Public Service Enterprise Group Incorporated (PEG) Q2 2018 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Lebay and I’m your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group Second Quarter 2018 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded Wednesday, August 1, 2018 and will be available for telephone replay beginning at 1 O'clock P.M. Eastern Time today until 11:30 P.M. Eastern Time on Thursday, August 9, 2018. 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 Kathleen. Please go ahead.

Thank you, Lebay. Good morning, everyone and thank you for participating in our earnings call. Earlier today PSEG released earning statements for the second quarter of 2018. These materials including the release, financial attachments and accompanying slides detailing operating results by companies are posted on the IR website at investor.pseg.com. Our 10-Q for the period ended June 30 has been filed with the SEC. The earnings release and other matters we will discuss 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. Reconciliations of our non-GAAP financial measures and a disclaimer regarding forward-looking statements are posted on our IR website and are included in today's live and in our earnings release. I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on the call is Dan Craig, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Ralph.

Thank you, Kathleen. And thank you everyone for joining us today. PSEG reported net income for the quarter of $0.53 per share versus $0.22 in the second quarter of 2017. We also reported non-GAAP operating earnings of $0.64 per share versus $0.62 in the last year's second quarter. Non-GAAP operating earnings for the second quarter rose 3% compared with the year ago period, reflecting continued strong performance at PSE&G and effective cost control and the lower corporate tax rate at PSEG power. Solid results for the quarter bringing non-GAAP operating earnings for the first half of 2018 to $1.61 per share. A 4,5% increase over non-GAAP operating earnings of $1.54 per share earned in 2017’s first half. For the first half of 2018, we have made substantial progress meeting our objectives for the full year. On slide 6 and 7, we summarize the results for the quarter and the first half of 2018. At PSE&G earnings increased by $0.05 per share up 12% over second quarter 2017 results. The continued investment in PSE&G transmission and distribution programs was the primary driver of earnings growth for the quarter and year-to-date periods. PSE&G has made over $3 billion in electrical gas infrastructure investments in the past 12 months. Including, increased distribution spending, as we continuously strive to upgrade New Jersey’s aging infrastructure and to maintain high levels of customer reliability and achieve high customer satisfaction scores. PSE&G reached many significant milestones during the second quarter. Successfully executing on its capital programs. PSE&G recently finished construction of the third and final phase of the $1.2 billion, 345kv Bergen-Linden Corridor or BLC as refer to it. This project improve the liability, was one of the larger and more complex projects we have built and was finished safely on time and on budget. At the completion of the BLC line, our transmission project portfolio will focus on our 69kv system upgrade program, enhance the storm hardening, as well as lifecycle replacement to maintain reliability, increase good resilience and modernize aging plant. Turning to our ongoing distribution programs. PSE&G is completing the first phase of its Gas System Modernization Program, what we will refer to as GSMP. And this is replaced approximately 500 miles of gas mains in the last three years. We will begin the work on GSMP II in 2019. This next phase, a five year $1.9 billion program was recently approved by the New Jersey Board of Public Utilities and will enable us to replace an additional 875 miles of aging gas mains. In early June PSE&G filed for an extension of its energy strong infrastructure program, or ES II with the BPU. The key components of the $2.5 billion five year program are outlined for you on slide 17. The request this progressing at the BPU will enable us to continue investments to hardness our system against storms, replace aging or end-of-life infrastructure. And incorporated advance technology to improve grid management. PSE&G’s pending distribution base rate cases proceeding according to the schedule, including our early stage settlement meetings with the parties held in July, which will continue until August. We public hearings across the state were recently completed in the early July, and in the next week we will file a scheduled update with financial data for the full test year ended June 30th. We also expect the BPU staff and others to file their initial testimony in the coming weeks. As a reminder, in the absence of the settlement, we have the ability to self implement interim rates this November, consistent with regulations issued by the BPU last December. The BPU recently released their investigating report conducted in response to the multiple March 2018 Nor’easters that left many customers throughout the state without power. PSENG is reviewing the BPU’s report and its recommendations for improving storm response protocols, to ensure that our procedures are continually aligned with industry best practices. Among the BPUs recommendation, each utility is to submit within 180 days, of plan with an accompanying cost benefit analysis. So the implementation of Advance Metering Infrastructure, or AMI, focusing on the use and benefits of AMI for the purpose of reducing the number of customer outages as well as outage durations during a major storm event. Also as we discussed during our recent investor conference this past May, New Jersey Governor Murphy signed infill law clean energy legislation which adopts significant new standards for energy efficiency and the use of renewable energy. PSE&G plans to submit our Clean Energy Future or CEF filing. A $2.9 billion six year proposal align with New Jersey's energy policy goals that details a broad range of planned investments in energy efficiency, electric vehicle infrastructure and battery storage. The CES program sets targets for energy efficiency savings for electric and gas usage in a cost efficient manager broadly benefit our customers by helping to lower bills and better management energy uses. PSE&G's focus remains on providing customers enhanced reliability, a resilient system supported by green energy and bills that are affordable. We look forward to making this filing in the near-term supporting the state’s energy policy goals and bringing value to our customers. New Jersey's legislation enabling Zero Emission Certificate or ZEC was also signed into law by Governor Murphy in May. The legislation closer to BPU within 230 days to establish a process for ZEC's including determining eligibility and certification of need. And ultimately selecting nuclear plants to receive ZEC's starting in April 2019. The BPU will remain nuclear plant applicants based on considerations that include fuel diversity, air quality, and other environmental attributes. PSEG Power estimates that if all three of its New Jersey, nuclear units are selected, it could be eligible to receive ZEC revenues of approximately $200 million per year. PSEG Power placed into service the keys Energy Center and fee warrant seven combined cycle unit. Adding 1,300 megawatts of clean efficient gas fired generating capacity. Construction activities are ongoing at Bridgeport Harbor 5 which we expect to bring online mid 2019. Once Bridgeport Harbors is in service, it will complete reconfiguration powers merchant generation fleet that will improve its competitiveness in the marketplace. In June of 2018, Federal Energy Regulatory Commission issued an or refining a PJMs current capacity market is unjust and unreasonable because it allows resources supported by out of market payments to suppress capacity prices. FERK established a new proceeding to address an alternative approach in which PJM would one, modify its minimum offer price rule, so that it would apply some new and existing resources that receive out of market payments, regardless of resource type. And two, establish an option that will allow on a resource specific basis. Resources receiving out of markets support to be removed from the PJM capacity market along with the commencement amount as load for some period of time. We are participating in this proceeding and we will continue advocating for policies at the Federal level to correct flaws in wholesale markets design that suppress prices. While striving to obtain adequate recognition of the value that fuel diversity brings to a secure, resilient and well functioning electric grid. We expect that the growth prospects or PSE&G, the reconfiguration about merchant generating fleet and successful execution of our policy initiatives will allow PSEG to extend its track record of delivering value for our customers and growth for our shareholders. We intend to maintain our strong balance sheet and credit metrics that enable us to fund PSEG's projected capital investment program of $14 billion to $17 billion over the 2018 to 2022 period without the need to issue equity and continue providing shareholders with the opportunity for consistent and sustainable dividend growth. Our non-GAAP operating earnings for the first half of 2018 are supportive of our outlook for the full year and we are maintaining our full year guidance for 2018 non-GAAP operating earnings of $3 to $3.20 per share. With that, I will turn the call over to Dan, who will discuss our financials in greater detail and then we will join Dan at the end of the call for your questions.

Thank you Ralph and thanks everybody for joining us today. As Ralph said PSEG reported non-GAAP operating earnings for the second quarter of 2018 of $0.64 per share versus non-GAAP operating earnings of $0.62 per share in the last year, second quarter. A reconciliation of non-GAAP operating earnings to net income for the quarter can be found on slide six. We have also provided you with a waterfall chart on Slide 11 that takes you through the net changes in quarter-over-quarter non-GAAP operating earnings by major business and a similar chart on Slide 13 that provides you with the changes in non-GAAP operating earnings by each business, for the first half of 2018. I will now review each Company in more detail starting with PSE&G. PSE&G reported net income of $231 million or $0.46 per share for the second quarter of 2018 compared with net income of $208 million or $0.41 per share for the second quarter of 2017. Results for the quarter is shown on Slide 15. PSE&G’s second quarter results reflect continued successful execution of our infrastructure, investment programs and ongoing control of operating expenses. Growth in PSE&G’s investment in transmission improved second quarter net income comparisons by $0.03 per share. Revenue recovery of investments made to enhance system resiliency under the energy strong and gases to modernization programs drove improved margin in second quarter net income comparisons by $0.02 per share. Distribution O&M savings added a $0.01 per share over the second quarter of 2017 results. Changes to the accounting treatment of the non-service component of pension and OPEB expenses resulted in a favorable $0.02 per share comparison over 2017 second quarter. Partially offsetting the favorable margin items, were higher expenses related to depreciation interest in taxes that had a combined impact of $0.03 compared to 2017 second quarter. As a reminder, transmission revenues are adjusted each year based on the Company's investment program. PSE&G’s investment in transmission is expected to grow to approximately $8.6 of rate base at the end of 2018 or 45% of the Company's year-end consolidated rate base. Under Energy Strong, electric rates are adjusted twice during the year in March and September, and gas rates are adjusted each year in September. Under the Gas System Modernization Program, gas rates which are now adjusted each year in January to reflecting investment made during the prior year will move to a semiannual recovery schedule when we begin the GSMP II program in 2019. The combined annual revenue increase from 2018 over 2017 from both the Energy Strong and GSNP programs is forecast to be approximately $53 million. Economic Indicators for New Jersey continue to be generally positive, supported by gains in employment and housing data. Quarterly gas sales were higher influenced by cold April temperatures. On a trailing 12 month basis, which provides longer term trending data, weather normalized electric sales were relatively flat, while gas sales were 2.7% higher, led by demand from the commercial sector. Residential electric and gas customer growth continues to try and higher at approximately 1% per year and our forecast to PSE&G's net income for 2018 is unchanged at a $1 billion to $1,30 billion. Now let's turn to Power. PSEG Power reported net income for the quarter of $41 million or $0.08 per share, compared with a net loss of $97 million and $0.19 per share for the second quarter of 2017. 2017 included incremental depreciation and other expenses related for last June's retirement, Hudson and Mercer coal-fired generating stations. Non-GAAP operating earnings for the second quarter of 2018 was $0.16 per share, compared to $0.19 per share in 2017. And non-GAAP adjusted EBITDA for the second quarter of 2018 was $210 million compared to $261 million in 2017. And non-GAAP adjusted EBITDA excludes the same items as our non-GAAP operating earnings measure as well as income tax expense, interest expense and depreciation and amortization. The earnings release and Slide 21 provide you with a detailed analysis of the impact on Power's non-GAAP operating earnings quarter-over-quarter. And we have also provided you with generations statistics for the quarter and for the first half of the year, on Slide 22 and 23. Power's non-GAAP results for the second quarter 2018 reflect the impact of lower market prices on re-contracting of our hedges which reduced operating earnings by $0.08 per share. Power experienced a $6 per megawatt hour decline and its average hedged energy price during the second quarter and this is consistent with our expectations for the full year. Lower volumes of $0.01 per share and higher O&M of $0.02 per share reflect the impact of Power so [quickly healing] (Ph) outage compared to the year ago outage of our 57% hometown sailing unit. An increasing capacity prices in PJM and New England, starting on June 1st improved quarter-over-quarter results by $0.03 per share and higher gas spend out as a result of cold April temperatures added a penny per share. The decline and depreciation expense related to the Hudson and Mercer coal requirements together with lower interest expense and a lower corporate income tax rate combined to improve quarterly comparisons by $0.04 for the quarter. Now let's turn to Power's operations. Generation output defined by 5% compared with the second quarter of 2017, reflecting the plan refueling outage and Hope Creek and other scheduled maintenance. Power's gas fired combined cycle fleet operated at an average capacity factor of 46% and produced 3.5 terawatt hours of output during the second quarter 2018, down by 11% over the years ago quarter reflecting outages and lower market demand. PJM coal generation output remain constant at 1.4 terawatt hours and operated at an 81% capacity factor in the quarter. And for the year-to-date period Power's nuclear fleet operated at an average capacity factor of 92.9%, producing 15.8 terawatt hours and representing 63% of Power's total generation. Gas prices were flat year-over-year and an improvement of Power prices is offset by lower market demand. Power has adjusted its forecast for expected 2018 through 2020 output to reflect current market conditions and now expects 2018 output of 53 to 55 terawatt hours, 2019 output of 57 59 terawatt hours and 2020 output of 62 to 64 terawatt hours down slightly from our earlier forecast volumes of 55 to 57 terawatt hours for 2018, 59 to 61 terawatt hours for 2019 and 63 to 65 terawatt hours for 2020. An update of Power’s hedge position is provided on Slide 25. For the remainder of 2018 Power has hedged 90% to 95% of total forecasted production of 28 to 30 terawatt hours, at an average price of $38 per megawatt hour. For 2019, Power has hedged 65% to 70% of forecasted production at 57 to 59 terawatt hours, at an average price of $37 per megawatt hour. And for 2020, Power had hedged 35% to 40% of output, forecasted to be at 62% to 64% terawatt hours, at an average price of $36 a megawatt hour. Earlier this year in July, the State of New Jersey made changes to its income tax laws, including imposing a temporary sure tax on corporate taxable income of 2.5% effective January 1, 2018 through 2019 and declining to 1.5% in 2020 and 2021. The surcharge provides an exemption for public utilities and as such, PSE&G will not be impacted by this change. But for the full year 2018, the tax surcharge is expected to have a modest negative impact on results of Power and to a lesser extent on enterprise and other as each begins to accrue the surcharge, starting July 1 2018. Our forecasts of Power’s full year 2018 non-GAAP operating earnings and non-GAAP adjusted EBITDA, remains unchanged at $485 million to $560 million and a $1,75 million to $1,180 million respectively. Now, let me turn to PSEG enterprise and other which reported a net loss of 3 million or a penny per share for the second quarter of 2018, compared to a net loss of $2 million for the second quarter of 2017. Non-GAAP operating earnings for the second quarter of 2018 were $11 million or $0.02 per share, representing no change versus the second quarter of 2017. The net loss for the second quarter of 2018 includes a pre-tax charge of $20 million related to the ongoing liquidity challenges facing Energy Rina, compared to a similar pre-tax charge of $22 million in the year ago quarter. Results this quarter also reflect higher parent interest expense offset by the lower federal tax rate at PSEG and ongoing contributions from our PSEG Long Island contract. For 2018, the forecast of PCEG enterprise and other non-GAAP operating earnings remains unchanged at $35 million. And I would like to take a moment just to recap our 2018 to 2022 capital spending plan of $14 billion to $18 billion, with approximately 90% directed to regulated growth initiatives at PSE&G. As we detailed in our investor day presentation in May, PSE&G’s five year $12 billion to $15.5 billion capital spending program supports our expected compound annual growth and rate base of 8% to 10% over the 2018 to 2022 period. The recent five year expansion of GSMP II at an approximately $1.9 billion is incorporated into the lower end of the spending and growth range at an average annual spend of approximately $350 million to $400 million which is an increase over GSMP I of approximately $75 million per year beginning in 2019. The upper end of the range as the full investment positions contained in our pending $2.5 billion Energy Strong II program. And our anticipated $2.9 billion dollar clean energy future program. That when combined, total approximately $3.5 billion through 2022. The timeframes for both Energy Strong II and our Clean Energy Future program extend beyond the 2022 horizon. So the tail end of both programs is beyond PSE&G’s 2018 to 2022 capital spending window. PSEG’s financial position remains strong. Powers free cash flow is expected to improve in 2018 with a decline in capital spending following the completion of construction at [Keys in C1] (Ph) And overall respect and improvement of PSEG's cash flow in 2018 versus 2017. PSEG closed the quarter ended June 30, 2018 with $95 million of cash on its balance sheet and debt representing 50% of consolidated capital. Power's that at the end of the quarter represented 34% of its capitalization, providing a debt to EBITDA ratio of 2.7 times at the midpoint of Power's 2018 non-GAAP adjusted EBITDA forecasts. And well within Power's solid investment grade credit metrics. And I will know that it May Standard & Poor's a firm the credit ratings of PSEG, PSE&G, PSEG Power retaining each rating outlook at stable. We continue to expect the Power's improving cash flow beginning in the second half of 2018 will be directed to supporting regulated growth investments. PSEG continues to expect no new equity to fund our current capital spending program over the 2018 to 2022 timeframe and we stand firm on our commitment to providing our shareholders with the opportunity for consistent and sustainable dividend growth that has averaged nearly 5% annually over the last few years. As Ralph mentioned, we are maintaining our forecasts and non-GAAP operating earnings for full year of $3 to $3.20 per share. And Lebay we are now ready to take some questions.

Thank you so much. Ladies and gentlemen, we will now begin the question-and-answer session for members of the financial community. [Operator Instructions] Your first question comes from the line of Julien Dumoulin Smith from Bank of America. Please proceed with your question.

Hey, good morning. This is actually [Claire] (Ph) hopping in for Julien here.

Hi, Claire.

Hi. Thank you for taking my questions here. So I appreciate the update on the rate case settlement negotiations. Just if you could provide a little more color on maybe progress on some of the critical issues and just anymore color you can get there?

Claire, it's really difficult to reveal the details of the negotiation publicly. That doesn't seem fair to the other parties. But there is a bunch of issues that we had resolved even prior to this discussion in terms of storm costs and recovery of that. But we are under confidentiality agreement with the other parties to not discussed in negotiations at this point. I think we just stick with what we said in the script that what we are engaging in dialogue, it's been constructive. Summer vacations are now interfering a little bit. And at the end of the day, everything is on schedule and we always have recourse to interim rates and nine months after filing date of January. So as much as I would like to share with you we do have these confidentiality limitations.

Yes, from a schedule standpoint we will provide the latest update as we step through times. So [indiscernible] I will be will be submitted on the 8th of August and things are moving according to schedule.

Just to reminder that our ask is a net of attached give back a 1% rate increase and we will still be 20% below where rates were and are less rate case even if we got 100% of our ask.

Got it and appreciate the confidentiality aspect. Well, in that case, my second question here is probably could you give a little more color on how you see in this survey the BTU complaints on transmission cost - allocation and cost inflation and how you might address that?

Sure. Well, first of all, let's make sure everybody understands that the issue is who pays not whether we get paid, right. So PSE&G will get fully compensated for its transmission investments as per our transmission rates and there has been some back and forth between who the beneficiaries are of things like the artificial islands, fidelity improvements, [indiscernible] and its impact on the New York ISO teams. And we have been working with the BPU to obviously as advocate for a fair treatment of New Jersey customers. So we are completely aligned in what we want to see happen there. So, we obviously had a couple of, not the best outcomes from New Jersey perspective at FERC recently, but there is no gap between what we want and what the New Jersey BPU wants. And again, I will end where I started, which is, there is no issue in terms of a shareholder recovery of what has been invested.

Got It. Could you give possibly one more color on some of the discussions at PJM to lower transmission costs or if there is anything could be always there.

Yes, I mean I think that there is two types of transmission projects that PJM has presented stuff that comes out of the ARCH, regional transmission expansion program that is generated by PJM and then there were additional non ARCH projects that have more of a local reliability component. So with that the company generate and there has been a movement at PJM which we have been supportive of to make the visibility of the justification for those projects more consistent with each other that hasn't been the case always in the past, primarily because the ARCH projects are bigger. So if you have one $750 million project like [indiscernible], you can understand why you would want to treat that different than 10. $75 million projects, like a 69 kv upgrade. But recognizing that customers and load serving entities and suppliers and all of the stakeholders at PJM have the right information, PJM has been moving towards a path of greater and greater upfront disclosure. We just have to make sure that we don't get to a point where diminishing returns where literally the eight figure project is or the seven figure project is getting the same amount of upfront time and disclosure that the nine and 10 figure projects demand that averages kind of the whole process.

Great, thank you.

Thank you so much. Next question comes from the line of Praful Mehta, from Citi Group. Please proceed with your question.

Thanks so much. Hi guys. So Ralph I wanted to get your view on the total capacity reform and the FERC proposal. It sounds like if you are going to remove both demand and supply from the capacity market it probably has a negative impact or at least not a positive impact on capacity prices. So first you want to get your view on that. And secondly what does that mean for resources that are getting support like zero emission credits. Does that mean they have to go the state to kind of get that refund for the capacity that they lost? Just some color, that would really appreciated.

Sure, Praful. So, I don’t think I’m being Pollyannaish when I say that I’m quite optimistic about what could come out of this. Although we don't know what will come out of this. And let me explain why this. Its first of all, let's level set the calendar right now. Borrowing in an unusual action by FERC to claw back prior RPM options. For the next three years, we know what our financial situation is right. We have three auctions that took place and those capacity prices are set and it's by no means coincidental that the first phase of the ZEC program in New Jersey, will coincide that we deliberately talked about three year horizons for the ZEC program, because of the visibility and capacity prices and fairly high visibility of energy prices will not deterministic way capacity question. So for three years, I think where we understand our financial situation pretty well, providers are New Jersey units are indeed selected from the ZEC payments which I don't want to presume to be the case. Now let's take a look at what FERC has said the reason for doing what they are doing. Number one, they said that they want to allow states flexibility and choosing their own resources. Well, when you get 60 out of 80 votes in this assembly and 20 out of 40 votes in the Senate and the governor signed the bill, you got it you got to feel pretty good at this state wanting to support its nuclear plants. And whether that is through and FR or some other mechanism, I have a very high degree of confidence that the state recognizes the energy, capacity and environmental attributes about nuclear plants. Now the devils of the details was to how that will be actually designed and recovered. But again, from a policy point of view, that feels pretty good to me. And then when you think about who brought the complaint and why they brought the complaint. The claim is that out of market payments which by the way is not limited to ZEC's, it's [REC's] (Ph) it's regulated generation in the market today that these out of market payments were serving to suppress capacity crisis. So if the goal is to correct for that, I feel pretty good about what that means for our powerful units. So somewhere between the goals and Ralph is feeling good about the goals and getting the details right is a fair amount of work to chop extensively over the next four months by January 9th, which has all sorts of other probations that are associated with in terms of how many FERC commissioners are there, who is filing for rehearing, who isn’t filing for reach hearing, et cetera, et cetera. So I don't want to suggest that there isn't uncertainty, but there is clearly. But I think if you hold on to the stated goals to eliminate price depression for the things that are receiving out of market payments, check that box for a powerful units. And number two, allow states to support those resources that they want support, check that box for our nuclear units. There is no other boxes for us to check. So, that is where I come out of [indiscernible] right now again, for the third time, we are actively engaged in the details of how one achieve that. And that is the part that no one is able to predict at this point. Dan, I don’t know if you want to add to that.

No, I mean, just the only other thing I would add, if you think about the mechanics of it as well, properly, you talk about taking out the load and taking a generation, there is a reserve aspect that that would come with the load and how that gets worked through would also have an effect. But that would service if it was megawatt-for-megawatt loading generation, you absolutely would have the effect you are talking about to the extent that reserves are going to turn any kind of FRR alternative into a smaller version of what you are seeing in the market, meaning to it be with reserves. You would have a lesser impact or maybe no impact, based upon how that mass would work.

And not to solve the problem here. But if the removed supply is a small subsets then presumably the reserve margin needed for that smaller market would have to be comparable if not higher than what you have 160,000 megawatt 13 state region so.

That is super helpful color. I mean and almost the depth of your answers also suggest the work the trough here and as you said, do you think that it can get done in January time frame or do you think this is kind of going to take more time?

Instinctively, I would say probably will take more time, but I don't want to second guess the FERC and their stated schedule, but yes, I mean we would be kidding ourselves if history wasn't some sort of feature about how long these things take on something as complicated as this.

Got you. Thanks so much guys.

You are welcome.

Thank you so much. And your next question comes from the line of Jonathan Arnold from Deutsche Bank. Please proceed with your question.

Good morning guys. A question on, I just curious what at the Analyst Day Ralph you said that you would on the CEF filling, it already held the 30 day pre-filing and that was kind of ready to go and, you slides today say later in the year, I think you said in the near-term but either way it seems to have been held off a little bit. Can you give us any color on why that is?

Sure Jonathan. It’s very simple. We have got a wonderful opportunity here with Governor Murphy's passion for the types of things that are in that filing and we just want to work very closely with the front office in terms of policy alignment and you may or may not be aware of this, but June 30th is the end of the fiscal year for New Jersey. So until June 30th arrived it’s just impossible think of anything, but statewide budget conversations right. So even though Energy is important, it doesn't step in front of the state budget. So then you run into vacations. It's really just a question of being completely in sync with the policy of the administration and having a couple of things step in front of us for that, but nothing more than that. I would be surprised if it's much delayed at this point. Once we get some people back from vacation for just further detail.

What you are saying seems to imply might it might involve a little bit versus what you share with us.

The program elements. I mean, we are determined to go in with this dollar amount. If anything this interesting, BTU comment on the importance of AMI for outage restoration could affect what we submit and that obviously would have the effect if anything, increases somewhat as opposed to decreasing.

That is what I was going to ask, do you have an [indiscernible] could feel what a full deployment would costs and it sounds like you are saying that would be incremental rather than displacing something else…

No, you are correct. It would be incremental, rather I give that Jonathan that number Jonathan because we are just starting that conversation with BTU staff and rather not have them here for the first time in one of your reports. Even though they, they will written in wonderful reports.

But, to the point of incremental instead of what is the…

I would think, it would be more incremental.

We don't want it to take away from the other side.

Okay.

From a dollar amount standpoint as well, Jonathan. If you look at the spend that has been identified that we have been talking about that does align with the EE savings objectives that are laid out within the legislation, so that should hold fairly steady to get the savings that we need and having the spend that we have talked about.

Okay. Than just a one other topic if I may. Dan you mentioned the forecast output Power. I'm just curious if you could give us a little more color behind the -- why the changes in 2019 and 2020?

Yes. I think Jonathan it’s a little bit of what we are seeing from a market demand perspective right now, and also a little bit related to whether or not the units are running through the night, and whether there is some [indiscernible] that is going on. So just, they moved from time-to-time and they remain estimates. And as we step through 2019 and 2020, we will continue to keep an eye on it. But the early indications now is that there is a little bit more downward pressure than up. So we are just providing that from the standpoint of our forecasts that output.

Okay. Thank you.

Thank you so much. And your next question comes from the line of Gregory Gordon from Evercore. Please proceed with your question.

Hey, good morning. Actually uncertainty upon uncertainty but in addition to the 206 remains the capacity market and the Power markets are as was sort of first articulated in the last answer to the last question pretty low and more upon pricing lies but we have got this fast start pricing decision pending. There also seems to be a continued desire or on the part of PJM leadership to address the overall pricing model from an energy perspective. So it seemed to me that the revenue model for Power does have a lot of uncertainty on both size of the equation capacity and energy? But it would seem to me that they are both bias to the upside, but I don't want - rather than bias or answer I would like to hear what you think about the momentum for energy price for form as well both fast-start? And if a momentum can be reestablished on the [indiscernible] reform?

Yes. So, I think what we are hearing is a fast-start chain and should be implemented as beginning of 2019 and then the broader inflexible unit aspects of price formation, PJM is committed to filing something at the end of this year. So I would agree with you Greg. My sense and this is not - it’s just that is that there has been enough delays in false-starts that it's hard to believe that either or both of those are fully baked into the full price curve at this point. So that would suggest that there is more upside I mean if the fast-start unit as lots of surprise, that is a good thing right and inflexible units fast-start surprise that is a good thing. But, I would be less than wholly accurate if I didn't say that when we last met at EEI I thought that it would happen around this time. At least PJM was saying we are not there yet. So there has got to be some degree of discounting going on and the full price curve. But we don't have just the full price preview, we do have a range of changing that we allow ourselves to gravitate up or down within some boundaries, but so short answer is yes, I would agree. There is some upside, but the delays of the past fully account where I think some of the steps moving that might not the fully price this into the forward curve.

Okay. Thank you Ralph. Have a good day.

Thank you so much. And your next question comes from line of Steve Fleishman from Wolfe Research. Your line is now open.

Hi, Ralph. Good morning. So just a try and get a better understanding scenarios from the FERC structure. Like what you said, you kind have a protection for non-subsidize generation and a path for subsidize generation. I guess the only issue would be you would I assume need to get a new legislative structure then if you just - no it can be done with the current one?

Yes, well I think yes, of course it depends what FREC says, but we have every reason to believe that the state could designate resource requirements that for example, legislation right now that is been signed by the Governor saying was 40% of its energy to come from nuclear plants. So that legislation exists. There is a real brand new legislation that exists in terms of renewable portfolio standard. So the approach we would think it could work is that the BPU would simply say that based upon that statutory authority using a couple of mechanisms that we have already started talking about what I would rather not go into detail here. It could be purely done through regulation without any need for additional legislation, fully supportive of the 3,500 megawatts of nuclear, 1400 megawatts of solar and whatever the headcounts. We have running around out there right now, which I’m not go into details.

Okay. so the fact that there was a $300 million cap on the ZEC is not relevant for that aspect.

It isn’t right because the ZEC was not a payment for Energy or Capacity, the ZEC was the payment for fuel diversity and environmental attributes. So to supply the load in New Jersey there has to be an Energy and the Capacity payment and that is wholly separate from the ZEC payment. That is, that was abundantly clear in the legislation and…

Okay. And then just, I am just curious if in trying to figure out this whole picture, if you heard any updates on potential DOE fuel stability plan and just where that might be and how that fit into this.

I had not - one could conclude that if price suppression is eliminated that could solve DOE’s concern about other units that are suffering from that price depression becoming viable again. But that is really an extrapolation that you would have to judge for yourself. The DOE issue has been out there for a while now, there is a resiliency technical workshop going on at FERC, I think there was a meeting yesterday if I'm not mistaken or two days ago, but I don't have any other information than what you probably have already read in the press.

And then just on the AMI big picture program you mentioned. When we are going to - what be the date for when will get an update on that?

So if we file it with the Clean Energy filing, it would literally be within a couple of weeks. If not also maybe a month or two. If it's done separately, that could be a little longer data that could still into the end of this year.

Okay. Thank you.

You are welcome.

Thank you so much. And your next question comes from the line of Paul Patterson from Glenrock. Your line is now open.

Good morning guys. So just sort of a follow up on this capacity. It seems to me that if I understand thoughtful and - question, your answer like it seems to me that if I understand you correctly, you expect to see some additional form of mitigation measures to address the impact of essentially disrupt self supply for our specific resource alternatives. Is that Correct? And am I understanding that correctly?

Yes, that is right Paul. So what we understand, and FERC has said and its second step of the process was that, okay states if you want to assure your own resource adequately consisting of various components, then you can do that. And we will let you remove them from the market as well as the load associated with that. And I think we are profitably we are talking about is that, that second half of that sense is well, what is the load associated with that, right. So if resource adequacy and a 168,000 megawatt market is 16% or 15.8%, what is an adequate reserve margin when the market is 3000 megawatts. Is it higher, is it lower, I would argue it's much higher, because if you lose one nuclear unit out of 3000, you got q big problem. So maybe resource adequacy then. You have got, you are only taking your reserve margin needs to be 35%, I'm making stuff up here with us. So, the state wants that nuclear unit, it's painful environmental attributes, it's going to collect an energy price in the PJM market, it's and going to set a capacity price, presumably through a market proxy, that RPM would be agree duplicate for. And then it's going to leave behind a lot more load and it took out. And a lot less supply, then it's took out. Well that works nicely for the residual market. We just have to make sure that everyone else sees it that way.

At a minimum, if you do have that hypothetical situation that Ralph just talks about and as a shortfall with respect to the load in the resources that we are thinking out, what is going to happen is that that load is going to rely upon the balance of the market and the reserve that sits within the balance of that market. So a very strong reserve within the balance of that market is going to so the benefit of the low that was taken out for an FRR. So absent some kind of ability to ensure that that is compensated for there is a bit of a free rider issue. So logically tell you that there should be a reserve that is going to be appropriate for the smaller amount of load just come out.

I hear you. That really hasn't been done with regulated assets, right? I mean, we don't see that I mean PJMs, IRM has been done throughout the footprints or regional specific area, it doesn't seem like they said, okay, this union is co-op that they have - right I mean, that is why it seems a little novel to me, I mean I understand the logic and - but I appreciate that that will be interesting to see how it all works out. Just an energy [indiscernible]. How much motive we have last year? What is the net investment after all this?

For the [indiscernible] there is an aggregate total of $20 million. So and those are the more acute areas. So there is very little that remains in that results.

Okay. So we are pretty much finished all I think.

We do, I mean, we'll see what happens. Ultimately, there could be some timing aspects to the extent that that there is a process that goes forward within a bankruptcy scenario. There could be a write down in the aggregate to be followed at a later date by a recovery in the aggregate. So from the accounting conservative standpoint, you could see more down before there is a recovery. And it could be separated as opposed to that. That would be the other element that I would point out.

Okay. Great. Thanks so much.

Sure.

Thank you so much. [Operator Instructions] Mr. Cregg, there are no further questions at this time, so please continue with your presentation and closing remarks.

Right yes, so thank you all for joining us, I know that Dan and [indiscernible] will be on the road next week, if I’m not mistaken and then for sure we will see everyone at EEI in San Francisco in November and once again we are pleased with where we are in terms of Power portfolio and the construction of the new units going into service and the ongoing growth, the utility with no shortage of opportunities, that continue to surface, the strength of the balance sheet and security of the dividend and look forward to seeing you on the road in San Francisco. Thanks everyone.

Ladies and gentlemen, this does conclude the conference call for today. You may now disconnect and thank you for participating.