Ladies and gentlemen, thank you for standing by. My name is Lee Wei 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. 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.
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 Carlotta Chan. Please go ahead.
Thank you, Liwei. Good morning, everyone, and thank you for participating in our earnings call. Earlier today, PSEG released earnings statements for the Q2 of 2018. These materials, including the release, financial attachments and accompanying slides detailing operating results by company 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 slides 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 At the conclusion of their remarks, there will be time for your questions. Ralph? Thank you, Carlotta,
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 Q2 of 2017. We also reported non GAAP operating earnings of $0.64 per share versus $0.62 in last year's Q2. Non GAAP operating earnings for the 2nd quarter rose 3% compared with the year ago period, reflecting continued strong performance at PSE and G and effective cost control and the lower corporate tax rate at PSEG Power. Solid results for the quarter bring non GAAP operating earnings for the first half of twenty eighteen to $1.61 per share, a 4.5% increase over non GAAP operating earnings of $1.54 per share earned in 20 seventeen's first half.
For the first half of twenty eighteen, we have made substantial progress in meeting our objectives for the full year. On Slide 6 and 7, we summarize the results for the quarter and the first half of twenty eighteen. At PSE and G, earnings increased by 0 point per share, up 12% over Q2 2017 results. Continued investment in PSE and G's transmission and distribution programs was the primary driver of earnings growth for the quarter and year to date periods. PSE and G has made over $3,000,000,000 in electric and gas infrastructure investments in the past 12 months, including increased distribution spending continuously strive to upgrade New Jersey's aging infrastructure and to maintain high levels of customer reliability and achieve high customer satisfaction scores.
PSE and G reached many significant milestones during the Q2, successfully executing on its capital programs. PSE and G recently finished construction of the 3rd and final phase of the $1,200,000,000 345 kV Bergen Linder corridor or BLC as we refer to it. This project improved reliability was one of the larger and more complex projects we have built and was finished safely on time and on budget. After completion of the VLC line, our transmission project portfolio will focus on our 69 kV system upgrade program, enhanced storm hardening as well as lifecycle replacement to maintain reliability, increase grid resilience and modernize aging plant. Turning to our ongoing distribution programs.
PSE and G is completing the first phase of its gas system modernization program or what we refer to as GSMP. And this has replaced approximately 500 miles of gas mains in the last 3 years. We will begin work on GSMP II in 2019. This next phase, a 5 year $1,900,000,000 program was recently approved by the New Jersey Board of Public Utilities and will enable us to replace an additional 8 75 miles of aging gas mains. In early June PSE and G filed for an extension of its Energy Strong Infrastructure Program or ES2 with the BPU.
The key components of the 2,500,000,000 dollars 5 year program are outlined for you on Slide 17. The request is progressing at the BPU and will enable us to continue investments to harden our system against storms, replace aging or end of life infrastructure and incorporate advanced technology to improve grid management. PSE and G's pending distribution based rate case is proceeding according to the schedule, including early stage settlement meetings with the parties held in July, which will continue into August. 3 public hearings across the state were recently completed in early July. In the next week, we will file a scheduled update with financial data for the full test year ended June 30.
We also expect the BPU staff and others to file their initial testimony in the coming weeks. As a reminder, in the absence of a 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 investigative report conducted in response to the multiple March 2018 nor'easters that left many customers throughout the state without power. PSE and G 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 BPU's recommendations, each utility is to submit within 180 days a plan with an accompanying cost benefit analysis for the implementation of advanced 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 into law clean energy future or CES filing a $2,900,000,000 6 year proposal aligned 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 CEF program sets targets for energy efficiency savings for electric and gas usage in a cost efficient manner to broadly benefit our customers by helping to lower bills and better manage energy use. PSE and 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 0 emission certificates or ZECs was also signed into law by Governor Murphy in May.
The legislation calls to the BPU within 3 30 days to establish a process for ZECs including determining eligibility and certification of need and ultimately selecting nuclear plants to receive ZECs starting in April 2019. The BPU will rank 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 nuclear of its New Jersey nuclear units are selected, it could be eligible to receive ZEC revenues of approximately $200,000,000 per year. PSEG Power placed into service the Keyes Energy Center and Sewaren's 7 combined cycle units, adding 1300 megawatts of clean efficient gas fired generating capacity. Construction activities are ongoing at Bridgeport Harbor 5, which we expect to bring online mid-twenty 19.
Once Bridgeport Harbor is in service, it will complete a reconfiguration of Power's merchant generation fleet that will improve its competitiveness in the marketplace. In June of 2018, the Federal Energy Regulatory Commission issued an order finding that PJM's current capacity market is unjust and unreasonable because it allows resources supported by out of market payments to suppress capacity prices. FERC established a new proceeding to address an alternative approach in which PJM would 1, modify its minimum offer price rule so that it would apply to new and existing resources that receive out of market payments regardless of resource type and 2, establish an option that would allow on specific basis resources receiving out of market support to be removed from the PGM capacity market along with a commensurate amount of load for some period of time. We are participating in this proceeding and will continue advocating for policies at the federal level to correct flaws in wholesale market 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 for PSE and G, the reconfiguration of our 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 $14,000,000,000 to $17,000,000,000 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 twenty 18 are supportive of our outlook for the full year, and we are maintaining our full year guidance for 20 eighteen's non GAAP operating earnings of $3 to $3.20 per share. With that, I'll turn the call over to Dan, who will discuss our financial in greater detail and then we'll 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 Q2 of 2018 of $0.64 per share versus non GAAP operating earnings of $0.62 per share in last year's Q2. And a reconciliation of non GAAP operating earnings to net income for the quarter can be found on slide 6. We've 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 twenty eighteen. I will now review each company in more detail, starting with PSE and G.
PSE and G reported net income of $231,000,000 or $0.46 per share for the Q2 of 2018 compared with net income of $208,000,000 or $0.41 per share for the Q2 of 2017. Results for the quarter are shown on slide 15. PSE and G's 2nd quarter results reflect continued successful execution of our infrastructure investment programs and ongoing control of operating expenses. Growth in PSE and G's investment in transmission improved 2nd quarter net income comparisons by $0.03 per share. Revenue recovery of investments made to enhance system resiliency under the Energy Strong and Gas System Modernization programs drove improved margin and 2nd quarter net income comparisons by $0.02 per share.
Distribution O and M savings added $0.01 per share over the Q2 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 Q2. Partially offsetting the favorable margin items were higher expenses related to depreciation, interest and taxes that had a combined impact of $0.03 compared to 20 seventeen's Q2. As a reminder, transmission revenues are adjusted each year based on the company's investment program. PSE and G's investment in transmission is expected to grow to approximately $8,600,000,000 of rate base at the end of 2018 or 45% of the company's year end consolidated rate base.
Under Energy Strong, electric rates were adjusted twice during the year in March September and gas rates were adjusted each year in September. Under the gas system modernization program, gas rates, which are now adjusted each year in January to reflect the investment made during the prior year, we'll move to a semi annual recovery schedule when we begin the GSMP II program in 2019. The combined annual revenue increase in 2018 over 20 17 from both the Energy Strong and GSMP programs is forecast to be approximately $53,000,000 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 trend higher at approximately 1% per year. And our forecast of PSE and G's net income for 20 18 is unchanged at $1,000,000,000 to $1,030,000,000 Now let's turn to Power. PSEG Power reported net income for the quarter of $41,000,000 or $0.08 per share compared with a net loss of $97,000,000 or $0.19 per share for the Q2 of 2017. 2017 included incremental depreciation and other expenses related to last June's retirement of the Hudson and Mercer Coal Fired Generating Stations. Non GAAP operating earnings for the Q2 of 2018 were $0.16 per share compared to $0.19 per share in 2017 and non GAAP adjusted EBITDA for the Q2 of 2018 was $210,000,000 compared to $261,000,000 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've also provided you with generation statistics for the quarter and for the first half of the year on slides 2223. Power's non GAAP results for the Q2 of 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 in its average hedged energy price during the Q2 and this is consistent with our expectations for the full year.
Lower volumes of $0.01 per share and higher O and M of $0.02 per share reflect the impact of Power's Hope Creek refueling outage compared to the year ago outage of our 57% owned Salem unit. An increase in capacity prices in both PJM and New England starting on June 1st improved quarter over quarter results by $0.03 per share and higher gas send out as a result of cold April temperatures added a penny per share. The decline in depreciation expense related to the Hudson 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 declined by 5% compared with the Q2 of 2017, reflecting the planned refueling outage at Hope Creek and other scheduled maintenance.
Power's gas fired combined cycle fleet operated at an average capacity factor 46% and produced 3.5 terawatt hours of output during the Q2 of 2018, down by 11% over the year ago quarter, reflecting outages and lower market demand. PGM coal generation output remained 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 factor of 92.9 percent producing 15.8 terawatt hours and representing 63% of Power's total generation. Gas prices were flat year over year and an improvement in power prices was offset by lower market demand. Power has adjusted its forecast 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 terawatt hours to 59 terawatt hours and 2020 output of 62 terawatt hours to 64 terawatt hours, down slightly from our earlier forecast volumes of 55 terawatt to 57 terawatt hours for 2018, 59 terawatt hours to 61 terawatt hours for 2019 and 63 terawatt to 65 terawatt hours for 2020.
An updated 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 terawatt hours to 30 terawatt hours at an average price of $38 per megawatt hour. For 2019, Tower has had 65% to 70% of forecasted production of 50 7 terawatt to 59 terawatt hours at an average price of $37 per megawatt hour. And for 2020, power has 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 surtax on corporate taxable income of 2.5% effective January 1, 2018 through 2019 and declining to 1.5% in 2020 2021.
The surcharge provides an exemption for public utilities and as such PSE and 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 at Power and to a lesser extent on Enterprise and Other as each begins to accrue the surcharge starting July 1, 2018. Our forecast of Power's full year 2018 and non GAAP adjusted EBITDA remains unchanged at $485,000,000 to $560,000,000 and $1,075,000,000 to 1,180, respectively. Now let me turn to PSEG Enterprise and Other, which reported a net loss of $3,000,000 or a penny per share for the Q2 of 2018 compared to a net loss of $2,000,000 for the Q2 of 2017. Non GAAP operating earnings for the Q2 of 2018 were 11,000,000 dollars or $0.02 per share, representing no change versus the Q2 of 2017.
The net loss for the Q2 of 2018 includes a pre tax charge of $20,000,000 related to the ongoing liquidity challenges facing NRG RIMA compared to a similar pre tax charge of $22,000,000 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 PSEG Enterprise and other non GAAP operating earnings remains unchanged at 35,000,000 dollars Now I'd like to take a moment just to recap our 2018 to 2022 capital spending plan of $14,000,000,000 to $18,000,000,000 with approximately 90% directed to regulated growth initiatives at PSE and G. As we detailed in our Investor Day presentation in May, PSE and G's 5 year $12,000,000,000 to $15,500,000,000 capital spending program supports our expected compound annual growth in rate base of 8% to 10% over the 2018 to 2022 period. The recent 5 year extension of GSMP 2 at an approximately $1,900,000,000 is incorporated into the lower end of the spending and growth range at an average annual spend of approximately $350,000,000 to $400,000,000 which is an increase over GS and P1 of approximately $75,000,000 per year beginning in 2019.
The upper end of the range adds the full investment positions contained in our pending $2,500,000,000 Energy Strong II program and our anticipated $2,900,000,000 Clean Energy Future program that when combined total approximately $3,500,000,000 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 and G's 2018 to 2022 capital spending window. PCG's financial position remains strong. Power's free cash flow is expected to improve in 2018 with the decline in capital spending following the completion of construction at Keyes and Seawarn.
And overall, we expect an improvement in PSEG's cash flow in 2018 versus 2017. PSEG closed the quarter ended June 30, 2018 with $95,000,000 of cash on its balance sheet and debt representing 50% of consolidated capital. Power's debt at the end of the quarter represented 34% of its capitalization, providing a debt to equity debt to EBITDA ratio of 2.7 times at the midpoint of Power's 2018 non GAAP adjusted EBITDA forecast and well within Power's solid investment grade credit metrics. And I would note that in May Standard and Poor's affirmed the credit ratings of PSEG, PSE and G and PSEG Power retaining each rating outlook at stable. We continue to expect that Power's improving cash flow beginning in the second half of twenty eighteen will be directed to supporting regulated growth investments.
PCG continues to expect no new equity to fund our current capital spending program over the 2018 to 2022 timeframe. And we stand firm in 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're maintaining our forecast of non GAAP operating earnings for the full year of $3 to $3.20 per share. And Leeway, 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. Your first question comes from the line of Joanne Tomlin Smith from Bank of America. Please proceed with your question.
Hey, good morning. This is actually Claire subbing in for Julien here.
Hi, Claire.
Hey, thank you for taking my questions here. So, I appreciate the update on the rate case settlement negotiations. Just if you could really
difficult
really difficult to reveal the details of a negotiation publicly. That doesn't seem fair to the other parties. But there's a bunch of issues that we had resolved even prior to this discussion in terms of storm costs and recovery of that. We are under a confidentiality agreement with the other parties to not discuss the negotiations
at this
point. I think we just stick with what we said in the script that that we're engaged in the dialogue. It's been constructive. Some of 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 9 months after the filing date of January.
So as much as I'd like to share with you we do have these confidentiality limitations.
From a schedule standpoint, we'll provide the latest update as we step through time. So the 12.0 will be submitted on the 8th August and things are moving according to schedule.
Got it. Just a reminder that our ask is net of the tax giveback of 1% rate increase and we'll still be 20% below where rates were in our last rate case even if we got 100% of our ask.
Got it. I appreciate the confidentiality aspect. Well, in that case, my second question here is broadly, could you give a little more color on how you see New Jersey, the BPU's 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 and G will get fully compensated for investments as per our FERC transmission rates. And there has been some back and forth between who the beneficiaries are of things like the artificial island stability improvement, the Bergen Linden Carter and its impact on the New York ISO seems. And we have been working with the BPU to obviously 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 of outcomes from a New Jersey perspective at FERC recently, but there's no gap between what we want and what the New Jersey BPU wants. And again, I'll end where I started, which is there's no issue in terms of shareholder recovery of what's been invested.
Got it. Could you give possibly a little more color on some of the discussions at PJM to lower transmission costs or if there's anything you can reveal at this time there?
Yes. No, I mean, I think that there's 2 types of transmission projects that PGM has presented to it, there's stuff that comes out of the RTEP, the regional transmission expansion program and that is generated by PJM. And then there are additional non RCAP projects that have more of a local reliability component to it that the companies generate. And there's been a movement at PJM which we've 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 RCAP projects are bigger.
So if you have $750,000,000 project like a Susquehanna Roseland, you can understand why you want to treat that different than $10,000,000 $75,000,000 projects like a 69 kV upgrade. But recognizing that customers and load serving entities and suppliers and all of the stakeholders of PGIM have a right to information. PGIM has been moving towards the path of greater and greater upfront disclosure. We just have to make sure that we don't get to the point where we're diminishing returns, where literally the 8 figure project is where the 7 figure project is getting the same amount of upfront time and disclosure that the 9 and 10 figure projects demanded because that would just parallelize the whole process.
Great. Thank you.
Thank you so much. And your next question comes from the line of Praful Mehta from Citigroup. Please proceed with your question.
Thanks so much. Hi, guys.
Hi, Prava.
Hi. So Ralph, wanted to get your view on the total capacity reform and the FERC proposal. It sounds like if you're 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 firstly, wanted to get your view on that. And secondly, what does that mean for resources that are getting support like 0 emission credits?
Does that mean they have to go to the state to kind of get that refund for the capacity that they lost? Just some color on that would be 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. Let me explain why. First of all, let's level set the calendar right now. Barring an unusual action by FERC to claw back prior RPM auctions.
For the next 3 years, we know what our financial situation is, right. We have 3 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 with that, right. We deliberately talked about 3 year horizons for the ZEC program because of the visibility of capacity prices and the fairly high visibility of energy prices although not deterministic the way capacity prices are. So for 3 years, I think we understand our financial situation pretty well provided our New Jersey units are indeed selected for 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 is the reason for doing what they're doing. Number 1, they said that they want to allow state flexibility in choosing their own resources. Well, when you get 60 out of 80 votes in assembly and 28 out of 40 votes in the Senate and a governor who signs the bill, you got to feel pretty good about this state wanting to support its nuclear plants. And whether that's through an FRR or some other mechanism, I have a very high degree of confidence that the state recognizes the energy, capacity and environmental attributes of our nuclear plants. Now the devil is in the details as 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 ZECs, it's ZECs, it's REX, it's regulated generation in the market today that these out of market payments we're serving to suppress capacity prices. So if the goal is to correct for that, I feel pretty good about what that means for our fossil units. So somewhere between the goals and Ralph is still feeling good about the goals and getting the details right is a fair amount of wood to chop ostensibly over the next 4 months by January 9, which has all sorts of other perturbations that are associated with it in terms of how many FERC commissioners are there, who's filing for rehearing, who isn't filing for rehearing, etcetera, etcetera. 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 suppression for the things that aren't receiving out of market payments, check that box for our fossil units. And number 2, allow states to support those resources if they want to support, check that box for our nuclear units. There's no other boxes for us to check. So that's where I come at and proffle that now again for the 3rd time. We are actively engaged in the details of how one achieves that and that's 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 talked about taking out the load and taking out the generation. There's a reserve aspect that would come with the load and how that gets worked through would also have an effect. But that would serve if it was megawatt for megawatt load and generation, you absolutely would have the effect you're talking about to the extent that reserves are going to turn any kind of an FRR alternative into a smaller version of what you're seeing in the market, meaning it would be with reserves, you would have a lesser impact or maybe no impact based upon how that math would work.
And not to solve the problem here, but if the removed supply is a small subset then presumably the reserve margin needed for that smaller market would have to be comparable if not higher than what you have for 100 and 68,000 megawatt 13 state regions.
Yes, that's super helpful color. I mean almost the depth of your answers also suggest the wood to chop here. And as you've said, do you really think that it can get done in that January timeframe or do you think this is kind of going to take more time?
Instinctively I'd say probably will take more time, but I don't want to second guess the FERC and the stated schedule. But yes, I mean we'd be kidding ourselves if history wasn't some sort of teacher about how long these things take on something as complicated as this.
Got you. Thanks so much guys.
Welcome.
Thank you so much. And your next question comes from the line of Jonathan Arnold from Deutsche Bank.
A question on I was just curious what's at the Analyst Day, Rob, you'd said that you'd on the CEF filing, you'd already held the 30 day pre filing and that it was kind of ready to go. And your slides today say later in the year, I think you said in the near term, but either way it seems to have been held up a little bit. Can you give us any color on why that is?
Sure, Jonathan. It's very simple. We've 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 30 is the end of the fiscal year for New Jersey.
So until June 30th arrived, it's just impossible to 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 look at the details.
What you're saying seems to imply it might evolve a little bit versus what you showed us, is that a fair?
The program elements, but I wouldn't expect I mean, we are determined to go in with this dollar amount. If anything, this interest thing BPU comment on the importance of AMI for outage restoration could affect what we submit and that obviously would have the effect to if anything increase it somewhat as opposed to decrease it.
That's what I was going to ask actually is, do you have an early feel of what a full deployment would cost and it sounds like you're saying that would be incremental rather than displacing something else, but I don't want to put words.
It would be no, you're correct. It would be incremental. I'd rather not give that number, Jonathan, because we're just starting that conversation with BPU staff. Rather than have them hear it for the first time in one of your reports, even though they're well written and wonderful reports. Okay.
But
to the point of incremental or go report sort of instead of what's the?
I would think it'd be more incremental. Yes, no, no, no. We don't want it to take away from the other stuff.
Okay. From a dollar amount standpoint as well, Jonathan, if you look at the spend that's been identified and 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've talked
about. Okay, thanks. Just one other topic if I may. Dan, you mentioned the lower forecast for output at power. Just curious if you could give us a little more color behind why the changes in 2019 2020?
I think, Jonathan, it's a little bit
of what we're 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's some duct firing that's going on. So just they move from time to time and they remain estimates. Step through 2019 2020, we'll continue to keep an eye on it. But the early indications now is that there's a little bit more downward pressure than up. We're just providing that from the standpoint of our forecasted output.
Thank you so much. And your next question comes from the line of Greg Gordon from Evercore. Please proceed with your question.
Hey, good morning.
Good morning, Greg.
Not to layer uncertainty upon uncertainty, but in addition to the 206 related to the capacity market, the power markets are as was sort of articulated in the last last question, pretty low and more about pricing wise, but we've got this fast start pricing decision pending. There also seems to be a continued desire on the part of PJM leadership to address the overall pricing model from an energy perspective. So it would seem to me that the revenue model for power does have a lot of uncertainty on both sides of the equation, capacity and energy. But it would seem to me that they're both biased to the upside, but I don't want to rather than bias your answer, I'd like to hear what you think about the momentum for energy price reform as well, both fast start and if the momentum can be reestablished on overall price reform?
Yes. So I think what we're hearing is that fast start can and should be implemented 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's been enough delays and false starts that it's hard to believe that either or both of those are fully baked into the forward price curve at this point.
So that would suggest that there is more upside. I mean if a fast start unit is allowed to set price that's a good thing, right. And if an inflexible unit allows us to set price that's a good thing. But I would be less than wholly accurate if I didn't say that when we less met at EEI I thought that it would happen around this time, at least that's what PGM was saying and yet we're not there yet. So there's got to be some degree of discounting going on in the forward price curve.
But we don't out guess the forward price curve here. We do have a range of hedging that we allow ourselves to gravitate up or down within some boundaries. But so short answer yes, I would agree there is some upside, but the delays of the past fully account for I think some of the skepticism that might not have fully priced this into the forward curve.
Thank you, Ralph. Have a good day.
Thank you so much. And your next question comes from the line of Stephen Fleishman from Wolfe Research. Your line is now open.
Yes. Hi, Ralph. Good morning. So just on the just to kind of get a better understand of scenarios from the FERC structure. I get what you say that you kind of have a protection for non subsidized generation and a path for subsidized generation.
I guess the only issue would be you would I assume need to get a new legislative structure then
if this
now they can be done within the current one?
Yes. Well, I mean, of course, it depends on what FERC says, but we have every reason to believe that the state could designate resource requirements that for example, it's got legislation right now that's been signed by the governor saying it wants 40% of its energy to come from nuclear plants. So that legislation exists. There is renewable energy legislation that exists in terms of our renewable portfolio standards. So the approach we would think could work is that the BPU would simply say that based upon that statutory authority using a couple of mechanisms that we've already started talking about, but I'd rather not go into detail here.
It could be purely done through regulation without any need for additional legislation fully, fully supportive of the 3,500 megawatts of nuclear, 1400 megawatts of solar and whatever the heck else we have running around out there right now which I'm not counting.
Okay. So the fact that there was a $300,000,000 cap on the Saks is not relevant for that aspect?
No, it isn't right because the ZEC was not a payment for energy or capacity. The ZEC was a payment for fuel diversity and environmental attributes. So to supply the load in New Jersey, there has to be an energy and a capacity payment. And that's wholly separate from the ZEC payment. That was abundantly clear in the legislation.
Okay. And then just I'm just curious if and trying to figure out this full picture, if you've heard any updates on a potential DOE fuel stability plan and just where that might be and how that might fit into this?
I have not. We one could conclude that if price suppression is eliminated that could solve DOE's concern about other units that are suffering from that price suppression becoming viable again, but that's really an extrapolation that you'd 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 2 days ago.
But I don't have any other information than what you probably have already surmised or read in the press.
And then just on the AMI potential program you mentioned, when are we going to what is the date from when we'll 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 at the outset maybe a month or 2. If it's done separately, that could be a little longer data that could spill into the end of this year. Okay.
Thank you.
You're 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 to sort of follow-up on this capacity, just to make sure I understand Praful and Greg's and others questions. The and your answers, I guess, 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 the sort of self supply FRR specific resource alternative. Is that correct? And am I understanding that correctly?
Yes, that's right Paul. So what we understand FERCUS said in its second step of the process was that, okay states if you want to assure your own resource adequacy consisting of various components then you can do that and we'll let you remove them from the market as well as the load associated with that. And I think what profitable we were talking about was that that second half of that sentence is what is the load associated with that, right. So if resource adequacy in 168,000 megawatt market is 16% or 15.8%. What's an adequate reserve margin when the market is 3,000 megawatts?
Is it higher, is it lower? I would argue it's much higher because if you lose 1 nuclear unit out of 3,000 you got a big problem. So maybe resource adequacy then says that you've got to have you're only taking your reserve margin needs to be 35%. I'm making stuff up here with you. So the state wants that nuclear unit, it's paying for the environmental attributes, it's going to collect an energy price in the PJM market, it's then going to set a capacity price presumably through a market proxy that RPM would be a great duplicate for.
And then it's going to leave behind a lot more load than it took out and a lot less supply than it 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 think about if you do have that hypothetical situation that Ralph just talks about and there's a shortfall with respect to the load and the resources that we're taking out, what's 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 inure to the benefit of the load that was taken out for an FRR. So absent some kind of ability to ensure that that's compensated for there's a bit of a free rider issue. So logic would tell you that there should be a reserve that's going to be appropriate for the smaller amount of load that's come out.
I hear you. But that really hasn't been done with regulated assets right? I mean, we don't see that. I mean, PJM's IRM has been done sort of on a footprint or regional specific area. It doesn't seem like they've said, okay, this muni and this co op that they have, right?
I mean, that's why it seems a little bit 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 on NRG RIMA, how much more do we have left there? What's the net investment after all
this? For Keystone Economa there's an aggregate total of $20,000,000 that's there. So and those are the more acute areas. So there's very little that remains in that regard.
Okay. So we're pretty much finished with all, I think?
We do. I mean, we'll see what happens. Ultimately, there could be some timing aspects to the extent that there's 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 an accounting conservative standpoint, you could see more down before there's a recovery and they could be separated as opposed to netted. That would be the other element that I would point out to you.
Okay, great. Thanks so much. Sure.
Thank you so much.
I'm sorry.
I'm sorry. Yes, Mr. Isa and Mr. Craig, there are no further questions at this time. So please continue with your presentation and closing remarks.
Great. Yes. So thank you all for joining us. I know that Dan and Carlotta will be on the road next week if I'm not mistaken. And then for sure we'll see everyone at EEI in San Francisco in November.
And once again we're pleased with where we are in terms of the power portfolio and the construction of the new units going into service and the ongoing growth of the utility with no shortage of opportunities that continue to surface, the strength of the balance sheet and security of the dividend. And we look forward to seeing you on the road and in San Francisco. Thanks everyone.
Ladies and gentlemen, this does conclude your conference call for today. You may now disconnect and thank you for participating.