, up by 3 percent over the year-ago quarter, primarily reflecting production from the three new combined-cycle gas turbines at Keys, Seaworn, and Bridgeport Harbor. For the quarter and -to-date periods, PCG Power's nuclear fleet operated at a capacity factor of 91 percent, producing 7.8 terawatt-hours and 23.1 terawatt-hours respectively, representing 53 percent of total fleet generation for the -to-date period. For the -to-date period, generation production volumes increased by 1.9 terawatt-hours to 43.5 terawatt-hours, driven by a higher combined-cycle output of 3.2 terawatt-hours, largely due to the three new units, partially offset by lower nuclear and coal output. This difference in generation reflects the one-month outage extension at Salem 1 in the second quarter for reactor vessel bolt replacements, as well as the decline in Hope Creek's output that I referenced earlier. Lower prices for power and natural gas continue to dampen generation volumes. In addition, the completed sale of PCG Power's interest in the Keystone Economie units will lower forecasted generation volumes by 1.2 terawatt-hours in 2019 and by 5 terawatt-hours in each of 2020 and 2021, and will reflect it in our second quarter 2019 volume updates. PCG Power continued 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 terawatt-hours is hedged at an average price of $37 per megawatt-hour. 2020's forecast output of 52 to 54 terawatt-hours is hedged approximately 85 to 90 percent at an average price of $37 per megawatt-hour. The 2021 PCG Power has hedged 40 to 45 percent 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 Economie during the third quarter of 2019. Park 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 to 420 million versus the original range of 395 to 460 million and have lowered the guidance for PCG Power's non-GAAP adjusted EBITDA to 1 billion to 1 billion 50 million from our original guidance of 1 billion 30 million to 1 billion 130 million. Now I'll briefly address operating results for Enterprise and Other. And for the third quarter, we reported income of 6 million or a penny per share compared to net income of 9 million or 2 cents per share in the third quarter of 2018. And the decrease in net income year over year reflects higher interest expense at the parent, which continues to benefit from ongoing contributions from PCG Long Island. For 2019, the forecast of PCG Enterprise and Other net income has been narrowed from a range of 5 to 10 million to simply 5 million. Our financial position remains strong. PCG 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 PCG Power represented 33% of its capital at the end of the quarter. During the quarter, PSE&G issued $400 million of 30-year secured median term notes at an interest rate of .2% and retired $250 million of maturing 2% median term notes. We continue to expect to fully fund PSE&G's existing 5-year, 13- to $15.5 billion capital investment program over the 2019-2023 period without the need to issue equity. As Ralph mentioned, we've narrowed our forecast of PSE&G'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.

Thank you, 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 star and the number 1 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 your first question. Your first question comes from Julian Smith from Bank of America. Please proceed.

Hey, good morning, team. Hi, Julian. Hey. So a couple 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 fate of the power of business. I know you all, typical practices, talk about media articles per se, but I'm curious, how do 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 investments?

Well, on the fate of the power of business, Julian, I think it's going to be around a while. 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 Kodama, 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.

And

help me out here.

Yeah, I mean, if there's a specific article you're referencing, Julian, 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 KeyCon?

As we've said in the past, Julian, we always are active in the market. We both look to purchase and look to engage with others. Although, candidly, we have made a net zero 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 yeah, we're always engaged in commercial discussions with interested parties. I mean, that doesn't change.

Okay, 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 this 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, the decision to be involved sort of outright in the ownership interest?

Yeah, so we've looked at this industry as best 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, an EIA or NOAA 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, Julian, 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 how to balance that risk of the total project versus the components. But yeah, 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 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.

Yeah. And I think Julian Ralph referenced in his prepared remarks that there are skills that we 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 I think that for that reason, you see an interest in potentially partnering. I think certainly that's that's the case. If you think about the existing solicitation that Orsted won on from a New Jersey standpoint, that all of that is linked. And as we step forward to the extent that things are done on a more differentiated basis, there may be more transmission specific oriented work that could come from.

Excellent. Thank you guys very much.

Your next question comes from Pratha Mehta from City. Please proceed with your question.

Thanks so much. Hi,

guys. Hey,

Pratha.

Hi. So maybe just a little bit more on the offshore wind side. I just want to understand the nature of the agreement. So is the 25 percent ownership reflective of your investment into the transmission or is that a upfront payment of 25 percent to get the 25 percent? 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 would that you know, that option that you have right now, how would that actually play out?

Yeah, I think the way to think about it, Propel, 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 substation on land. So all of those are an indistinguishable project that is it was put forth to New Jersey and was awarded to Orsted. So the 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.

Roger. So you're paying upfront 25 something to get the 25 percent and then as a partner you would put in money to kind of build out that project as approved?

No, 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 percent 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 percent 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, you know, everything's going great. But if you just look at from a, you know, like, for example, 2021 curve perspective, your hedging for the, you know, for the base load generation is down about four dollars 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 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, I said so that's fair, Prof. 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 a 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 a year and a half, two 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 reasonable. They have to replace that with rules. And hopefully they will replace with the rules that meet the two 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 that society appears to value, but the market doesn't price in. The one that's most 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.

Got it. Thanks so much, guys. Really appreciate it.

Our next question comes from Greg Gordon from Evercore. Please proceed.

Thank you. Good morning.

Morning, Gary.

Two questions, not to beat a dead horse on the power side of the house. The willingness to enter into the negotiation with Orsted to take a position in the project itself feels like a bit of an evolution of your thinking. And 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.

Yeah. So Greg, I think it is fair to say 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 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 meet 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 cost risk. But at the end of the day, if if if Orsted 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 if they put wind turbines out there on time and we don't build transmission line in time, how do they get paid? So so these relative risks and returns are all part of the calculation going forward a year from now. But 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 bit more open minded about overall project risk and what what that means for us.

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

Yeah, kind of simple in concept. I think, Greg, we've what we did without changing any of the benefits within the pension. And 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 mid year this year prompted a remeasurement. And so if you think about what year end look like from the standpoint of overall returns and what it looks 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 from where they were at the turn of the year.

OK, great. Thank you, guys.

Yeah. Your next question comes from Christopher Tenure from JP Morgan.

Good morning, guys. I was wondering if you can give us a 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 the CES 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 be probably all we know. 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, a very important role in heating and various other uses in the state and therefore given the housing infrastructure and a building infrastructure that would not immediately lend itself to moving away from 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 be in encouraging electric vehicles, and there seems to be some enthusiasm for that. But every draft we've seen 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. And I mean, clearly the governor's stated his position on the Penn East 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 discussions for the Energy Master Plan so far?

Yes, I think that that conversation in general is not quite as specific in New Jersey as it is in New York when it comes to permitting of specific projects and the ability of 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 a timeframe as 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 to 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 option 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 percent?

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. Okay. Thanks for the call, Ralph.

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.

Okay. Thank you.

Your next question comes from Shar. From Guggenheim Partners. Please proceed.

Hey, hey, good morning, guys. So just a couple of follow ups on the prior questions. You know, 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. Quarks 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?

I mean, I think one thing to think about, Shar, is to the extent that load 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 there's a little bit of a sawtooth from that perspective. And that may be 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, you know, is there any updates there? Can you confirm that? And then, you know, it's your only asset left in New York. So sort of how you're thinking about that exposure. Well,

and I think you're right. And I think that what you're following on to the question actually captures 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. That's 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. That's helpful and thanks, which went to be 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, you know, there's been some sort of negative dialogue from rating agencies. We've seen some downward movement and ratings with some of your peers and 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 is any dialogue right now you've had with the rating agencies and if there's any concerns coming from their end.

Yeah, I mean, sure. 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's 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.

Got it. Thank you. Thanks, guys. Congrats.

Your next question comes from Travis Miller from Morningstar. Please proceed with your question.

Hello. Thank you. Hi Travis. Like your options on options on options, I have a follow on, on follow on, follow on, on the offshore wind here. The 25%, wondering how you're 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 10% or 50%? And what's that capital at risk that you think about?

Yeah, so, so that percentage is based upon the agreement we have with Orsted. 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 Orsted. Yeah. But yes, we do have some expectations of what that 25% amount to in dollars and cents and we'll spend a year making sure that those expectations are as solid as they can 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. And then when you think about that amount of capital that you would put into offshore wind, how do you think about that in terms of bucketing and a return on capital across the two businesses here? The utility, in terms of returns versus putting more capital into the utility versus returns relative to, say, buying back stock or other kind of corporate level or even power. Yeah,

philosophy on that hasn't changed. You know, we view share or purchase 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 a 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 Orstedt has received from the state of New Jersey. It's actually a regulatory order and we like their experience base. So we're 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 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 expectations off of over the utility. And having said that, we're still very much committed to the utility representing over 90% of our capital deployment over the next five 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. Yeah, 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, 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 by in five years from our end, our GSMP, which is 2023 is what we would have felt December of 2023, I think. So we've got four more years before we need to worry about that.

And nothing before that.

Correct.

Okay, great. Thanks so much.

Your next question comes from Paul Patterson from Glen Rock Associates. Please proceed with your question.

Hey, good morning. Good morning, Paul. I have a question about transmission. In the last couple months, we've been seeing, Brooke 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 PJ might think put out a cost containment filing not that long ago that I think you guys have actually filed some stuff on. 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. 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 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'll say today is what we said when FERC Order 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. I think we'd have to raise it FERC and get fixed. Having said all of that, I still believe that FERC Order 1000 was a solution in search of a problem and has created more problems than it has done anything else. We'll 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. This notion is just...FERC would be far better off spending its time figuring out how to fix wholesale tower markets than trying 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, you think?

I think it's too early to say.

Okay. Okay, great. Well, the rest of my questions have been answered. Thanks so much.

Your next question comes from Michael Lapidus from Goldman Sachs. Please proceed with your question.

Hey, 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-based growth and earnings growth at PSE and GE will move in lockstep?

Yeah, so remember, Michael, I think it's about 90 percent. I forget the exact number, and I will know it 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 immodesty I'm going to boast about our employees. They do a great job of controlling O&M. So the anemic low growth we have is enough to help us combat the regulatory lag associated with the 10 percent 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 clause recovery, but candidly it is back end and closer to the rate case test year. So we always have the ability to file for rates 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 utility do a darn good job of making that happen.

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 a dollar amount for that?

Aggregate amount I think was in approximately the 300 million dollar number. It's a year over year jump that's a little bit bigger than the norm though, because if you think about last year, there was some particular tax flow backs 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 give back, which we'll conclude at the end of this year.

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

Yeah. Yeah.

Okay. Thank you guys. Much appreciated.

Thanks,

Michael.

Your next question comes from Paul Fremont from the ZUHO.

Thanks. 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 suffices to say the generator lead, which is a transmission like, it's not regulated, it doesn't get a rate based 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 in someone else's service territory, that the RTEP type of impact in our area would not be something that materially change our capital budget.

Okay. Okay. And then I guess I just wanted to follow up on something that you mentioned earlier, the Ned Zero Pledge. We shouldn't assume, for instance, for Keystone and Conama 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'm not sure I understand your question, but I think the answer is no. In

fact, almost the opposite of what we've said is that we would not be acquiring a fossil driven generation, so that would imply that replacing those would not happen.

Okay. I just wanted to sort of make sure that I understood what you meant by that. Okay. Thank you.

Your final question comes from Sophie Karp from KeyBank. Please proceed with your question.

Hi. Good morning, guys. Thank you for taking my question. Sure. 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 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?

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

All right. So you took down at some point on the Energy Strong 2 decision, you took down a little bit your CapEx plan, and so is that fair to say that you have some headroom there versus your original plan, maybe that you contemplated at the end of the day?

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

Got

it.

Thank you.

Mr. Izzo, Mr. Craig, there are no further questions at this time. Please continue with your presentation. Our 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 status 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.